Idacorp Inc 10-Q for FY2026 Q3
Idacorp Inc (IDA)
10-Q
2026-10-29
For: 2026-09-30
View Original
Added on
October 29, 2026
About this 10-Q
Idacorp Inc filed this 10-Q on October 29, 2026, covering the quarter ended September 30, 2026 (FY2026 Q3).
IDACORP's net income rose $35.8 million in the third quarter of 2026 and $50.9 million for the first nine months, while its board increased the quarterly dividend from $0.88 per share to $0.90 per share. AI summary
Headline figures
Quarter ended September 30, 2026, as reported in this filing, compared with the same period a year earlier where the filing states it.
- Revenue
- $608.04M
- up 15.9% from $524.42M a year earlier
- Net income
- $160.21M
- up 28.8% from net income of $124.44M a year earlier
- Diluted EPS
- $2.73
- up 20.8% from $2.26 a year earlier
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES | |||||||||||||||||
| EXCHANGE ACT OF 1934 | |||||||||||||||||
| For the quarterly period ended | |||||||||||||||||
| OR | |||||||||||||||||
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES | |||||||||||||||||
| EXCHANGE ACT OF 1934 | |||||||||||||||||
| For the transition period from __________ to __________ | |||||||||||||||||
| Exact name of registrants as specified | I.R.S. Employer | ||||||||||||||||
| Commission File | in their charters, address of principal | Identification | |||||||||||||||
| Number | executive offices, zip code and telephone number | No. | |||||||||||||||
| State of Incorporation: | ||||||||||||||
| Former name, former address and former fiscal year, if changed since last report | ||||||||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
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.
| IDACORP, Inc.: | ☒ | No | ☐ | Idaho Power Company: | ☒ | No | ☐ | ||||||||||||||||||||||
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.: | ☒ | No | ☐ | Idaho Power Company: | ☒ | No | ☐ | ||||||||||||||||||||||
Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
| Accelerated filer | Smaller reporting company | Emerging growth company | |||||||||||||||
| IDACORP, Inc.: | ☒ | ☐ | ☐ | ||||||||||||||
| Idaho Power Company: | ☐ | ☐ | ☒ | ||||||||||||||
If an emerging growth company, indicate by check mark if the registrants have 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
1
Act.
| IDACORP, Inc.: | ☐ | Idaho Power Company: | ☐ | |||||||||||||||||||||||||||||
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
| IDACORP, Inc.: | Yes | ☐ | No | Idaho Power Company: | Yes | ☐ | No | ||||||||||||||||||||||
Number of shares of common stock outstanding as of October 23, 2026:
| IDACORP, Inc.: | Idaho Power Company: | |||||||||||||
This combined Form 10-Q 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 representations as to the information relating to IDACORP, Inc.’s other operations.
Idaho Power Company meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this report on Form 10-Q with the reduced disclosure format.
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| TABLE OF CONTENTS | ||||||||||||||
| Page | ||||||||||||||
| Commonly Used Terms | ||||||||||||||
| Cautionary Note Regarding Forward-Looking Statements | ||||||||||||||
| Available Information | ||||||||||||||
| Part I. Financial Information | ||||||||||||||
| Item 1. Financial Statements (unaudited) | ||||||||||||||
| IDACORP, Inc.: | ||||||||||||||
| Condensed Consolidated Statements of Income | ||||||||||||||
| Condensed Consolidated Statements of Comprehensive Income | ||||||||||||||
| Condensed Consolidated Balance Sheets | ||||||||||||||
| Condensed Consolidated Statements of Cash Flows | ||||||||||||||
| Condensed Consolidated Statements of Equity | ||||||||||||||
| Idaho Power Company: | ||||||||||||||
| Condensed Consolidated Statements of Income | ||||||||||||||
| Condensed Consolidated Statements of Comprehensive Income | ||||||||||||||
| Condensed Consolidated Balance Sheets | ||||||||||||||
| Condensed Consolidated Statements of Cash Flows | ||||||||||||||
| Notes to Condensed Consolidated Financial Statements | ||||||||||||||
| Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP | ||||||||||||||
| Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | ||||||||||||||
| Item 3. Quantitative and Qualitative Disclosures About Market Risk | ||||||||||||||
| Item 4. Controls and Procedures | ||||||||||||||
| Part II. Other Information | ||||||||||||||
| Item 1. Legal Proceedings | ||||||||||||||
| Item 1A. Risk Factors | ||||||||||||||
| Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | ||||||||||||||
| Item 3. Defaults Upon Senior Securities | ||||||||||||||
| Item 4. Mine Safety Disclosures | ||||||||||||||
| Item 5. Other Information | ||||||||||||||
| Item 6. Exhibits | ||||||||||||||
| Signatures | ||||||||||||||
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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: | ||||||||||||||||||||||||||
| 2018 Settlement Stipulation | - | May 2018 Idaho settlement stipulation related to tax reform | IERCo | - | Idaho Energy Resources Co., a subsidiary of Idaho Power Company | |||||||||||||||||||||
| 2023 Settlement Stipulation | - | The settlement stipulation for Idaho Power's 2023 Idaho general rate case | IFS | - | IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc. | |||||||||||||||||||||
| 2024 ATM | - | ATM established in May 2024 | IPUC | - | Idaho Public Utilities Commission | |||||||||||||||||||||
| 2025 Annual Report | - | IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2025 | IRP | - | Integrated Resource Plan | |||||||||||||||||||||
| 2025 Settlement Stipulation | - | The settlement stipulation for Idaho Power's 2025 Idaho general rate case | Jim Bridger plant | - | Idaho Power's jointly-owned coal- and gas-fired Jim Bridger power plant | |||||||||||||||||||||
| 2026 ATM | - | ATM established in May 2026 | Large contract customer | - | Industrial customers demanding over 20 MW of load, served under individual, commission-approved energy service agreements | |||||||||||||||||||||
| ADITC | - | Accumulated Deferred Investment Tax Credits | MD&A | - | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||||||||||||||
| AFUDC | - | Allowance for Funds Used During Construction | MMBtu | - | Million British Thermal Units | |||||||||||||||||||||
| AOCI | - | Accumulated Other Comprehensive Income | MW | - | Megawatt | |||||||||||||||||||||
| APCU | - | Annual power cost update | MWh | - | Megawatt-hour | |||||||||||||||||||||
| ATM | - | At-the-market equity offering program | NAV | - | Net asset value | |||||||||||||||||||||
| B2H | - | Boardman-to-Hemingway, a high-voltage transmission line project | NEPA | - | National Environmental Policy Act | |||||||||||||||||||||
| BCC | - | Bridger Coal Company, a jointly-owned investment of IERCo | NMFS | - | National Marine Fisheries Service | |||||||||||||||||||||
| BLM | - | U.S. Bureau of Land Management | 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 | pension plan | - | Idaho Power's noncontributory defined benefit pension plan for employees | |||||||||||||||||||||
| FERC | - | Federal Energy Regulatory Commission | PPA | - | Power purchase agreement | |||||||||||||||||||||
| FSA | - | Forward sale agreement | PURPA | - | Public Utility Regulatory Policies Act of 1978, as amended | |||||||||||||||||||||
| GAAP | - | Accounting principles generally accepted in the United States of America | RFP | - | Request for proposals | |||||||||||||||||||||
| GWW | - | Gateway West, a high-voltage transmission line project | SEC | - | U.S. Securities and Exchange Commission | |||||||||||||||||||||
| HCC | - | Hells Canyon Complex, composed of the Brownlee, Oxbow, and Hells Canyon facilities | SMSP | - | Security Plans for Senior Management Employees I and II | |||||||||||||||||||||
| IDACORP | - | IDACORP, Inc., an Idaho corporation | SWIP-N | - | Southwest Intertie Project-North, a high-voltage transmission line project | |||||||||||||||||||||
| Idaho Power | - | Idaho Power Company, an Idaho corporation | USFWS | - | U.S. Fish and Wildlife Service | |||||||||||||||||||||
| Idaho ROE | - | Idaho-jurisdiction return on year-end equity | WMP | - | Wildfire Mitigation Plan | |||||||||||||||||||||
| Ida-West | - | Ida-West Energy Company, a subsidiary of IDACORP, Inc. | WPSC | - | Wyoming Public Service Commission | |||||||||||||||||||||
4
| 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 this report, the 2025 Annual Report, particularly Part I, Item 1A - "Risk Factors" and Part II, Item 7 - MD&A of that 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 availability of qualified contractors and suppliers, contractor and supplier capacity constraints, and 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 expenses and risks on Idaho Power's ability to serve customers and generate revenues;
•the rapid addition of new industrial customer load, uncertainty of forecasted power usage ramp rates or volumes, and the volatility and timing of that new load demand and revenues, resulting in increased risks of power demand potentially exceeding available supply and revenue, cash flow, and earnings volatility;
•impacts of economic conditions, including an inflationary or recessionary environment and higher interest rates and their impacts on items such as operations and capital investments, supply costs, supply scarcity and shortages, customer 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, federal grants, 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, public 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;
5
•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, loss of life, or other losses; 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 postretirement 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 plant;
•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. New factors emerge from time to time and it is not possible for the companies to predict all such factors, nor can they assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.
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| AVAILABLE INFORMATION | ||||||||
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. 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. IDACORP's website is idacorpinc.com and Idaho Power's website is idahopower.com. The contents of these websites are not part of this report.
Those 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. The contents of these websites are not part of this report.
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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
IDACORP, Inc.
Condensed Consolidated Statements of Income
(unaudited)
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (in thousands of dollars or shares, except for per share amounts) | ||||||||||||||||||||||||||
| Operating Revenues: | ||||||||||||||||||||||||||
| Electric utility revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total operating revenues | ||||||||||||||||||||||||||
| Operating Expenses: | ||||||||||||||||||||||||||
| Electric utility: | ||||||||||||||||||||||||||
| Purchased power | ||||||||||||||||||||||||||
| Fuel expense | ||||||||||||||||||||||||||
| Power cost adjustment | ( | ( | ( | |||||||||||||||||||||||
| Other operations and maintenance | ||||||||||||||||||||||||||
| Energy efficiency programs | ||||||||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||||||||
| Other electric utility operating expenses, net | ||||||||||||||||||||||||||
| Total electric utility operating expenses | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total operating expenses | ||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||
| Non-operating (Income) Expense: | ||||||||||||||||||||||||||
| Allowance for equity funds used during construction | ( | ( | ( | ( | ||||||||||||||||||||||
| Earnings of unconsolidated equity-method investments | ( | ( | ( | ( | ||||||||||||||||||||||
| Interest on long-term debt and finance leases | ||||||||||||||||||||||||||
| Other interest | ||||||||||||||||||||||||||
| Allowance for borrowed funds used during construction | ( | ( | ( | ( | ||||||||||||||||||||||
| Other income, net | ( | ( | ( | ( | ||||||||||||||||||||||
| Total non-operating expense, net | ||||||||||||||||||||||||||
| Income Before Income Taxes | ||||||||||||||||||||||||||
| Income Tax Expense (Benefit) | ( | |||||||||||||||||||||||||
| Net Income | ||||||||||||||||||||||||||
| Income attributable to noncontrolling interests | ( | ( | ( | ( | ||||||||||||||||||||||
| Net Income Attributable to IDACORP, Inc. | $ | $ | $ | $ | ||||||||||||||||||||||
| Weighted Average Common Shares Outstanding - Basic | ||||||||||||||||||||||||||
| Weighted Average Common Shares Outstanding - Diluted | ||||||||||||||||||||||||||
| Earnings Per Share of Common Stock: | ||||||||||||||||||||||||||
| Earnings Attributable to IDACORP, Inc. - Basic | $ | $ | $ | $ | ||||||||||||||||||||||
| Earnings Attributable to IDACORP, Inc. - Diluted | $ | $ | $ | $ | ||||||||||||||||||||||
The accompanying notes are an integral part of these statements.
8
IDACORP, Inc.
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (in thousands of dollars) | ||||||||||||||||||||||||||
| Net Income | $ | $ | $ | $ | ||||||||||||||||||||||
| Other Comprehensive Income: | ||||||||||||||||||||||||||
Unfunded pension liability adjustment, net of tax of $ | ||||||||||||||||||||||||||
| Total Comprehensive Income | ||||||||||||||||||||||||||
| Comprehensive income attributable to noncontrolling interests | ( | ( | ( | ( | ||||||||||||||||||||||
| Comprehensive Income Attributable to IDACORP, Inc. | $ | $ | $ | $ | ||||||||||||||||||||||
The accompanying notes are an integral part of these statements.
9
IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)
| September 30, 2026 | December 31, 2025 | |||||||||||||
| (in thousands of dollars) | ||||||||||||||
| Assets | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Receivables: | ||||||||||||||
Customer (net of allowance of $ | ||||||||||||||
Other (net of allowance of $ | ||||||||||||||
| Income taxes receivable | ||||||||||||||
| Accrued unbilled receivables | ||||||||||||||
| Materials and supplies (at average cost) | ||||||||||||||
| Fuel stock (at average cost) | ||||||||||||||
| Prepayments | ||||||||||||||
| Current regulatory assets | ||||||||||||||
| Assets held for sale | ||||||||||||||
| Other | ||||||||||||||
| Total current assets | ||||||||||||||
| Investments | ||||||||||||||
| Property, Plant, and Equipment: | ||||||||||||||
| Utility plant in service | ||||||||||||||
| Accumulated provision for depreciation | ( | ( | ||||||||||||
| Utility plant in service - net | ||||||||||||||
| Construction work in progress | ||||||||||||||
| Finance lease right-of-use assets | ||||||||||||||
| Utility plant held for future use | ||||||||||||||
| Other property, net of accumulated depreciation | ||||||||||||||
| Property, plant, and equipment - net | ||||||||||||||
| Other Assets: | ||||||||||||||
| Company-owned life insurance | ||||||||||||||
| Regulatory assets | ||||||||||||||
| Other | ||||||||||||||
| Total other assets | ||||||||||||||
| Total | $ | $ | ||||||||||||
The accompanying notes are an integral part of these statements.
10
IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)
| September 30, 2026 | December 31, 2025 | |||||||||||||
| (in thousands of dollars or shares) | ||||||||||||||
| Liabilities and Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Current maturities of long-term debt | $ | $ | ||||||||||||
| Accounts payable | ||||||||||||||
| Taxes accrued | ||||||||||||||
| Interest accrued | ||||||||||||||
| Accrued compensation | ||||||||||||||
| Current regulatory liabilities | ||||||||||||||
| Advances from customers | ||||||||||||||
| Liabilities held for sale | ||||||||||||||
| Other | ||||||||||||||
| Total current liabilities | ||||||||||||||
| Other Liabilities: | ||||||||||||||
| Deferred income taxes | ||||||||||||||
| Regulatory liabilities | ||||||||||||||
| Pension and other postretirement benefits | ||||||||||||||
| Finance lease liabilities | ||||||||||||||
| Other | ||||||||||||||
| Total other liabilities | ||||||||||||||
| Long-Term Debt | ||||||||||||||
| Commitments and Contingencies | ||||||||||||||
| Equity: | ||||||||||||||
| IDACORP, Inc. shareholders’ equity: | ||||||||||||||
Common stock, no par value ( | ||||||||||||||
| Retained earnings | ||||||||||||||
| Accumulated other comprehensive loss | ( | ( | ||||||||||||
| Total IDACORP, Inc. shareholders’ equity | ||||||||||||||
| Noncontrolling interests | ||||||||||||||
| Total equity | ||||||||||||||
| Total | $ | $ | ||||||||||||
| The accompanying notes are an integral part of these statements. | ||||||||||||||
11
IDACORP, Inc.
Condensed Consolidated Statements of Cash Flows
(unaudited)
Nine months ended September 30, | ||||||||||||||
| 2026 | 2025 | |||||||||||||
| (in thousands of dollars) | ||||||||||||||
| Operating Activities: | ||||||||||||||
| Net income | $ | $ | ||||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||
| Depreciation and amortization | ||||||||||||||
| Deferred income taxes and investment tax credits | ( | ( | ||||||||||||
| Changes in regulatory assets and liabilities | ||||||||||||||
| Pension and postretirement benefit plan expense | ||||||||||||||
| Contributions to pension and postretirement benefit plans | ( | ( | ||||||||||||
| Earnings of equity-method investments | ( | ( | ||||||||||||
| Distributions from equity-method investments | ||||||||||||||
| Allowance for equity funds used during construction | ( | ( | ||||||||||||
| Other non-cash adjustments to net income, net | ||||||||||||||
| Change in: | ||||||||||||||
| Accounts receivable and unbilled receivables | ( | ( | ||||||||||||
| Prepayments | ( | ( | ||||||||||||
| Materials, supplies, and fuel stock | ( | |||||||||||||
| Accounts and wages payable | ( | ( | ||||||||||||
| Taxes accrued/receivable | ||||||||||||||
| Other assets and liabilities | ( | ( | ||||||||||||
| Net cash provided by operating activities | ||||||||||||||
| Investing Activities: | ||||||||||||||
| Additions to property, plant, and equipment, net | ( | ( | ||||||||||||
| Payments received from transmission project joint funding partners | ||||||||||||||
| Proceeds from the sale of renewable energy certificates | ||||||||||||||
| Other | ( | ( | ||||||||||||
| Net cash used in investing activities | ( | ( | ||||||||||||
| Financing Activities: | ||||||||||||||
| Issuance of long-term debt | ||||||||||||||
| Discount on issuance of long-term debt | ( | ( | ||||||||||||
| Retirement of long-term debt | ( | ( | ||||||||||||
| Payments on finance lease liabilities | ( | ( | ||||||||||||
| Dividends on common stock | ( | ( | ||||||||||||
| Issuance of common stock | ||||||||||||||
| Tax withholdings on net settlements of share-based awards | ( | ( | ||||||||||||
| Other | ( | ( | ||||||||||||
| Net cash provided by financing activities | ||||||||||||||
| Net decrease in cash and cash equivalents | ( | ( | ||||||||||||
| Cash and cash equivalents at beginning of the period | ||||||||||||||
| Cash and cash equivalents at end of the period | $ | $ | ||||||||||||
| Supplemental Disclosure of Cash Flow Information: | ||||||||||||||
| Cash paid for interest (net of amount capitalized) | $ | $ | ||||||||||||
| Non-cash investing and financing activities: | ||||||||||||||
| Additions to property, plant, and equipment in accounts payable | $ | $ | ||||||||||||
| Right-of-use asset obtained in exchange for finance lease liability | $ | $ | ||||||||||||
The accompanying notes are an integral part of these statements.
12
IDACORP, Inc.
Condensed Consolidated Statements of Equity
(unaudited)
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (in thousands of dollars) | ||||||||||||||||||||||||||
| Common Stock | ||||||||||||||||||||||||||
| Balance at beginning of period | $ | $ | $ | $ | ||||||||||||||||||||||
| Issuance | ||||||||||||||||||||||||||
| Share-based compensation expense | ||||||||||||||||||||||||||
| Tax withholdings on net settlements of share-based awards | ( | ( | ( | |||||||||||||||||||||||
| Other | ( | ( | ( | ( | ||||||||||||||||||||||
| Balance at end of period | ||||||||||||||||||||||||||
| Retained Earnings | ||||||||||||||||||||||||||
| Balance at beginning of period | ||||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | ||||||||||||||||||||||||||
Common stock dividends ($ | ( | ( | ( | ( | ||||||||||||||||||||||
| Balance at end of period | ||||||||||||||||||||||||||
| Accumulated Other Comprehensive Loss | ||||||||||||||||||||||||||
| Balance at beginning of period | ( | ( | ( | ( | ||||||||||||||||||||||
| Unfunded pension liability adjustment (net of tax) | ||||||||||||||||||||||||||
| Balance at end of period | ( | ( | ( | ( | ||||||||||||||||||||||
| Total IDACORP, Inc. shareholders’ equity at end of period | ||||||||||||||||||||||||||
| Noncontrolling Interests | ||||||||||||||||||||||||||
| Balance at beginning of period | ||||||||||||||||||||||||||
| Net income attributable to noncontrolling interests | ||||||||||||||||||||||||||
| Balance at end of period | ||||||||||||||||||||||||||
| Total equity at end of period | $ | $ | $ | $ | ||||||||||||||||||||||
The accompanying notes are an integral part of these statements.
13
Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (in thousands of dollars) | ||||||||||||||||||||||||||
| Operating Revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Operating Expenses: | ||||||||||||||||||||||||||
| Operation: | ||||||||||||||||||||||||||
| Purchased power | ||||||||||||||||||||||||||
| Fuel expense | ||||||||||||||||||||||||||
| Power cost adjustment | ( | ( | ( | |||||||||||||||||||||||
| Other operations and maintenance | ||||||||||||||||||||||||||
| Energy efficiency programs | ||||||||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||||||||
| Other operating expenses, net | ||||||||||||||||||||||||||
| Total operating expenses | ||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||
| Non-operating (Income) Expense: | ||||||||||||||||||||||||||
| Allowance for equity funds used during construction | ( | ( | ( | ( | ||||||||||||||||||||||
| Earnings of unconsolidated equity-method investments | ( | ( | ( | ( | ||||||||||||||||||||||
| Interest on long-term debt and finance leases | ||||||||||||||||||||||||||
| Other interest | ||||||||||||||||||||||||||
| Allowance for borrowed funds used during construction | ( | ( | ( | ( | ||||||||||||||||||||||
| Other income, net | ( | ( | ( | ( | ||||||||||||||||||||||
| Total non-operating expense, net | ||||||||||||||||||||||||||
| Income Before Income Taxes | ||||||||||||||||||||||||||
| Income Tax Expense (Benefit) | ( | |||||||||||||||||||||||||
| Net Income | $ | $ | $ | $ | ||||||||||||||||||||||
The accompanying notes are an integral part of these statements.
14
Idaho Power Company
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (in thousands of dollars) | ||||||||||||||||||||||||||
| Net Income | $ | $ | $ | $ | ||||||||||||||||||||||
| Other Comprehensive Income: | ||||||||||||||||||||||||||
Unfunded pension liability adjustment, net of tax of $ | ||||||||||||||||||||||||||
| Total Comprehensive Income | $ | $ | $ | $ | ||||||||||||||||||||||
The accompanying notes are an integral part of these statements.
15
Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)
| September 30, 2026 | December 31, 2025 | |||||||||||||
| (in thousands of dollars) | ||||||||||||||
| Assets | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Receivables: | ||||||||||||||
Customer (net of allowance of $ | ||||||||||||||
Other (net of allowance of $ | ||||||||||||||
| Income taxes receivable | ||||||||||||||
| Accrued unbilled receivables | ||||||||||||||
| Materials and supplies (at average cost) | ||||||||||||||
| Fuel stock (at average cost) | ||||||||||||||
| Prepayments | ||||||||||||||
| Current regulatory assets | ||||||||||||||
| Assets held for sale | ||||||||||||||
| Other | ||||||||||||||
| Total current assets | ||||||||||||||
| Investments | ||||||||||||||
| Property, Plant, and Equipment: | ||||||||||||||
| Utility plant in service | ||||||||||||||
| Accumulated provision for depreciation | ( | ( | ||||||||||||
| Utility plant in service - net | ||||||||||||||
| Construction work in progress | ||||||||||||||
| Finance lease right-of-use assets | ||||||||||||||
| Plant held for future use | ||||||||||||||
| Other property | ||||||||||||||
| Property, plant, and equipment, net | ||||||||||||||
| Other Assets: | ||||||||||||||
| Company-owned life insurance | ||||||||||||||
| Regulatory assets | ||||||||||||||
| Other | ||||||||||||||
| Total other assets | ||||||||||||||
| Total | $ | $ | ||||||||||||
The accompanying notes are an integral part of these statements.
16
Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)
| September 30, 2026 | December 31, 2025 | |||||||||||||
| (in thousands of dollars or shares, except par value) | ||||||||||||||
| Liabilities and Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Current maturities of long-term debt | $ | $ | ||||||||||||
| Accounts payable | ||||||||||||||
| Accounts payable to affiliates | ||||||||||||||
| Taxes accrued | ||||||||||||||
| Interest accrued | ||||||||||||||
| Accrued compensation | ||||||||||||||
| Current regulatory liabilities | ||||||||||||||
| Advances from customers | ||||||||||||||
| Liabilities held for sale | ||||||||||||||
| Other | ||||||||||||||
| Total current liabilities | ||||||||||||||
| Other Liabilities: | ||||||||||||||
| Deferred income taxes | ||||||||||||||
| Regulatory liabilities | ||||||||||||||
| Pension and other postretirement benefits | ||||||||||||||
| Finance lease liabilities | ||||||||||||||
| Other | ||||||||||||||
| Total other liabilities | ||||||||||||||
| Long-Term Debt | ||||||||||||||
| Commitments and Contingencies | ||||||||||||||
| Equity: | ||||||||||||||
Common stock, $ | ||||||||||||||
| Premium on capital stock | ||||||||||||||
| Capital stock expense | ( | ( | ||||||||||||
| Retained earnings | ||||||||||||||
| Accumulated other comprehensive loss | ( | ( | ||||||||||||
| Total equity | ||||||||||||||
| Total | $ | $ | ||||||||||||
| The accompanying notes are an integral part of these statements. | ||||||||||||||
17
Idaho Power Company
Condensed Consolidated Statements of Cash Flows
(unaudited)
Nine months ended September 30, | ||||||||||||||
| 2026 | 2025 | |||||||||||||
| (in thousands of dollars) | ||||||||||||||
| Operating Activities: | ||||||||||||||
| Net income | $ | $ | ||||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||
| Depreciation and amortization | ||||||||||||||
| Deferred income taxes and investment tax credits | ( | |||||||||||||
| Changes in regulatory assets and liabilities | ||||||||||||||
| Pension and postretirement benefit plan expense | ||||||||||||||
| Contributions to pension and postretirement benefit plans | ( | ( | ||||||||||||
| Earnings of equity-method investments | ( | ( | ||||||||||||
| Distributions from equity-method investments | ||||||||||||||
| Allowance for equity funds used during construction | ( | ( | ||||||||||||
| Other non-cash adjustments to net income, net | ( | |||||||||||||
| Change in: | ||||||||||||||
| Accounts receivable and unbilled receivables | ( | ( | ||||||||||||
| Prepayments | ( | ( | ||||||||||||
| Materials, supplies, and fuel stock | ( | |||||||||||||
| Accounts and wages payable | ( | ( | ||||||||||||
| Taxes accrued/receivable | ||||||||||||||
| Other assets and liabilities | ( | ( | ||||||||||||
| Net cash provided by operating activities | ||||||||||||||
| Investing Activities: | ||||||||||||||
| Additions to utility plant, net | ( | ( | ||||||||||||
| Payments received from transmission project joint funding partners | ||||||||||||||
| Proceeds from the sale of renewable energy certificates | ||||||||||||||
| Other | ||||||||||||||
| Net cash used in investing activities | ( | ( | ||||||||||||
| Financing Activities: | ||||||||||||||
| Issuance of long-term debt | ||||||||||||||
| Discount on issuance of long-term debt | ( | ( | ||||||||||||
| Retirement of long-term debt | ( | ( | ||||||||||||
| Payments on finance lease liabilities | ( | ( | ||||||||||||
| Dividends on common stock | ( | ( | ||||||||||||
| Capital contribution from parent | ||||||||||||||
| Other | ( | ( | ||||||||||||
| Net cash provided by financing activities | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | ( | |||||||||||||
| Cash and cash equivalents at beginning of the period | ||||||||||||||
| Cash and cash equivalents at end of the period | $ | $ | ||||||||||||
| Supplemental Disclosure of Cash Flow Information: | ||||||||||||||
| Cash paid for interest (net of amount capitalized) | $ | $ | ||||||||||||
| Non-cash investing and financing activities: | ||||||||||||||
| Additions to utility plant in accounts payable | $ | $ | ||||||||||||
| Right-of-use asset obtained in exchange for finance lease liability | $ | $ | ||||||||||||
The accompanying notes are an integral part of these statements.
18
IDACORP, INC. AND IDAHO POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This Quarterly Report on Form 10-Q is a combined report of IDACORP and Idaho Power. Therefore, these Notes to the Condensed 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 16 - "Assets Held For Sale" 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.
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.
Financial Statements
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
19
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.
New and Recently Adopted Accounting Pronouncements
Recently Adopted Accounting Pronouncements
There have been no recently adopted accounting pronouncements that have had a material impact on IDACORP's or Idaho Power's condensed consolidated financial statements.
Recently Issued Accounting Pronouncements Not Yet Adopted
In May 2026, the FASB issued Accounting Standards Update (ASU) 2026-02, Environmental Credits and Environmental Credit Obligations, which establishes accounting requirements for environmental credits and environmental obligations, including their recognition, measurement, presentation, and disclosure. This ASU is effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. The provisions of this ASU are required to be applied retrospectively. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their respective condensed consolidated financial statements.
Other than those described in Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in the 2025 Annual Report and discussed above, there have been no additional recently issued accounting pronouncements that have not yet been adopted and are expected to have a material impact on IDACORP's or Idaho Power's condensed consolidated financial statements.
2. INCOME TAXES
In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount.
Income Tax Expense
The following table provides a summary of income tax expense (benefit) (in thousands of dollars):
| IDACORP | Idaho Power | |||||||||||||||||||||||||
| Nine months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| $ | $ | $ | $ | |||||||||||||||||||||||
| Excess deferred income tax reversal | ( | ( | ( | ( | ||||||||||||||||||||||
| Income tax return adjustments | ( | ( | ( | ( | ||||||||||||||||||||||
Other(1) | ( | ( | ( | ( | ||||||||||||||||||||||
| Income tax expense before ADITC | $ | $ | $ | $ | ||||||||||||||||||||||
| Additional ADITC amortization | ( | ( | ( | ( | ||||||||||||||||||||||
| Income tax expense (benefit) | $ | $ | ( | $ | $ | ( | ||||||||||||||||||||
| Effective tax rate | % | ( | % | % | ( | % | ||||||||||||||||||||
(1) "Other" primarily consists of the net tax effect of Idaho Power's regulatory flow-through tax adjustments.
20
Supplemental Disclosure of Cash Flow Information
Supplemental cash flow information related to income taxes, including cash (refunded) paid for income taxes and cash received from IDACORP related to income taxes, is presented below (in thousands of dollars):
| Nine months ended September 30, | ||||||||||||||
| 2026 | 2025 | |||||||||||||
| IDACORP | ||||||||||||||
| Total cash (refunded) paid for income taxes | $ | ( | $ | |||||||||||
| Idaho Power | ||||||||||||||
| Total cash received from IDACORP related to income taxes | $ | ( | $ | ( | ||||||||||
3. REGULATORY MATTERS
Included below is a summary of Idaho Power's most recent general rate cases and base rate changes, as well as other recent or pending notable regulatory matters and proceedings.
Idaho and Oregon Rate Cases
Idaho Power's current base rates result from the IPUC and OPUC orders described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report.
Idaho ADITC Mechanism
The 2018 Settlement Stipulation, 2023 Settlement Stipulation, and 2025 Settlement Stipulation are each described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. The 2025 Settlement Stipulation and the 2023 Settlement Stipulation modified the 2018 Settlement Stipulation in part. The 2023 Settlement Stipulation included provisions for the accelerated amortization of ADITCs to help achieve a minimum 9.12 percent Idaho ROE, while the 2025 Settlement Stipulation established an annual cap of $55 million on the amount of accelerated amortization of ADITCs for calendar year 2026 and thereafter and also modified the ADITC mechanism to include an additional amount of investment tax credits equal to the total of existing ADITCs not previously eligible for accelerated amortization under the mechanism and all investment tax credits generated through the end of calendar-year 2028.
Based on its estimate of full-year 2026 Idaho ROE, for the three months and nine months ended September 30, 2026, Idaho Power recorded zero and $6.3 million, respectively, in additional ADITC amortization under the 2025 Settlement Stipulation. Accordingly, as of September 30, 2026, approximately $154 million of additional ADITCs remained available for future use. Idaho Power recorded $2.5 million and $39.0 million, respectively, of additional ADITC amortization for the three months and nine months ended September 30, 2025, based on its then-current estimate of full-year 2025 Idaho ROE.
Power Cost Adjustment Mechanisms
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 power generation, changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, and changes in fuel prices.
In May 2026, the IPUC issued an order approving a $51.3 million increase in PCA revenues as compared with the prior collection period, effective for the 2026-2027 PCA collection period from June 1, 2026 to May 31, 2027. The increase in PCA revenues is due primarily to a decrease in forecast hydroelectric generation for the April 2026 to March 2027 forecast period.
21
In May 2026, the OPUC approved a settlement stipulation between Idaho Power and intervening parties for its annual power cost adjustment mechanism in Oregon. The filing also requested recovery of 2025 incremental deferred wildfire mitigation costs. The settlement resulted in an increase of $1.9 million in Oregon-jurisdictional rates, effective June 1, 2026.
In May 2026, the OPUC approved a settlement stipulation between Idaho Power and intervening parties for its APCU in Oregon, resulting in an increase of $0.7 million in Oregon-jurisdictional revenues, effective June 1, 2026.
Idaho Fixed Cost Adjustment Mechanism
The FCA mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kilowatt-hour charge, which may result in 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 2026, the IPUC issued an order approving Idaho Power's recovery of its 2025 FCA balance of $2.0 million, reflecting an increase in recovery from the FCA of $5.1 million as compared to the 2024 FCA regulatory liability balance of $3.1 million, over the period from June 1, 2026 to May 31, 2027.
Wildfire Mitigation Cost Recovery
The 2025 Settlement Stipulation authorized Idaho Power to defer certain incremental O&M and insurance costs for wildfire mitigation efforts above the 2024 base through the earlier of the next general rate case or 2027. As of September 30, 2026, Idaho Power’s deferral balance of Idaho-jurisdiction costs related to the WMP was $90.8 million, of which $65.1 million is approved to be amortized and currently collected in Idaho rates.
In December 2025, Idaho Power filed an application with the OPUC 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. In September 2026, the OPUC approved the application. As of September 30, 2026, Idaho Power’s deferral balance of Oregon-jurisdiction costs related to the WMP was $3.2 million, of which $2.0 million is approved to be amortized and currently collected in Oregon rates.
4. REVENUES
The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands of dollars):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Revenue from contracts with customers | $ | $ | $ | $ | ||||||||||||||||||||||
| Alternative revenue programs and other revenues | ( | ( | ||||||||||||||||||||||||
| Total electric utility operating revenues | $ | $ | $ | $ | ||||||||||||||||||||||
22
Revenues from Contracts with Customers
The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands of dollars):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Retail revenues: | ||||||||||||||||||||||||||
Residential (includes $( | $ | $ | $ | $ | ||||||||||||||||||||||
Commercial (includes $( | ||||||||||||||||||||||||||
| Industrial | ||||||||||||||||||||||||||
| Irrigation | ||||||||||||||||||||||||||
Deferred revenue related to HCC relicensing AFUDC(2) | ( | ( | ( | ( | ||||||||||||||||||||||
| Total retail revenues | ||||||||||||||||||||||||||
Less: FCA mechanism revenues(1) | ( | |||||||||||||||||||||||||
| Wholesale energy sales | ||||||||||||||||||||||||||
| Transmission wheeling-related revenues | ||||||||||||||||||||||||||
| Energy efficiency program revenues | ||||||||||||||||||||||||||
| Other revenues from contracts with customers | ||||||||||||||||||||||||||
| Total revenues from contracts with customers | $ | $ | $ | $ | ||||||||||||||||||||||
(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 included in the 2025 Annual 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.
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.
The table below presents the FCA mechanism revenues and other revenues (in thousands of dollars):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| FCA mechanism revenues | $ | ( | $ | ( | $ | $ | ( | |||||||||||||||||||
| Derivative revenues | ||||||||||||||||||||||||||
| Total alternative revenue programs and other revenues | $ | ( | $ | ( | $ | $ | ||||||||||||||||||||
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Receivables and Allowance for Uncollectible Accounts
The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of dollars):
Nine months ended September 30, | ||||||||||||||
| 2026 | 2025 | |||||||||||||
| Balance at beginning of period | $ | $ | ||||||||||||
| Additions to the allowance | ||||||||||||||
| Write-offs, net of recoveries | ( | ( | ||||||||||||
| Balance at end of period | $ | $ | ||||||||||||
| Allowance for uncollectible accounts as a percentage of customer receivables | % | % | ||||||||||||
5. LONG-TERM DEBT
Long-Term Debt Issuances, Maturities, and Redemptions
On February 27, 2026, Idaho Power issued $350 million in aggregate principal amount of 4.85 % first mortgage bonds, secured medium-term notes, Series O, maturing on March 1, 2036.
On July 15, 2026, Idaho Power repaid $116 million in aggregate principal amount of maturing 1.70 % pollution control revenue bonds.
On August 6, 2026, Idaho Power issued $200 million in aggregate principal amount of its 5.70 % first mortgage bonds, secured medium-term notes, Series O, maturing on March 15, 2055. The bonds were issued at a reoffer yield of 6.133 %, which resulted in net proceeds to Idaho Power of $186.6 million plus accrued interest. After this offering the aggregate principal amount of the 5.70 % first mortgage bonds is $600 million.
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 June and July 2026, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.5 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 June 30, 2029, 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 September 30, 2026, $1.3 billion remained available for debt issuance under the regulatory orders.
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), 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 September 30, 2026, the maximum amount of additional first mortgage bonds Idaho Power could issue under this test was approximately $2.4 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 September 30, 2026, Idaho Power could issue approximately $1.6 billion of additional first mortgage bonds under that aggregate cap.
6. COMMON STOCK
IDACORP Common Stock
During the nine months ended September 30, 2026, IDACORP issued an aggregate of 2,996,285 shares of common stock using original issuances of shares. IDACORP granted 71,855 restricted stock unit awards and issued 55,032 shares of common stock to employees pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, and issued an additional 31,837 shares of common stock pursuant to director equity compensation plans. IDACORP issued 31,323 shares of common
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stock pursuant to the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and 3,226 shares pursuant to the Idaho Power Company Employee Savings Plan.
At-the-Market Offering Programs (2024 & 2026 ATM Series): On May 15, 2026, IDACORP entered into an Equity Distribution Agreement pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $600 million of shares of its common stock through the 2026 ATM, which includes the ability to enter into FSAs. At September 30, 2026, IDACORP had $66.5 million of remaining capacity under its 2026 ATM. Before the 2026 ATM became effective, IDACORP had available the 2024 ATM providing for the sale of up to an aggregate gross sales price of $300 million of shares of its common stock. Upon effectiveness of the 2026 ATM, the 2024 ATM terminated with respect to new issuances.
During the nine months ended September 30, 2026, IDACORP executed FSAs under its 2024 ATM and 2026 ATM with various counterparties who borrowed and sold 4,926,437 shares of IDACORP’s common stock at an aggregate gross sales price of $689.0 million, including approximately $7.0 million in commissions and fees payable by IDACORP to the counterparties upon settlement.
At September 30, 2026, IDACORP had the following FSAs outstanding under its 2024 ATM and 2026 ATM (in thousands of dollars, except for shares and forward prices):
| Maturity Date | ATM Series | Shares | Net Proceeds Available | Forward Price | ||||||||||||||||||||||
| March 31, 2027 | 2024 | $ | $ | |||||||||||||||||||||||
| March 31, 2027 | 2024 | |||||||||||||||||||||||||
| March 31, 2027 | 2024 | |||||||||||||||||||||||||
| May 28, 2027 | 2026 | |||||||||||||||||||||||||
| May 28, 2027 | 2026 | |||||||||||||||||||||||||
| December 3, 2027 | 2026 | |||||||||||||||||||||||||
| February 29, 2028 | 2026 | |||||||||||||||||||||||||
| February 29, 2028 | 2026 | |||||||||||||||||||||||||
| February 29, 2028 | 2026 | |||||||||||||||||||||||||
| Total / Weighted Average Forward Price | $ | $ | ||||||||||||||||||||||||
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 September 30, 2026, IDACORP could have settled all its outstanding FSAs under the ATMs with physical delivery of 4,926,437 shares of common stock to the counterparties in exchange for cash of $684.5 million. At September 30, 2026, IDACORP could have settled the FSAs with net receipt from various counterparties of approximately $3.3 million of cash or approximately 26,319 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 the nine months ended September 30, 2026, IDACORP settled the following FSAs (in thousands of dollars, except for settlement shares and forward settlement prices):
| Settlement Date | ATM Series | Settlement Shares | Net Cash Proceeds(1) | Forward Settlement Price | ||||||||||||||||||||||
| March 31, 2026 | 2024 | $ | $ | |||||||||||||||||||||||
| March 31, 2026 | 2024 | |||||||||||||||||||||||||
| Total / Weighted Average Forward Settlement Price | $ | $ | ||||||||||||||||||||||||
(1) Settlement of the FSAs is recognized in IDACORP’s equity on the settlement date.
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
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$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.
During the nine months ended September 30, 2026, and subsequently through the date of this report, IDACORP settled the following FSAs under the 2025 Series (in thousands of dollars, except for settlement shares and forward settlement prices):
| Settlement Date | Settlement Shares | Net Cash Proceeds(1) | Forward Settlement Price | |||||||||||||||||
| May 28, 2026 | $ | $ | ||||||||||||||||||
| July 13, 2026 | ||||||||||||||||||||
| October 15, 2026 | $ | $ | ||||||||||||||||||
| Total / Weighted Average Forward Settlement Price | $ | $ | ||||||||||||||||||
(1) Settlement of the FSAs is recognized in IDACORP’s equity on the settlement date.
At September 30, 2026, IDACORP could have settled the remaining outstanding FSAs with physical delivery of 2,757,569 shares of common stock to the counterparties in exchange for cash of $297.7 million. The FSAs could have also been settled at September 30, 2026, with delivery of approximately $89.2 million of cash or approximately 634,702 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.
FSA Earnings Per Share 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. For the three months and nine months ended September 30, 2026, approximately 758,000 and 1,074,000 incremental shares, respectively, were included in the calculation of diluted earnings per share related to the securities under the FSAs. For the three months and nine months ended September 30, 2025, approximately 744,000 and 311,000 incremental shares, respectively, were included in the calculation of diluted earnings per share related to the securities under the FSAs. See Note 7 - "Earnings Per Share" for additional information on IDACORP's diluted earnings per share.
Idaho Power Common Stock
During the three months and nine months ended September 30, 2026, IDACORP contributed $186.8 million and $376.8 million, respectively, of additional capital to Idaho Power. 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 September 30, 2026, the leverage ratios for IDACORP and Idaho Power, as defined in the credit facilities, were each 51
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percent. Based on these restrictions, IDACORP’s and Idaho Power’s potential dividends were limited to $1.8 billion and $1.7 billion, respectively, at September 30, 2026. 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 September 30, 2026, 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 September 30, 2026, Idaho Power's common equity capital was 49 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 Federal Power Act prohibits the payment of dividends from "capital accounts." The term "capital account" is undefined in the Federal Power Act 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. EARNINGS PER SHARE
The table below presents the computation of IDACORP’s basic and diluted earnings per share (in thousands of dollars or shares, except for per share amounts).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Numerator: | ||||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | $ | $ | $ | $ | ||||||||||||||||||||||
| Denominator: | ||||||||||||||||||||||||||
| Weighted-average common shares outstanding - basic | ||||||||||||||||||||||||||
Effect of dilutive securities(1) | ||||||||||||||||||||||||||
| Weighted-average common shares outstanding - diluted | ||||||||||||||||||||||||||
| Basic earnings per share | $ | $ | $ | $ | ||||||||||||||||||||||
| Diluted earnings per share | $ | $ | $ | $ | ||||||||||||||||||||||
(1) Includes the effect of dilutive securities related to FSAs. See Note 6 - "Common Stock" for additional information on IDACORP's FSAs.
8. COMMITMENTS
Purchase Obligations
During the nine months ended September 30, 2026, Idaho Power entered into the following agreements:
•fuel-related agreements in April 2026, increasing its contractual purchase obligations by approximately $1.6 billion over a 15 -year term, beginning May 2030 and expiring May 2045;
•an agreement in May 2026 to replace expiring PPAs with a PURPA-qualifying hydropower facility, which increased Idaho Power's contractual purchase obligations by approximately $10.3 million over the 20 -year term commencing in September 2026;
•a 200 MW solar facility PPA and an agreement to purchase the storage capacity from a 100 MW battery storage facility, both executed in May 2026 with a scheduled online date of May 2028, which collectively increased Idaho Power's contractual purchase obligations by approximately $796.2 million over their 20 -year terms;
•an agreement in June 2026 to acquire and own certain equipment and to receive related technical services, which increased Idaho Power's contractual purchase obligations by approximately $218.0 million through the first half of 2029; and
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•an agreement in July 2026 to extend an expiring PPA with a wind facility, which increased Idaho Power's contractual purchase obligations by approximately $94.6 million over the 5 -year term commencing in January 2028.
Except as discussed above, during the nine months ended September 30, 2026, IDACORP's and Idaho Power's contractual obligations outside the ordinary course of business did not change materially from the amounts disclosed in the notes to the consolidated financial statements in the 2025 Annual Report.
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 $49.7 million at September 30, 2026, representing IERCo's one-third share of BCC's total reclamation obligation of $149.2 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At September 30, 2026, 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 September 30, 2026, 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 condensed consolidated balance sheets with respect to these indemnification obligations.
9. 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.
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Idaho Power actively monitors any pending or potential 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 any such regulations and orders.
10. BENEFIT PLANS
Idaho Power has the noncontributory defined benefit pension plan and two The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended September 30, 2026 and 2025 (in thousands of dollars).
| Pension Plan | SMSP | Postretirement Benefits | Total | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||||||||||
| Service cost | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Interest cost | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Amortization of prior service cost | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Amortization of net loss | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Net periodic benefit cost | ||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory deferral of net periodic benefit cost(1) | ( | ( | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
Previously deferred pension costs recognized(1) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Net periodic benefit cost recognized for financial reporting(1)(2) | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
(1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit 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 benefit cost recognized for financial reporting, $9.8 million and $9.8 million, respectively, were recognized in "Other operations and maintenance" and $1.6 million and $1.5 million, respectively, were recognized in "Other income, net" on the condensed consolidated statements of income of the companies for the three months ended September 30, 2026 and 2025.
The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the nine months ended September 30, 2026 and 2025 (in thousands of dollars). | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Pension Plan | SMSP | Postretirement Benefits | Total | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||||||||||
| Service cost | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Interest cost | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Amortization of prior service cost | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Amortization of net loss | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Net periodic benefit cost | ||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory deferral of net periodic benefit cost(1) | ( | ( | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
Previously deferred pension costs recognized(1) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Net periodic benefit cost recognized for financial reporting(1)(2) | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
(1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit 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 benefit cost recognized for financial reporting, $29.1 million and $29.4 million, respectively, were recognized in "Other operations and maintenance" and $4.6 million and $4.5 million, respectively, were recognized in "Other income, net" on the condensed consolidated statements of income of the companies for the nine months ended September 30, 2026 and 2025.
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Idaho Power has no minimum contribution to its pension plan required in 2026. During the nine months ended September 30, 2026, Idaho Power contributed $20
Idaho Power also has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the Employee Savings Plan.
11. 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.
The table below presents the gains and losses on derivatives not designated as hedging instruments (in thousands of dollars):
Gain/(Loss) on Derivatives Recognized in Income(1) | ||||||||||||||||||||||||||||||||
| Location of Realized Gain/(Loss) on Derivatives Recognized in Income | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||
| Financial swaps | Operating revenues | $ | $ | $ | $ | |||||||||||||||||||||||||||
| Financial swaps | Purchased power | ( | ( | ( | ( | |||||||||||||||||||||||||||
| Financial swaps | Fuel expense | ( | ( | ( | ( | |||||||||||||||||||||||||||
| Forward contracts | Operating revenues | ( | ||||||||||||||||||||||||||||||
| Forward contracts | Purchased power | ( | ( | |||||||||||||||||||||||||||||
| Forward contracts | Fuel expense | ( | ( | ( | ( | |||||||||||||||||||||||||||
(1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Credit Risk
At September 30, 2026, 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
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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. contracts. These contracts typically contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at September 30, 2026, was $61.6 million. As of September 30, 2026, Idaho Power posted $47.8 million of cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2026, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $34.4 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 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2026 | ||||||||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other current liabilities | ( | ( | (1) | ||||||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current assets | ( | ( | |||||||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current liabilities | |||||||||||||||||||||||||||||||||||||||||||
| Long-term: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other assets | ( | ( | |||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other liabilities | ( | ( | (2) | ||||||||||||||||||||||||||||||||||||||||
| Forward contracts | Other liabilities | |||||||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | ( | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||
| December 31, 2025 | ||||||||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other current liabilities | $ | $ | ( | $ | $ | $ | ( | (3) | $ | ||||||||||||||||||||||||||||||||||
| Forward contracts | Other current assets | |||||||||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current liabilities | |||||||||||||||||||||||||||||||||||||||||||
| Long-term: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other liabilities | ( | ( | (4) | ||||||||||||||||||||||||||||||||||||||||
| Forward contracts | Other liabilities | |||||||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | ( | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||
(1) Current liability derivative amounts offset include $32.7 million of collateral receivable at September 30, 2026.
(2) Long-term liability derivative amounts offset include $2.1 million of collateral receivable at September 30, 2026.
(3) Current liability derivative amounts offset include $26.9 million of collateral receivable at December 31, 2025.
(4) Long-term liability derivative amounts offset include $2.9 million of collateral receivable at December 31, 2025.
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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding (in thousands of units):
| September 30, | ||||||||||||||||||||
| Commodity | Units | 2026 | 2025 | |||||||||||||||||
| Electricity purchases | MWh | |||||||||||||||||||
| Electricity sales | MWh | |||||||||||||||||||
| Natural gas purchases | MMBtu | |||||||||||||||||||
| Natural gas sales | MMBtu | |||||||||||||||||||
12. 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 condensed 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.
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 (in thousands of dollars):
| September 30, 2026 | December 31, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Money market funds and commercial paper | ||||||||||||||||||||||||||||||||||||||||||||||||||
IDACORP(1) | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Idaho Power | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity securities | ||||||||||||||||||||||||||||||||||||||||||||||||||
IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||
(1) Holding company only. Does not include amounts held by Idaho Power.
Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity swap derivatives are valued on the Intercontinental Exchange (ICE) with quoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forward contract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange (NYMEX) and 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, using available market information and appropriate valuation methodologies (in thousands of dollars).
| September 30, 2026 | December 31, 2025 | |||||||||||||||||||||||||
| Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||||||||||||
| IDACORP | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
Notes receivable(1) | $ | $ | $ | $ | ||||||||||||||||||||||
Held-to-maturity securities(1)(2) | ||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
Long-term debt (including current portion)(1) | ||||||||||||||||||||||||||
| Idaho Power | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
Held-to-maturity securities(1)(2) | $ | $ | $ | $ | ||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
Long-term debt (including current portion)(1) | ||||||||||||||||||||||||||
(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 12 - "Fair Value Measurements."
(2) All held-to-maturity securities are carried at amortized cost and were in a gross unrealized holding loss position totaling $2.5 million and $1.4 million as of September 30, 2026, and December 31, 2025, respectively. Substantially all of these debt securities mature between 2027 and 2038. Based on ongoing credit evaluations of these holdings, Idaho Power does not expect payment defaults or delinquencies and had not recorded an allowance for credit losses for these securities as of September 30, 2026, and December 31, 2025.
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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13. 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 power supply, 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 consists of IFS’s investments in affordable housing and other real estate tax credit projects, Ida-West’s joint venture investments in small hydropower generation projects, and IDACORP’s holding company expenses.
IDACORP’s and Idaho Power’s chief operating decision maker is regularly provided with segment expense information for utility operations at the same level of detail as presented in Idaho Power’s condensed 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).
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| Utility Operations | All Other | Eliminations | Consolidated Total | |||||||||||||||||||||||
| Three months ended September 30, 2026: | ||||||||||||||||||||||||||
| Revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||||||||
| Other income (expense), net | ||||||||||||||||||||||||||
| Interest income including carrying charges on regulatory assets | ( | |||||||||||||||||||||||||
| Earnings of unconsolidated equity-method investments | ||||||||||||||||||||||||||
| Interest expense | ( | |||||||||||||||||||||||||
| Income tax expense (benefit) | ( | |||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | ||||||||||||||||||||||||||
| Expenditures for long-lived assets | ||||||||||||||||||||||||||
Total assets as of September 30, 2026 | ( | |||||||||||||||||||||||||
| Three months ended September 30, 2025: | ||||||||||||||||||||||||||
| Revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||||||||
| Other income (expense), net | ||||||||||||||||||||||||||
| Interest income including carrying charges on regulatory assets | ( | |||||||||||||||||||||||||
| Earnings of unconsolidated equity-method investments | ||||||||||||||||||||||||||
| Interest expense | ( | |||||||||||||||||||||||||
| Income tax expense | ||||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | ||||||||||||||||||||||||||
| Expenditures for long-lived assets | ||||||||||||||||||||||||||
| Nine months ended September 30, 2026: | ||||||||||||||||||||||||||
| Revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||||||||
| Other income (expense), net | ||||||||||||||||||||||||||
| Interest income including carrying charges on regulatory assets | ( | |||||||||||||||||||||||||
| Earnings of unconsolidated equity-method investments | ||||||||||||||||||||||||||
| Interest expense | ( | |||||||||||||||||||||||||
| Income tax expense (benefit) | ( | |||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | ||||||||||||||||||||||||||
| Expenditures for long-lived assets | ||||||||||||||||||||||||||
| Nine months ended September 30, 2025: | ||||||||||||||||||||||||||
| Revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||||||||
| Other income (expense), net | ( | |||||||||||||||||||||||||
| Interest income including carrying charges on regulatory assets | ( | |||||||||||||||||||||||||
| Earnings of unconsolidated equity-method investments | ||||||||||||||||||||||||||
| Interest expense | ( | |||||||||||||||||||||||||
| Income tax (benefit) expense | ( | ( | ||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | ||||||||||||||||||||||||||
| Expenditures for long-lived assets | ||||||||||||||||||||||||||
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14. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
The table below presents changes in components of AOCI, net of tax (in thousands of dollars). Items in parentheses indicate charges to AOCI.
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Defined benefit pension items | ||||||||||||||||||||||||||
| Balance at beginning of period | $ | ( | $ | ( | $ | ( | $ | ( | ||||||||||||||||||
| Other comprehensive income before reclassification | ( | |||||||||||||||||||||||||
| Amounts reclassified out of AOCI | ||||||||||||||||||||||||||
| Balance at end of period | $ | ( | $ | ( | $ | ( | $ | ( | ||||||||||||||||||
The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified (in thousands of dollars). Items in parentheses indicate increases to net income.
| Amount Reclassified from AOCI | ||||||||||||||||||||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
Amortization of defined benefit pension items(1) | ||||||||||||||||||||||||||
| Prior service cost | $ | $ | $ | $ | ||||||||||||||||||||||
| Net loss | ||||||||||||||||||||||||||
| Total before tax | ||||||||||||||||||||||||||
Tax benefit(2) | ( | ( | ( | ( | ||||||||||||||||||||||
| Total reclassification for the period, net of tax | $ | $ | $ | $ | ||||||||||||||||||||||
(1) Amortization of these items is included in IDACORP's condensed consolidated statements of income in other operating expenses and in Idaho Power's condensed consolidated statements of income in other expense, net.
(2) The tax benefit is included in income tax expense in the condensed consolidated statements of income of both IDACORP and Idaho Power.
15. CHANGES IN IDAHO POWER RETAINED EARNINGS
The table below presents changes in Idaho Power retained earnings (in thousands of dollars).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Balance at beginning of period | $ | $ | $ | $ | ||||||||||||||||||||||
| Net income | ||||||||||||||||||||||||||
| Dividends to parent | ( | ( | ( | ( | ||||||||||||||||||||||
| Balance at end of period | $ | $ | $ | $ | ||||||||||||||||||||||
16. ASSETS HELD FOR SALE
On February 13, 2026, Idaho Power executed a definitive asset purchase 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 as of 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. Idaho Power also agreed to provide certain transition services to OTEC for a limited post-closing period for a fee. While Idaho Power expects the transaction to be completed within one year of September 30, 2026, the Oregon Sale is subject to various closing conditions, including approvals of the OPUC, IPUC, and FERC, as well as certain price adjustment and termination provisions.
36
Idaho Power determined that the assets and liabilities related to the Oregon Sale (disposal group) met the criteria for classification as held for sale as of September 30, 2026. Accordingly, the disposal group was reclassified to assets held for sale and liabilities held for sale, respectively, within the condensed consolidated balance sheets as of September 30, 2026. The disposal group is reported within IDACORP's Utility Operations reportable segment. See Note 13 - "Segment Information."
Upon reclassification, the disposal group was measured at the lower of its carrying amount or estimated fair value less costs to sell. As a result of this measurement, the fair value less costs to sell of the disposal group exceeds its net carrying amount as of September 30, 2026, and accordingly no impairment loss has been recognized for the three months and nine months ended September 30, 2026. Any gain on the Oregon Sale will be recognized upon closing of the transaction. Because depreciation and amortization of the assets and liabilities included in the disposal group continue to be reflected in Oregon customer rates through closing of the transaction, Idaho Power will continue recording depreciation and amortization on the disposal group through that date.
The disposal group has not been classified as a discontinued operation and the historical results of the disposal group are included in the condensed consolidated statements of income for all periods presented.
The table below summarizes components of assets and liabilities in the disposal group classified as held for sale on the condensed consolidated balance sheets (in thousands of dollars):
| September 30, 2026 | ||||||||
| Assets held for sale: | ||||||||
| Current regulatory assets | $ | |||||||
| Utility plant in service | ||||||||
| Accumulated provision for depreciation | ( | |||||||
| Construction work in progress | ||||||||
| Regulatory assets | ||||||||
Total assets held for sale(1) | $ | |||||||
| Liabilities held for sale: | ||||||||
| Current regulatory liabilities | $ | |||||||
| Regulatory liabilities | ||||||||
Total liabilities held for sale(1) | $ | |||||||
(1) Total assets held for sale and total liabilities held for sale are presented within current assets and current liabilities, respectively, on the condensed consolidated balance sheets as of September 30, 2026, as the sale is expected to be completed within 12 months.
37
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of IDACORP, Inc.
Results of Review of Interim Financial Information
We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of September 30, 2026, the related condensed consolidated statements of income, comprehensive income and equity for the three-month and nine-month periods ended September 30, 2026 and 2025, and of cash flows for the nine-month periods ended September 30, 2026 and 2025, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2025, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 19, 2026, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of the Company’s management. 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
October 29, 2026
38
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Idaho Power Company
Results of Review of Interim Financial Information
We have reviewed the accompanying condensed consolidated balance sheet of Idaho Power Company and subsidiary (the “Company”) as of September 30, 2026, the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2026 and 2025, and of cash flows for the nine-month periods ended September 30, 2026 and 2025, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2025, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 19, 2026, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of the Company’s management. 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
October 29, 2026
39
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
In MD&A in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. While reading this MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report. This discussion updates the MD&A included in the 2025 Annual Report, and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year, particularly in light of the seasonality of Idaho Power's sales volumes, as discussed below.
INTRODUCTION
IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the IPUC, OPUC, and FERC. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity. Idaho Power experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.
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
Management's Outlook and Company Objectives
In the 2025 Annual Report, IDACORP's and Idaho Power's management included a summary of their business objectives for the companies for 2026 and beyond, under the heading "Executive Overview" in the MD&A. As of the date of this report, management's outlook and strategy remain consistent with that discussion, as updated by the discussion in this MD&A. Some notable developments that have occurred since that report include the following:
•Idaho Power continues to experience and forecast positive customer growth in its service area. During the twelve months ended September 30, 2026, Idaho Power's customer count grew by approximately 15,000 customers and the customer growth rate was 2.2 percent.
•In September 2026, IDACORP's board of directors approved an increase in the regular quarterly cash dividend on IDACORP's common stock from $0.88 per share to $0.90 per share, as a part of a 200 percent increase in quarterly dividends over the last 15 years.
•So far in 2026, Idaho Power has taken important actions and several key projects achieved notable milestones, underscoring significant progress towards addressing Idaho Power's growing capacity and energy needs in 2026 and beyond:
◦In March, Idaho Power filed a CPCN request for two facilities: (1) a 222 MW natural gas-fueled facility, with an expected in-service date in 2029, and (2) a 430 MW natural gas-fueled facility, with an expected in-service date in 2030. As of the date of this report, the CPCN request remains pending.
◦Also in March, the IPUC approved Idaho Power's agreement to purchase the output of an 80 MW solar facility, with a scheduled online date of June 2027. The IPUC also approved Idaho Power's CPCN request 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. Construction commenced at the Bennett Mountain power plant in May 2026.
◦In April, Idaho Power, jointly with co-owner PacifiCorp, filed a CPCN request for Segment E-8 for the GWW transmission line, with an expected in-service date for the entire segment in 2030 or later. As of the date of this report, the CPCN request remains pending.
◦In June, Idaho Power filed an application with the IPUC for an order approving a 20-year PPA with Bluebird Solar Project LLC, supplying up to 200 MW of output to Idaho Power, along with a 20-year energy storage system tolling agreement for 100 MW of dispatchable energy storage capacity. Both are expected to be in-service by June 2028. As of the date of this report, the application remains pending.
◦The conversion of unit 2 at the North Valmy plant from coal to natural gas was completed in June, ending all coal-fired generation at the plant.
40
◦Also in June, the Hemingway expansion and Boise Bench battery energy storage systems became fully operational, adding 250 MW of energy storage.
◦Construction commenced in June on SWIP-N, a 285-mile high voltage transmission line, with an expected in-service date in 2028.
◦In July, Idaho Power began stringing transmission line wire on B2H and construction continues to progress, with more than half of transmission structures erected and nearly a quarter of conductor installed. B2H remains targeted for a late 2027 in-service date.
◦In July, the IPUC approved Idaho Power's application for a determination that expenditures from 2016 through 2025 on relicensing of the HCC were prudently incurred and thus eligible for inclusion in retail rates in a future regulatory proceeding. In September, FERC issued the final Supplemental Environmental Impact Statement for Idaho Power's HCC relicensing efforts. Idaho Power believes issuance of a new HCC license by the FERC will be in 2027 or thereafter.
Summary of 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 (in thousands of dollars or shares, except earnings per share amounts):
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Idaho Power net income | $ | 158,136 | $ | 122,156 | $ | 326,071 | $ | 273,121 | ||||||||||||||||||
| Net income attributable to IDACORP, Inc. | $ | 160,213 | $ | 124,437 | $ | 330,771 | $ | 279,865 | ||||||||||||||||||
| Weighted average outstanding shares – diluted | 58,656 | 55,055 | 57,402 | 54,522 | ||||||||||||||||||||||
| IDACORP, Inc. earnings per diluted share | $ | 2.73 | $ | 2.26 | $ | 5.76 | $ | 5.13 | ||||||||||||||||||
The table below provides a reconciliation of net income attributable to IDACORP for the three months and nine months ended September 30, 2026, from the same periods in 2025 (items are in millions of dollars and are before related income tax impact unless otherwise noted):
| Three months ended | Nine months ended | |||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. - September 30, 2025 | $ | 124.4 | $ | 279.9 | ||||||||||||||||||||||
Increase (decrease) in Idaho Power net income: | ||||||||||||||||||||||||||
Retail revenues per MWh, excluding large contract customers, net of power cost adjustment mechanisms | 38.1 | 75.7 | ||||||||||||||||||||||||
| Customer growth, excluding large contract customers, net of associated power supply costs and power cost adjustment mechanisms | 5.8 | 13.9 | ||||||||||||||||||||||||
| Usage per retail customer, excluding large contract customers, net of associated power supply costs and power cost adjustment mechanisms | 0.2 | (12.4) | ||||||||||||||||||||||||
| Idaho fixed cost adjustment (FCA) revenues | (3.7) | 18.2 | ||||||||||||||||||||||||
| Retail revenues from large contract customers, net of associated power supply costs and the PCA mechanism | 11.8 | 20.1 | ||||||||||||||||||||||||
| Other O&M expenses | (22.5) | (47.4) | ||||||||||||||||||||||||
| Depreciation and amortization expense | (7.4) | (18.4) | ||||||||||||||||||||||||
Other changes in operating revenues and expenses, net | 10.6 | 40.0 | ||||||||||||||||||||||||
| Increase in Idaho Power operating income | 32.9 | 89.7 | ||||||||||||||||||||||||
| Non-operating expense, net | (1.1) | (5.7) | ||||||||||||||||||||||||
| Additional ADITC amortization | (2.5) | (32.7) | ||||||||||||||||||||||||
| Income tax expense, excluding additional ADITC amortization | 6.7 | 1.7 | ||||||||||||||||||||||||
| Total increase in Idaho Power net income | 36.0 | 53.0 | ||||||||||||||||||||||||
Other IDACORP changes (net of tax) | (0.2) | (2.1) | ||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. - September 30, 2026 | $ | 160.2 | $ | 330.8 | ||||||||||||||||||||||
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Net Income - Third Quarter 2026
IDACORP's net income increased $35.8 million for the third quarter of 2026 compared with the third quarter of 2025, due primarily to higher net income at Idaho Power.
The net increase in retail revenues per MWh, excluding large contract customers, and net of power cost adjustment mechanisms, increased operating income by $38.1 million in the third quarter of 2026 compared with the third quarter of 2025. This benefit was due primarily to an overall increase in Idaho base rates, effective January 1, 2026, from the outcome of the 2025 Settlement Stipulation. For more information on the 2025 Settlement Stipulation, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report.
Customer growth, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $5.8 million in the third quarter of 2026 compared with the third quarter of 2025, as the number of Idaho Power customers grew by approximately 15,000, or 2.2 percent, during the twelve months ended September 30, 2026. Usage per retail customer, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, was relatively consistent in the third quarter of 2026 compared with the third quarter of 2025, as a 1 percent increase in usage per residential customer and a 3 percent increase in usage per irrigation customer were mostly offset by a decrease in usage per industrial customer. An increase in the deferral of residential and small commercial customer revenues through the FCA mechanism negatively affected retail revenues by $3.7 million.
Retail revenues from large contract customers, net of associated power supply costs and the PCA mechanism, increased operating income by $11.8 million in the third quarter of 2026 compared with the third quarter of 2025. This benefit was primarily due to the commencement of Idaho Power earning revenue under a large customer contract on June 1, 2026, the overall increase in Idaho base rates effective January 1, 2026, and an increase in usage per large contract customer.
Other O&M expenses increased $22.5 million in the third quarter of 2026 compared with the third quarter of 2025, primarily due to the amortization of previously deferred costs associated with the conversion of generating units at the Jim Bridger and North Valmy plants from coal to natural gas and higher wildfire mitigation costs, including amortization of previously deferred wildfire mitigation program expenses. These increases were substantially offset by corresponding revenues recognized through regulatory recovery mechanisms, including the 2025 Settlement Stipulation and approved Idaho and Oregon customer rates.
Depreciation and amortization expense increased $7.4 million in the third quarter of 2026 compared with the third quarter of 2025, due primarily to an increase in plant-in-service.
Other changes in operating revenues and expenses, net, increased operating income by $10.6 million in the third quarter of 2026 compared with the third quarter of 2025. This was due primarily to a decrease in net power supply expenses that were not accrued for future refund in rates through Idaho Power's power cost adjustment mechanisms. Also contributing to the increase in other changes in operating revenues and expenses, net, was lower property tax expense due to property tax legislative changes in Idaho.
Non-operating expense, net, increased $1.1 million in the third quarter of 2026 compared with the third quarter of 2025. Higher long-term debt balances increased interest expense, while lower interest-bearing cash investment balances decreased interest income. This increase was mostly offset by an increase in AFUDC income in the third quarter of 2026 compared with the third quarter of 2025, as the average construction work in progress balance was higher.
The decrease in income tax expense for the third quarter of 2026, compared with the third quarter of 2025, was primarily due to plant-related flow-through items, partially offset by statutory taxes on higher pre-tax income and a decrease in additional ADITC amortization. Based on Idaho Power's current expectations of full-year 2026 financial results, Idaho Power recorded no additional ADITC amortization during the third quarter of 2026, compared with $2.5 million of additional ADITC amortization during the third quarter of 2025.
Net Income - Year-To-Date 2026
IDACORP's net income increased $50.9 million for the first nine months of 2026 compared with the first nine months of 2025, due primarily to higher net income at Idaho Power.
The net increase in retail revenues per MWh, excluding large contract customers, and net of power cost adjustment mechanisms, increased operating income by $75.7 million in the first nine months of 2026 compared with the first nine months
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of 2025. This benefit was due primarily to an overall increase in Idaho base rates, effective January 1, 2026, from the outcome of the 2025 Settlement Stipulation.
Customer growth, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $13.9 million in the first nine months of 2026 compared with the first nine months of 2025. Usage per retail customer, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, decreased operating income by $12.4 million in the first nine months of 2026 compared with the first nine months of 2025. Residential usage per customer decreased most significantly, as more moderate temperatures in the first six months of 2026 compared with the first six months of 2025 led residential customers to use less energy for heating and cooling purposes, slightly offset by less moderate temperatures and higher usage per customer in the third quarter of 2026 compared with the third quarter of 2025. A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $18.2 million.
Retail revenues from large contract customers, net of associated power supply costs and the PCA mechanism, increased operating income by $20.1 million in the first nine months of 2026 compared with the first nine months of 2025. This change was primarily due to the commencement of Idaho Power earning revenue under a large customer contract on June 1, 2026, the overall increase in Idaho base rates effective January 1, 2026, and an increase in usage per large contract customer.
Other O&M expenses increased $47.4 million in the first nine months of 2026 compared with the first nine months of 2025, primarily due to the amortization of previously deferred costs associated with the conversion of generating units at the Jim Bridger and North Valmy plants from coal to natural gas and higher wildfire mitigation costs, including amortization of previously deferred wildfire mitigation program expenses. These increases were substantially offset by corresponding revenues recognized through regulatory recovery mechanisms, including the 2025 Settlement Stipulation and approved Idaho and Oregon customer rates.
Depreciation and amortization expense increased $18.4 million in the first nine months of 2026 compared with the first nine months of 2025, due primarily to an increase in plant-in-service.
Other changes in operating revenues and expenses, net, increased operating income by $40.0 million in the first nine months of 2026 compared with the first nine months of 2025. This was due primarily to a decrease in net power supply expenses that were not accrued for future refund in rates through Idaho Power's power cost adjustment mechanisms. Also contributing to the increase in other changes in operating revenues and expenses, net, was lower property tax expense due to property tax legislative changes in Idaho.
Non-operating expense, net, increased $5.7 million in the first nine months of 2026 compared with the first nine months of 2025. Higher long-term debt balances increased interest expense, while lower interest-bearing cash investment balances decreased interest income. This increase was partially offset by an increase in AFUDC income in the first nine months of 2026 compared with the first nine months of 2025, as the average construction work in progress balance was higher.
The increase in income tax expense was principally the result of a decrease in additional ADITC amortization and statutory taxes on higher pre-tax income, partially offset by plant-related flow-through items. Based on Idaho Power's current expectations of full-year 2026 financial results, Idaho Power recorded $6.3 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during the first nine months of 2026, compared with $39.0 million of additional ADITC amortization during the same period in 2025.
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 several factors and trends, and the impact of those factors and trends 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 and trends are as follows:
•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.
Idaho Power filed its most recent general rate case in Idaho in May 2025. The IPUC approved a settlement stipulation for the general rate case in December 2025, with rates effective January 1, 2026. The general rate case filing and the
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settlement stipulation are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. Idaho Power continues to evaluate the timing of its next general rate cases in Idaho and Oregon.
•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 authorized by the IPUC and OPUC and any write-downs. 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. To help meet growing capacity and energy needs, Idaho Power is planning to construct three new natural gas-fired generating facilities with planned generation capacities of 167 MW, 222 MW, and 430 MW, and expected in-service dates in 2028, 2029, and 2030, respectively. Idaho Power also has RFPs in progress for resources beyond those years. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company continues a significant relicensing effort for the HCC, its largest hydropower generation resource. Idaho Power intends to pursue timely inclusion of completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding, as well as through recovery via regulator-approved large customer contracts, 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. 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. Over the twelve months ended September 30, 2026, Idaho Power's customer count grew by 2.2 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 in the foreseeable future. This was visible during the third quarter of 2026, with an increase in large contract industrial loads and revenues over the prior year's third quarter driven by the ramp-up in electric service and in revenues by two large contract customers. Idaho Power expects these customers, together with other large contract customers, to ramp up operations further during the remainder of 2026 and for the next several years. Idaho Power is in the process of discussing and negotiating terms, conditions, and pricing of potential service agreements with several large contract customers.
Idaho Power is preparing its 2027 IRP, its 20-year forecast of load and power supply resource options. Included in the below table are Idaho Power's preliminary load forecast assumptions the company anticipates using in the 2027 IRP as of the date of this report, and for comparison purposes, growth rates Idaho Power used in its prior two IRPs.
| 5-Year Forecasted Annual Growth Rate | 20-Year Forecasted Annual Growth Rate | |||||||||||||||||||||||||
| Retail Sales (Billed MWh) | Annual Peak (Peak Demand MW) | Retail Sales (Billed MWh) | Annual Peak (Peak Demand MW) | |||||||||||||||||||||||
| 2027 IRP (Preliminary) | 8.9% | 5.4% | 2.6% | 2.0% | ||||||||||||||||||||||
| 2025 IRP | 8.3% | 5.1% | 2.7% | 1.9% | ||||||||||||||||||||||
| 2023 IRP | 5.5% | 3.7% | 2.1% | 1.8% | ||||||||||||||||||||||
Customer growth has contributed to increases in peak loads experienced in recent years. 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 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,
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transmission, and distribution infrastructure. For more information on Idaho Power's system investments and resource procurements, see "Liquidity and Capital Resources" in this MD&A.
•Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters of each year, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use 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 FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.
Further, as Idaho Power's hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydropower generation decreases, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales. Much of the adverse or favorable impact of this variability is addressed through the Idaho and Oregon power cost adjustment mechanisms, which mitigate in large part the impact on earnings. For 2026, as of the date of this report, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 6.0 million MWh, compared with actual generation of 7.0 million MWh in 2025 and a 20-year average annual total of approximately 7.3 million MWh.
•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 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 conditions. Idaho Power is taking a proactive approach to wildfire risk in its service area and transmission corridors. In 2021, Idaho Power adopted a WMP that outlined 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 the 2025 Annual Report and the condensed consolidated financial statements included in this report. In December 2025, Idaho Power filed its 2026-2028 WMP with the OPUC, and in June 2026, the OPUC issued an order approving the WMP. In October 2026, Idaho Power filed its 2027 WMP with the IPUC for approval. See "Other Matters - Idaho Wildfire Standard of Care Act" included in the 2025 Annual Report, for additional details.
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RESULTS OF OPERATIONS
This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three months and nine months ended September 30, 2026. In this analysis, the results for the three months and nine months ended September 30, 2026, are compared with the same periods in 2025.
The table below presents Idaho Power’s energy sales and supply (in thousands of MWh).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Retail energy sales | 5,000 | 4,854 | 12,852 | 12,677 | ||||||||||||||||||||||
| Wholesale energy sales | 265 | 193 | 483 | 1,230 | ||||||||||||||||||||||
| Energy sales bundled with renewable energy credits | — | 26 | 80 | 641 | ||||||||||||||||||||||
| Total energy sales | 5,265 | 5,073 | 13,415 | 14,548 | ||||||||||||||||||||||
| Hydropower generation | 1,315 | 1,483 | 4,469 | 5,751 | ||||||||||||||||||||||
Jointly-owned thermal generation(1) | 1,371 | 1,046 | 2,285 | 2,183 | ||||||||||||||||||||||
| Natural gas and other generation | 1,304 | 1,276 | 2,690 | 2,802 | ||||||||||||||||||||||
| Total system generation | 3,990 | 3,805 | 9,444 | 10,736 | ||||||||||||||||||||||
| Purchased power | 1,610 | 1,641 | 4,906 | 4,849 | ||||||||||||||||||||||
| Line losses, net of battery discharge | (335) | (373) | (935) | (1,037) | ||||||||||||||||||||||
| Total energy supply | 5,265 | 5,073 | 13,415 | 14,548 | ||||||||||||||||||||||
(1) "Jointly-owned thermal generation" consists of generation from steam plants that include coal-fired units as well as natural gas-fired units that were converted from coal.
Weather-related information for Boise, Idaho, is presented in the table below. 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 and is included for illustrative purposes.
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | Normal (2) | 2026 | 2025 | Normal (2) | |||||||||||||||||||||||||||||||||
Heating degree-days(1) | 61 | 7 | 94 | 2,624 | 2,989 | 3,181 | ||||||||||||||||||||||||||||||||
Cooling degree-days(1) | 1,025 | 967 | 847 | 1,226 | 1,248 | 1,035 | ||||||||||||||||||||||||||||||||
| Precipitation (inches) | 0.5 | 1.7 | 0.8 | 7.9 | 8.1 | 8.0 | ||||||||||||||||||||||||||||||||
(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 cooling. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.
(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 normal amounts are the sum of the monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration.
Sales Volume and Generation: Retail sales volumes increased 3 percent and 1 percent for the third quarter and first nine months of 2026, respectively, compared with the same periods in 2025. The increases were primarily due to customer growth, as the number of Idaho Power's customers grew by 2.2 percent over the prior twelve months, and increased usage per large contract and irrigation customers. For more information on the changes in sales volumes, see the "Operating Revenues" section below in this MD&A.
Total system generation increased 5 percent in the third quarter of 2026 compared with the third quarter of 2025, due primarily to higher jointly-owned thermal generation, partially offset by lower hydropower generation. Total system generation decreased 12 percent in the first nine months of 2026 compared with the same period in 2025, due primarily to lower hydropower generation and natural gas generation, partially offset by an increase in jointly-owned thermal generation. For more information on the changes in generation, see the "Operating Expenses" section below in this MD&A.
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The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms."
Operating Revenues
Retail Revenues: The table below presents Idaho Power’s retail revenues (in thousands of dollars), MWh sales volumes (in thousands of MWh), and the number of retail customers.
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Retail revenues: | ||||||||||||||||||||||||||
Residential (includes $(7,811), $(4,125), $8,674 and $(9,194), respectively, related to the FCA)(1) | $ | 235,900 | $ | 195,445 | $ | 608,260 | $ | 535,505 | ||||||||||||||||||
Commercial (includes $(58), $(70), $137, and $(150), respectively, related to the FCA)(1) | 123,946 | 111,510 | 319,374 | 304,014 | ||||||||||||||||||||||
| Industrial | 91,278 | 72,079 | 236,963 | 205,526 | ||||||||||||||||||||||
| Irrigation | 115,648 | 101,690 | 214,895 | 195,172 | ||||||||||||||||||||||
Deferred revenue related to HCC relicensing AFUDC(2) | (12,605) | (2,854) | (30,240) | (6,848) | ||||||||||||||||||||||
| Total retail revenues | $ | 554,167 | $ | 477,870 | $ | 1,349,252 | $ | 1,233,369 | ||||||||||||||||||
| Volume of retail sales (MWh) | ||||||||||||||||||||||||||
| Residential | 1,681 | 1,621 | 4,515 | 4,593 | ||||||||||||||||||||||
| Commercial | 1,210 | 1,191 | 3,298 | 3,302 | ||||||||||||||||||||||
| Industrial | 1,041 | 984 | 2,995 | 2,817 | ||||||||||||||||||||||
| Irrigation | 1,068 | 1,058 | 2,044 | 1,965 | ||||||||||||||||||||||
| Total retail MWh sales | 5,000 | 4,854 | 12,852 | 12,677 | ||||||||||||||||||||||
| Number of retail customers at period end | ||||||||||||||||||||||||||
| Residential | 570,466 | 557,065 | ||||||||||||||||||||||||
| Commercial | 82,035 | 80,707 | ||||||||||||||||||||||||
| Industrial | 157 | 150 | ||||||||||||||||||||||||
| Irrigation | 22,709 | 22,620 | ||||||||||||||||||||||||
| Total customers | 675,367 | 660,542 | ||||||||||||||||||||||||
(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 included in the 2025 Annual 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.
Changes in rates, changes in customer demand, customer growth, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. 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 moderate 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 increased $76.3 million and $115.9 million during the third quarter and first nine months of 2026, respectively, compared with the same periods in 2025. The factors affecting retail revenues during the periods are discussed below.
•Rates: Customer rates, excluding revenues related to large contract customers, and power cost adjustment mechanisms, increased retail revenues by $38.1 million and $75.7 million, respectively, for the three months and nine months ended September 30, 2026, compared with the same periods in 2025. This was due primarily to an overall increase in Idaho base rates, effective January 1, 2026, from the outcome of the 2025 Settlement Stipulation. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which increased revenues
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by $18.3 million and decreased revenues by $5.1 million in the third quarter and first nine months of 2026, respectively, compared with the same periods of 2025. The amount collected from customers in rates under the power cost adjustment mechanisms has relatively little effect on operating income as a corresponding amount is recorded as expense in the same period it is collected through rates.
•Customers: Customer growth of 2.2 percent during the twelve months ended September 30, 2026, increased retail revenues, excluding large contract customers, by $9.2 million and $20.6 million in the third quarter and first nine months of 2026, respectively, compared with the same periods of 2025.
•Usage: Usage (on a per customer basis), excluding large contract customers, increased retail revenues by $0.7 million in the third quarter of 2026, compared with the third quarter of 2025, due to a 3 percent increase in usage per irrigation customer and a 1 percent increase in usage per residential customer, partially offset by a 3 percent decrease in usage per industrial customer and changes in customer mix. Lower usage per customer, excluding large contract customers, decreased retail revenues by $18.3 million in the first nine months of 2026, compared with the same period of 2025. Usage per residential customer decreased most significantly, as more moderate temperatures in the first six months of 2026 compared with the first six months of 2025 led these customers to use less energy for heating and cooling purposes, slightly offset by less moderate temperatures and higher usage per residential customer in the third quarter of 2026 compared with the third quarter of 2025.
•FCA Mechanism: An increase in the deferral of residential and small commercial customer revenues through the FCA mechanism negatively affected retail revenues by $3.7 million in the third quarter of 2026, compared with the same period in 2025. Conversely, a decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $18.2 million in the first nine months of 2026, compared with the same period in 2025.
•Large Contract Customers: Retail revenues from large contract customers increased $13.7 million and $24.8 million during the third quarter and first nine months of 2026, respectively, compared with the same periods of 2025. The increases were primarily due to the commencement of Idaho Power earning revenue under a large customer contract on June 1, 2026, the overall increase in Idaho base rates effective January 1, 2026, and an increase in usage per large contract customer.
Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the energy imbalance market in the western United States, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales (in thousands of dollars or MWh, except for revenue per MWh amounts).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Wholesale energy revenues | $ | 16,957 | $ | 10,520 | $ | 25,328 | $ | 45,443 | ||||||||||||||||||
| Wholesale MWh sold | 265 | 193 | 483 | 1,230 | ||||||||||||||||||||||
| Wholesale energy revenues per MWh | $ | 63.99 | $ | 54.51 | $ | 52.44 | $ | 36.95 | ||||||||||||||||||
In the third quarter of 2026, wholesale energy revenues increased $6.4 million compared with the same period of 2025, due primarily to an increase in wholesale energy volumes sold and higher market prices. Wholesale energy revenues decreased $20.1 million in the first nine months of 2026, compared with the same period of 2025, as lower wholesale energy sales volumes were partially offset by higher market prices. The financial impacts of fluctuations in wholesale energy sales are largely mitigated by Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in this section of the MD&A under "Power Cost Adjustment Mechanisms."
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Operating Expenses
Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes (in thousands of dollars or MWh, except for per MWh amounts).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Purchased power expense | $ | 140,519 | $ | 121,276 | $ | 296,056 | $ | 284,163 | ||||||||||||||||||
| MWh purchased | 1,610 | 1,641 | 4,906 | 4,849 | ||||||||||||||||||||||
| Average cost per MWh | $ | 87.28 | $ | 73.90 | $ | 60.35 | $ | 58.60 | ||||||||||||||||||
Purchased power expense increased $19.2 million, or 16 percent, and $11.9 million, or 4 percent, during the third quarter and first nine months of 2026, respectively, compared with the same periods of 2025, primarily due to higher market prices.
Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation (in thousands of dollars or MWh, except for per MWh amounts).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Fuel Expense | ||||||||||||||||||||||||||
Jointly-owned thermal(1) | $ | 33,847 | $ | 37,350 | $ | 65,602 | $ | 85,082 | ||||||||||||||||||
Natural gas(2) | 40,343 | 37,642 | 100,640 | 94,156 | ||||||||||||||||||||||
| Total fuel expense | $ | 74,190 | $ | 74,992 | $ | 166,242 | $ | 179,238 | ||||||||||||||||||
| MWh generated | ||||||||||||||||||||||||||
Jointly-owned thermal(1) | 1,371 | 1,046 | 2,285 | 2,183 | ||||||||||||||||||||||
Natural gas(2) | 1,304 | 1,276 | 2,690 | 2,802 | ||||||||||||||||||||||
| Total MWh generated | 2,675 | 2,322 | 4,975 | 4,985 | ||||||||||||||||||||||
| Average cost per MWh - Jointly-owned thermal | $ | 24.69 | $ | 35.71 | $ | 28.71 | $ | 38.97 | ||||||||||||||||||
| Average cost per MWh - Natural gas | $ | 30.94 | $ | 29.50 | $ | 37.41 | $ | 33.60 | ||||||||||||||||||
| Weighted average, all sources | $ | 27.73 | $ | 32.30 | $ | 33.42 | $ | 35.96 | ||||||||||||||||||
(1) "Jointly-owned thermal" consists of expenses and generation from steam plants that include coal-fired units as well as natural gas-fired units that were converted from coal.
(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 $0.8 million, or 1 percent, and $13.0 million, or 7 percent, in the third quarter and first nine months of 2026, respectively, compared with the same periods of 2025, primarily attributable to a decrease in coal prices. For the third quarter of 2026, this decrease was partially offset by a 15 percent increase in total MWh generated from jointly-owned thermal and natural gas facilities compared with the same period of 2025.
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. For the third quarters and first nine months of 2026 and 2025, losses on financial gas hedges of $6.2 million and $9.1 million, respectively, and $33.9 million and $21.9 million, respectively, increased natural gas fuel expense. Most of these realized hedging losses 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. Variability 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 variability 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, capital lease payments associated with battery energy storage systems, 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 or accrued during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Because of the power cost adjustment mechanisms, the primary financial impact 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 (in thousands of dollars).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Idaho power supply cost accrual (deferral) | $ | 11,034 | $ | (2,002) | $ | 37,987 | $ | 46,935 | ||||||||||||||||||
| Oregon power supply cost deferral | — | (523) | — | (2,317) | ||||||||||||||||||||||
| Amortization of prior year authorized balances | (23,436) | (15,770) | (50,789) | 13,349 | ||||||||||||||||||||||
| Total power cost adjustment (income statement) | $ | (12,402) | $ | (18,295) | $ | (12,802) | $ | 57,967 | ||||||||||||||||||
The power supply accruals (deferrals) represent the portion of the power supply cost fluctuations accrued (deferred) 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 the third quarter and first nine months of 2026, lower purchased power and fuel 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. 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 PCA year (the balancing adjustment component of the power cost adjustment mechanism).
Other O&M Expenses: Other O&M expenses increased $22.5 million and $47.4 million in the third quarter and first nine months of 2026, respectively, compared with the same periods of 2025. These increases were primarily due to the amortization of previously deferred costs associated with the conversion of generating units at the Jim Bridger and North Valmy plants from coal to natural gas and higher wildfire mitigation costs, including amortization of previously deferred wildfire mitigation program expenses. These increases were substantially offset by corresponding revenues recognized through regulatory recovery mechanisms, including the 2025 Settlement Stipulation and approved Idaho and Oregon customer rates.
Income Taxes
IDACORP's and Idaho Power's income tax expense increased $29.1 million and $31.0 million, respectively, for the nine months ended September 30, 2026, when compared with the same period in 2025, primarily due to decreased ADITC amortization from the regulatory mechanism described in Note 3 – “Regulatory Matters” to the condensed consolidated financial statements included in this report, and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. Also, greater flow-through tax benefits from plant-related items mostly offset an increase in statutory taxes on higher pre-tax income. For information relating to IDACORP's and Idaho Power's computation of income tax expense, see Note 2 - "Income Taxes" to the condensed consolidated financial statements included in this report.
LIQUIDITY AND CAPITAL RESOURCES
Overview
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. Idaho Power files for rate adjustments for recovery of
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operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators.
IDACORP may issue debt securities or common stock, and Idaho Power may issue first mortgage bonds or other debt securities to fund its business. Idaho Power also periodically evaluates whether partial or full early redemption of one or more outstanding series of first mortgage bonds is desirable and, in some cases, may refinance existing indebtedness with new indebtedness.
As of October 23, 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;
•IDACORP's executed FSAs under its 2024 ATM, which may be physically settled with common stock in exchange for net proceeds, which as of October 23, 2026, would have been approximately $154 million;
•IDACORP's executed FSAs under its 2026 ATM, which may be physically settled with common stock in exchange for net proceeds, which as of October 23, 2026, would have been approximately $532 million;
•IDACORP's FSAs, executed outside of its ATMs, which may be physically settled with common stock in exchange for net proceeds, which as of October 23, 2026, would have been approximately $187 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; $1.3 billion is 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 Employee Savings Plan. IDACORP may discontinue using original issuances of shares for these plans at any time.
In February and August 2026, Idaho Power issued $350 million and $200 million in first mortgage bonds, respectively. In July 2026, Idaho Power repaid $116 million in aggregate principal amount of maturing pollution control revenue bonds. For more detailed information about Idaho Power's long-term debt transactions, see Note 5 - "Long-Term Debt" to the condensed consolidated financial statements included in this report.
During the nine months ended September 30, 2026, IDACORP executed FSAs under its 2024 ATM and 2026 ATM at aggregate gross sales prices totaling $689 million. In addition, IDACORP settled FSAs under its 2024 ATM and FSAs executed outside of its ATMs, resulting in aggregate cash proceeds of $314 million.
Subsequently, through the date of this report, IDACORP settled FSAs executed outside of its ATMs, resulting in cash proceeds of $111 million in October 2026.
For more detailed information about IDACORP's equity transactions, see the discussion below in this MD&A and Note 6 - "Common Stock," to the condensed consolidated financial statements included in this report.
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 September 30, 2026, IDACORP's and Idaho Power's capital structure ratios, with no impact to equity from unsettled FSAs, were as follows:
| IDACORP | Idaho Power | |||||||||||||
| Debt | 49% | 49% | ||||||||||||
| Equity | 51% | 51% | ||||||||||||
IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.
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At September 30, 2026, IDACORP and Idaho Power believed they were in compliance with all credit facility and long-term debt covenants. Further, IDACORP and Idaho Power do not anticipate they will be in violation or breach of their respective debt covenants during 2026.
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 benefit 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 for the nine months ended September 30, 2026, were $378 million and $366 million, respectively, a decrease in cash flows from operations of $86 million for IDACORP and $99 million for Idaho Power, when compared with the same period in 2025. 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 the first nine months of 2026 when compared with the same period in 2025 were as follows:
•a $51 million and $53 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 $59 million;
•changes in deferred taxes and taxes accrued and receivable combined to increase operating cash flows for IDACORP and Idaho Power by $26 million and $87 million, respectively; 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 for IDACORP and Idaho Power by $78 million;
◦the changes in materials, supplies, and fuel stock decreased operating cash flow by $11 million for IDACORP and Idaho Power, which was 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 for IDACORP by $1 million and decreased operating cash flows for Idaho Power by $78 million. The difference in the changes between IDACORP and Idaho Power relates primarily to the timing of intercompany tax payments from Idaho Power to IDACORP; and
◦the changes in other assets and liabilities decreased cash flows by $18 million for IDACORP and Idaho Power, primarily due to Idaho Power's transmission network upgrade deposit payments and the timing of interest payments.
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 the nine months ended September 30, 2026, were $981 million and $969 million, respectively, increasing cash outflow by $250 million for IDACORP and by $253 million for Idaho Power when compared with the same period in 2025. Investing cash outflows for 2026 and 2025 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth and resource needs, aging plant and equipment, and environmental and regulatory compliance requirements. Investing cash outflows were partially offset in 2026 and 2025 by reimbursements from a B2H project joint funding partner and proceeds from the sale of renewable energy certificates.
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 the nine months ended September 30, 2026, were $574 million and $639 million, respectively, an increase of $343 million and $409 million for IDACORP and Idaho Power, respectively, when compared with the same period in 2025. IDACORP and Idaho Power financing cash inflows for 2026 were primarily related to Idaho Power's net proceeds from issuance of first mortgage bonds, IDACORP's issuance of common stock, and Idaho Power's receipt of a capital contribution from IDACORP, partially offset by the repayment of pollution control revenue bonds and dividend payments. IDACORP and Idaho Power financing cash inflows for 2025 were primarily related to Idaho Power's
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net proceeds from issuance of first mortgage bonds, partially offset by dividend payments and repayment of variable rate bonds. 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.
Financing Programs and Available Liquidity
IDACORP Equity Programs: IDACORP's ATMs include the 2024 ATM and the 2026 ATM, which were established in May 2024 and May 2026, respectively. At September 30, 2026, IDACORP's cumulative aggregate gross sales price of executed and outstanding FSAs under its ATMs was $689 million. Also at September 30, 2026, IDACORP had $66 million of remaining capacity under its 2026 ATM. Upon effectiveness of the 2026 ATM, the 2024 ATM terminated with respect to new issuances. If IDACORP had elected to physically settle the FSAs under its ATMs as of October 23, 2026, by delivering shares of common stock, aggregate cash proceeds would have been approximately $686 million. IDACORP may elect to settle the outstanding FSAs under its ATMs at any time through their respective maturity dates, which extend through February 29, 2028.
IDACORP's equity programs also include FSAs executed by IDACORP in May 2025 outside of its ATMs. Subsequent to September 30, 2026, and through the date of this report, IDACORP settled some of the FSAs under this program on October 15, 2026, resulting in cash proceeds of $111 million. If IDACORP had elected to physically settle the remaining FSAs outside of its ATMs as of October 23, 2026, by delivering shares of common stock, aggregate cash proceeds would have been approximately $187 million. IDACORP may elect to settle the remaining FSAs at any time through their maturity date of November 9, 2026.
Actual cash proceeds, if any, for settlement of the FSAs will depend on the method and timing IDACORP elects for settlement. For more detailed information about IDACORP's equity transactions, see Note 6 - "Common Stock" to the condensed consolidated financial statements included in this report.
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 June and July 2026, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.5 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. At September 30, 2026, $1.3 billion remained available for debt issuance under the regulatory orders. For more detailed information about Idaho Power's First Mortgage Bonds, see Note 5 - "Long-Term Debt" to the condensed consolidated financial statements included in this report.
Idaho Power Credit Facility: Idaho Power's incurrence of short-term indebtedness, such as its credit facility, is subject to the approval of the IPUC, OPUC, and WPSC. Idaho Power currently has authority for unsecured borrowing up to $600 million with a final maturity date no later than December 31, 2030. In October 2026, Idaho Power requested regulatory approval to maintain up to $1.0 billion of unsecured borrowings outstanding at any one time, with a final maturity date of December 31, 2033. The requests are intended to support liquidity and financial flexibility. In October 2026, the IPUC and OPUC approved Idaho Power's applications. As of the date of this report, the WPSC application remains pending.
Available Short-Term Borrowing Liquidity
The table below outlines available short-term borrowing liquidity as of the dates specified (in thousands of dollars).
| September 30, 2026 | December 31, 2025 | |||||||||||||||||||||||||
IDACORP(1) | Idaho Power | IDACORP(1) | Idaho Power | |||||||||||||||||||||||
| Revolving credit facility | $ | 100,000 | $ | 400,000 | $ | 100,000 | $ | 400,000 | ||||||||||||||||||
| Commercial paper outstanding | — | — | — | — | ||||||||||||||||||||||
| Net balance available | $ | 100,000 | $ | 400,000 | $ | 100,000 | $ | 400,000 | ||||||||||||||||||
(1) Holding company only.
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On October 23, 2026, IDACORP and Idaho Power had no loans outstanding under their respective revolving credit facilities and had no commercial paper outstanding.
Impact of Credit Ratings on Liquidity and Collateral Obligations
IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depend in part on their respective credit ratings. The following table outlines the ratings of IDACORP's and Idaho Power’s securities, and the ratings outlook, by Moody's Investors Service and Standard & Poor’s Ratings Services as of the date of this report:
| Moody's | Standard & Poor's | |||||||||||||||||||||||||
| IDACORP | Idaho Power | IDACORP | Idaho Power | |||||||||||||||||||||||
| Rating Outlook | Stable | Stable | Stable | Stable | ||||||||||||||||||||||
| Issuer Rating/Corporate | Baa3 | Baa2 | BBB | BBB | ||||||||||||||||||||||
| First Mortgage Bonds | None | A3 | ||||||||||||||||||||||||
| Senior Secured Debt | None | A3 | None | A- | ||||||||||||||||||||||
| Commercial Paper/Short-Term | P-3 | P-2 | A-2 | A-2 | ||||||||||||||||||||||
Credit ratings can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. In March 2026, Moody's rating for IDACORP was downgraded to Baa3 for long-term issuer rating and P-3 short-term commercial paper rating with a revised outlook of stable. At that time, Moody's rating for Idaho Power was downgraded to Baa2 for long-term issuer rating, A3 for first mortgage bonds, and A3 for senior secured debt with a revised outlook of stable. Moody's credit ratings of Baa3 and above are widely considered to be investment grade, or prime, ratings. The security ratings above reflect the views of Moody's or Standard & Poor's, as applicable. An explanation of the significance of these ratings may be obtained from the applicable rating agency. There have been no changes to IDACORP's or Idaho Power's ratings by Standard & Poor’s from those included in the 2025 Annual Report. Such ratings are not a recommendation to buy, sell, or hold securities.
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 I - Item 3 "Quantitative and Qualitative Disclosures About Market Risk" included in this report.
Capital Requirements
Idaho Power's cash capital expenditures, excluding AFUDC, were $1.15 billion during the nine months ended September 30, 2026. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2026 (including amounts incurred to-date) 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 their timing could 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 | |||||||||||||||||
Major Infrastructure Projects: Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of developments in certain of those projects since the discussion of these matters included in Part II, Item 7 - MD&A - "Capital Requirements" in the 2025 Annual Report. The discussion below should be read in conjunction with that report.
Resource Additions to Address Projected Energy and Capacity Deficits: Idaho Power's existing and sustained growth in customers, load, and demand for electricity, along with transmission constraints, has created the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs 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 resource needs in 2026 and beyond:
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•placed in service 250 MW of company-owned battery storage assets in June 2026 with expected useful lives of approximately 20 years;
•entered into 20-year agreements to purchase the storage capacity from two 100-MW battery storage facilities;
•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 five PPAs for a combined 825 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 agreements under Idaho Power’s Clean Energy Your Way program;
•received IPUC approval for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant, for which construction commenced in May 2026; and
•submitted an application to the IPUC for a CPCN for two natural gas-fueled power plants of 222 MW and 430 MW.
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 requested a CPCN for the resource. 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 under construction between the Longhorn 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 in late 2027.
Idaho Power's ownership interest in the project is approximately 45 percent, while PacifiCorp's ownership interest in the project is approximately 55 percent. Idaho Power has spent approximately $1.15 billion, including Idaho Power's AFUDC, on the B2H project through September 30, 2026. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $535 million in reimbursement as of September 30, 2026, 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 grants 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 filed three complaints in the Baker County and Union County Circuit Courts challenging the OPUC decision. All three complaints were voluntarily dismissed. 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 processed modifications of the Fire Protection and Suppression Plan. The court granted Idaho Power's and the Oregon Department of Energy's motion to dismiss the complaints in a letter order in April 2026. Petitioners in the case have filed a notice of intent to appeal the Morrow County Circuit Court's decision. In July 2026, Malheur Mining Company, Ltd. filed a complaint in federal district court, Pendleton division, against Idaho Power and the BLM asserting their mineral rights are being infringed upon by the B2H project and requesting various forms of relief, including damages and injunctive relief. In October 2026, the federal court judge denied the mining company's request for a temporary restraining order. 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. Idaho Power and PacifiCorp are parties to a joint funding agreement for permitting of the project. Idaho Power
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has expended approximately $127 million, including Idaho Power's AFUDC, for its share of the project through September 30, 2026.
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 an ownership interest in four segments within this area, totaling approximately 330 miles of new line.
Current permitting and pre-construction activities are focused on Segment E-8, the segment of line between the Hemingway substation and the Midpoint substation near Jerome, Idaho. In April 2026, Idaho Power and PacifiCorp filed a joint request that the IPUC grant both companies a CPCN for this segment of the line. Idaho Power is the majority owner of the approximately 133-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 remaining 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 a portion of this segment will be 2028 or later and the entire segment to be completed in 2030 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 a few segments of the project.
SWIP-N Transmission Line: In February 2025, Idaho Power entered into a commitment to become a partial owner of SWIP-N, a 285-mile high-voltage transmission line under construction 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 providing Idaho Power with 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 is obligated 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. In December 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. Construction of the project commenced in June 2026, and Idaho Power expects construction to be completed in 2028.
Pension Plan Contributions
Idaho Power has no minimum contribution to its pension plan required in 2026. During the nine months ended September 30, 2026, Idaho Power contributed $20 million in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions, as well as to mitigate the cost of being in an underfunded position. The primary impact of pension contributions is on the timing of cash flows, as the timing of cost recovery lags behind contributions.
Contractual Obligations
IDACORP’s and Idaho Power’s contractual cash obligations have not materially changed during the nine months ended September 30, 2026, except as disclosed in Note 5 – “Long-Term Debt” and Note 8 – “Commitments” to the condensed consolidated financial statements included in this report.
Dividends
The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems
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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.
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 condensed consolidated financial statements included in this report.
Off-Balance Sheet Arrangements
IDACORP's and Idaho Power's off-balance sheet arrangements have not changed materially from those reported in the MD&A in the 2025 Annual Report.
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 Federal Power Act, 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's most recent general rate case in Idaho was filed in 2025 and resolved by the 2025 Settlement Stipulation, which the IPUC approved in December 2025 for rates that went into effect for Idaho-jurisdiction customers on January 1, 2026. Previously, in 2024, Idaho Power filed a limited-issue rate case in Idaho (2024 Idaho Limited-Issue Rate Case), which the IPUC resolved through its order issued in December 2024 for rates that went into effect for Idaho-jurisdiction customers on January 1, 2025. In 2023, Idaho Power's general rate case in Idaho was resolved by the IPUC's approval of the 2023 Settlement Stipulation in December 2023 for rates that went into effect for Idaho-jurisdiction customers on January 1, 2024. Idaho Power's most recently concluded general rate case in Oregon was resolved by the OPUC's approval of settlement stipulations in September 2024 for rates that went into effect for Oregon-jurisdiction customers on October 15, 2024. Refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report for additional information relating to the 2025 Settlement Stipulation, 2024 Idaho Limited-Issue Rate Case, 2023 Idaho general rate case, and Oregon general rate case.
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.
The outcomes of significant proceedings are described in part in this report and further in the 2025 Annual Report. In addition to the discussion below, which includes notable regulatory developments since the discussion of these matters in the 2025 Annual Report, refer to Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report for additional information relating to Idaho Power's regulatory matters and recent regulatory filings and orders.
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Notable Retail Rate or Revenue Changes
During 2026, Idaho Power received orders authorizing the rate or revenue changes summarized in the table below.
| Description | Status | Estimated Impact(1) | Notes | |||||||||||||||||
| PCA - Idaho | New PCA rate became effective June 1, 2026 | $51.3 million PCA increase for the period from June 1, 2026 to May 31, 2027 | The income statement impact of revenue changes associated with the PCA mechanism is largely offset by associated increases and decreases in actual power supply costs and amortization of deferred power supply costs. The rate increase is primarily attributable to a decrease in forecast hydroelectric generation for the April 2026 to March 2027 forecast period. | |||||||||||||||||
| FCA - Idaho | New FCA rate became effective June 1, 2026 | $5.1 million FCA increase for the period from June 1, 2026 to May 31, 2027 | The FCA is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by partially separating (or decoupling) the recovery of fixed costs from the volumetric kilowatt-hour charge and instead linking it to a set amount per customer. | |||||||||||||||||
| APCU - Oregon | New APCU rate became effective June 1, 2026 | $0.7 million APCU increase for the period from June 1, 2026 to May 31, 2027 | The rate increase reflects a decrease in expected net power supply expense for the March 2026 forecast combined with an increase in normalized net power supply expense for the October 2025 update. | |||||||||||||||||
| PCAM - Oregon | New PCAM rate became effective June 1, 2026 | $1.9 million PCAM increase for the period from June 1, 2026 to May 31, 2027 | The Oregon power cost adjustment mechanism (PCAM) allows Idaho Power to recover or refund differences between actual net power supply costs and those included in rates, subject to applicable deadbands and an earnings test. The PCAM also includes the amortization of certain authorized deferrals. | |||||||||||||||||
(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.
Idaho Earnings Support and Sharing from Idaho Settlement Stipulations
The 2025 Settlement Stipulation, 2023 Settlement Stipulation, and 2018 Settlement Stipulation are each described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. IDACORP and Idaho Power believe that the terms allowing additional amortization of ADITC, subject to an annual cap of $55 million, in the settlement stipulations provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulations in effect. Based on its estimate of full-year 2026 Idaho ROE, for the three months and nine months ended September 30, 2026, Idaho Power recorded zero and $6.3 million, respectively, in additional ADITC amortization under the settlement stipulations.
Change in Deferred (Accrued) Net Power Supply Costs and the Power Cost Adjustment Mechanisms
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 variability 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 further in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.
With the exception of power supply expenses incurred under PURPA, expenses under export credit mechanisms, capital lease payments associated with battery energy storage systems, and certain demand response program costs that are passed through to customers substantially in full, the PCA mechanism allows Idaho Power to pass through to customers 95 percent of the differences in actual net power supply expenses as compared with base net power supply expenses, whether positive or negative. Thus, the primary financial statement impact of power supply cost deferrals or accruals is that the timing of when cash is paid out for power supply expenses differs from when those costs are recovered from customers, impacting operating cash flows from year to year.
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The following table summarizes the change in accrued net power supply costs (in millions of dollars).
| Idaho | Oregon | Total | ||||||||||||||||||
| Balance at December 31, 2025 | $ | (41.0) | $ | (1.4) | $ | (42.4) | ||||||||||||||
| Current period net power supply costs accrued | (38.0) | — | (38.0) | |||||||||||||||||
| Prior amounts refunded through rates | 50.4 | 0.4 | 50.8 | |||||||||||||||||
| Renewable energy credit sales | (38.1) | (1.5) | (39.6) | |||||||||||||||||
| Interest and other | (5.2) | (0.1) | (5.3) | |||||||||||||||||
Balance at September 30, 2026 | $ | (71.9) | $ | (2.6) | $ | (74.5) | ||||||||||||||
Open Access Transmission Tariff Posting
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 August 2026, Idaho Power filed its 2026 final transmission rate with the FERC, reflecting a transmission rate of $35.40 per kilowatt-year (kW-year), to be effective for the period from October 1, 2026, to September 30, 2027. Idaho Power's final rate was based on a net annual transmission revenue requirement of $162.6 million. The OATT rate in effect from October 1, 2025, to September 30, 2026, was $34.13 per kW-year based on a net annual transmission revenue requirement of $148.3 million. A kW-year is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours.
Resource Procurement Filings
In March 2026, Idaho Power filed an application with the IPUC for a CPCN for the South Hills Power Plant, a 222 MW natural gas-fueled facility to meet an identified capacity deficit in 2029, and a CPCN for the Peregrine Power Plant, a 430 MW natural gas-fueled facility to meet an identified capacity deficit in 2030, as well as confirmation and approval by the IPUC of AFUDC accrued for each of the projects prior to the issuance of a CPCN. As of the date of this report, the case remains pending.
In April 2026, Idaho Power and PacifiCorp filed a joint application with the IPUC to grant a CPCN to each of Idaho Power and PacifiCorp for Segment E-8 of GWW, an approximately 133-mile section of GWW jointly owned by Idaho Power and PacifiCorp that will run from the Midpoint substation near Jerome, Idaho, to the Hemingway substation near Boise, Idaho. As of the date of this report, the case remains pending.
In June 2026, Idaho Power filed an application with the IPUC for an order approving the 20-year PPA with Bluebird Solar Project LLC supplying up to 200 MW of output to Idaho Power and the 20-year energy storage system tolling agreement for 100 MW of dispatchable energy storage capacity. Both are expected to be in-service by June 2028. As of the date of this report, the case remains pending.
Large Contract Customer Rate Proceedings
In June 2026, Idaho Power filed an application with the IPUC for approval of a large contract for electric service for Chobani, LLC, at the Chobani food production facility located in Twin Falls, Idaho. As of the date of this report, the IPUC's decision is pending.
In September 2026, Idaho Power filed an application with the IPUC for approval of the third amendment to the contract for electric service between Idaho Power and a large contract customer, Brisbie, LLC (Brisbie), a wholly-owned subsidiary of Meta Platforms, Inc. The amendment provides for changes to better align Brisbie's obligations with the costs and risks associated with planning for and providing service to Brisbie's load while further protecting Idaho Power and its other customers from potential cost shifting. As of the date of this report, the IPUC's decision is pending.
Oregon Sale Regulatory Applications
In May 2026, Idaho Power and OTEC jointly filed an application with the OPUC to approve the Oregon Sale and its related territory allocation agreement. In June 2026, Idaho Power filed an application with the IPUC to approve the Oregon Sale and its related transition framework and agreement for supply of power and energy. In July 2026, Idaho Power filed an application with the FERC under Section 203 of the Federal Power Act to approve Idaho Power's sale of certain transmission assets to OTEC as part of the Oregon Sale, and FERC granted the application in October 2026. As of the date of this report, the cases with the OPUC and the IPUC remain pending.
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Relicensing of Hydropower Projects
HCC Relicensing: In connection with Idaho Power's major efforts to relicense the HCC, Idaho Power's largest hydropower complex, as described in more detail in the 2025 Annual Report in Part II, Item 7 - MD&A – "Liquidity and Capital Resources" and "Regulatory Matters," 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. The FERC issued a draft supplemental EIS in January 2026 and requested, and the USFWS and the NMFS initiated, formal consultation under section 7 of the ESA. In September 2026, the FERC issued the final supplemental EIS.
Relicensing costs of $568 million (including AFUDC) for the HCC were included in construction work in progress at September 30, 2026. 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 relicensing of the HCC project. Collecting these amounts currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of September 30, 2026, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $324 million.
As of the date of this report, Idaho Power believes issuance of a new HCC license by the FERC will be in 2027 or thereafter. Idaho Power is unable to predict the exact timing that the FERC will issue a new license or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with a new license. Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $35 million to $45 million until issuance of the license. Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial. In December 2025, as established by a previous IPUC order, Idaho Power filed an application with the IPUC requesting a determination, and in July 2026, the IPUC issued an order with its determination, that Idaho Power's expenditures from 2016 through 2025 on relicensing of the HCC were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding.
American Falls Relicensing: In February 2023, Idaho Power filed its final relicensing application with the FERC 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. 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.
Idaho Power's previous license at American Falls expired in February 2025 and was renewed automatically at that time and again in February 2026 for one year periods on the same terms and conditions as its prior license. The annual license is effective until February 28, 2027, and Idaho Power expects to continue with annual renewals automatically until the FERC issues a new license for the American Falls facility. As of the date of this report, Idaho Power expects FERC to issue a new license for the facility in 2027.
ENVIRONMENTAL MATTERS
Overview
Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act, 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 natural gas-fired power plants 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:
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•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.
Part I, Item 1 - "Business - Utility Operations - Environmental Regulation and Costs" in the 2025 Annual 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.
A summary of notable environmental matters (including conditions and events associated with climate change) impacting, or expected to potentially impact, IDACORP and Idaho Power is included in Part II, Item 7 - MD&A - "Environmental Matters" and MD&A - "Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs" in the 2025 Annual Report. Recent developments in certain environmental matters relevant to Idaho Power are described below.
EPA Regulatory Actions
In March 2025, the EPA announced a set of proposed regulatory actions relating to environmental laws and regulations, many of which may 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 Mercury and Air Toxics Standards (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. Each of the proposed rules described in the 2025 Annual Report or below is subject to public comment and remains pending as of the date of this report, except for the final rules described below.
Idaho Power will continue to actively monitor EPA's proposals and any other pending or potential environmental regulations related to environmental matters that may have an impact on its future 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
In June 2026, the EPA published a proposed rule that amends its procedures for implementing NEPA. For actions where the EPA is the NEPA lead agency, the proposed changes would create hard deadlines and page limits aimed at faster reviews, narrow the scope of analysis to reasonably foreseeable effects, expand the use of categorical exclusions, and allow sponsors (such as Idaho Power) to prepare NEPA documents themselves and pay fees to accelerate review timelines. If adopted as proposed, the rule could reduce the time required to develop future Idaho Power generation and transmission projects.
Clean Air Act Matters
Greenhouse Gas Endangerment Finding: In February 2026, the EPA finalized a rule rescinding the EPA's 2009 greenhouse gas endangerment finding. Idaho Power does not expect any near-term impact on its plans or operations as a result of the rescission of the endangerment finding but will continue to monitor any potential effects.
Mercury and Air Toxic Standards: In February 2026, the EPA finalized the repeal of 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. Idaho Power does not expect any near-term impact on its plans or operations as a result of the amendments to the MATS Rule but will continue to monitor any potential effects.
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Revisions to New Source Review: In May 2026, the EPA proposed revisions to the new source review (NSR) air permitting regulations to allow construction of non-emitting components or structures before issuance of an NSR air permit for a new major stationary source or major modification of an existing major stationary source. If adopted as proposed and subsequently implemented by the Idaho Department of Environmental Quality, the rule could reduce the time required for Idaho Power to bring new natural gas-fueled generation resources online.
Greenhouse Gas Standards for Fossil Fuel-Fired Power Plants: In September 2026, the EPA finalized a rule repealing the 2024 carbon capture and storage (CCS)-based standards under CAA Section 111 for new base load stationary combustion turbines and the emissions guidelines and standards for existing fossil fuel-fired steam electric generating units (EGUs). The final rule also retained the Phase 1 CO2 emission rate limits from the 2024 rule for new natural gas plants. Concurrently, the EPA issued a supplemental proposal to repeal all greenhouse gas (GHG) emission standards for fossil fuel-fired EGUs under CAA Section 111. Idaho Power does not expect the repeal of the 2024 CCS standards to have any near-term impact on its plans or operations, however the Phase 1 CO2 emission rate limits retained from the 2024 rule may impact emission rate limits for Idaho Power’s new natural gas-fired facilities. If the repeal of the GHG emission standards for fossil fuel-fired EGUs is finalized and becomes effective, it could simplify Idaho Power's compliance requirements with respect to both existing and new fossil fuel-fired EGUs.
Clean Water Act Matters
In September 2026, the EPA and the Army Corps of Engineers released a supplemental proposal to the original plan proposed in 2025 to define the "Waters of the United States" or WOTUS. This supplemental WOTUS proposal would narrow federal CWA jurisdiction by moving toward a perennial water standard to align with the Supreme Court’s 2023 Sackett v. Environmental Protection Agency decision. The proposal defines “relatively permanent” as perennial, meaning that for water to be considered WOTUS under the CWA, it must contain standing or continuously flowing water every day of the year under ordinary conditions. The proposal also narrows when wetlands are federally regulated, requiring perennial surface water in the wetland and a continuous surface-water connection to a jurisdictional water. Idaho Power does not expect that the proposed definition of WOTUS would alter how the CWA applies to most of Idaho Power's facilities, including its hydropower plants. As a result, Idaho Power does not expect the proposed definition, if implemented, to materially impact Idaho Power's operations or financial condition.
Endangered Species Act Matters
In July 2026, the USFWS and the NMFS finalized a rule that rescinded the definition of "harm" under the ESA in their respective regulations. In addition, in September 2026, USFWS and NMFS circulated internal memoranda interpreting “take” of a species under the ESA to require an affirmative act that’s deliberately directed at a given animal. The rescission of the definition of harm and the potential change in the interpretation of "take" may have the effect of reducing the applicability of the ESA for some Idaho Power projects, however, as of the date of this report, Idaho Power is unable to estimate the impact on Idaho Power of the changes.
Resource Conservation and Recovery Act Matters
In April 2026, the EPA published proposed rules to amend several provisions of the federal regulations governing the disposal of coal ash, also known as coal combustion residuals or CCR. The proposed rules are subject to public comment and remain pending as of the date of this report. If adopted as proposed, the proposed rules could simplify certain CCR requirements applicable to Idaho Power's jointly-owned facilities. However, given uncertainties regarding the proposed rule, Idaho Power is unable to estimate the impact on Idaho Power of the proposed rules.
Snake River Minimum Streamflow at Swan Falls
In June 2026, Idaho Power sent a letter to Idaho Governor Little acknowledging drought conditions impacting the historical Swan Falls Agreement regarding Idaho Power's water rights and the risk that the streamflow in the Snake River that the State is contractually required to maintain could drop below the minimum required level at Swan Falls. Idaho Power requested that the State and water users work collaboratively with Idaho Power to develop a long-term mitigation plan. In response, Governor Little directed the Idaho Water Resource Board to develop a long-term mitigation plan to ensure the State meets its minimum streamflow obligations. The Water Resource Board has begun work to develop a long-term mitigation plan in consultation with relevant stakeholders, including Idaho Power. To the extent that drought conditions and reduced Snake River streamflows at Swan Falls persist, this will generally reduce the amount of water available to Idaho Power for hydropower production.
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OTHER MATTERS
Critical Accounting Policies and Estimates
IDACORP's and Idaho Power's discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires IDACORP and Idaho Power to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and Idaho Power evaluate these estimates, including those estimates related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled receivables, and the allowance for uncollectible accounts. These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate.
IDACORP’s and Idaho Power’s critical accounting policies are reviewed by the audit committees of the boards of directors. These policies have not changed materially from the discussion of those policies included under "Critical Accounting Policies and Estimates" in the 2025 Annual Report.
Recently Issued Accounting Pronouncements
For discussion of new and recently adopted accounting pronouncements, see Note 1 - "Summary of Significant Accounting Policies" to the condensed consolidated financial statements included in this report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IDACORP is exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes material changes in these risks since December 31, 2025, 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 September 30, 2026. IDACORP has not entered into any of these market-risk-sensitive instruments for speculative purposes.
Interest Rate Risk
IDACORP manages interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.
Variable Rate Debt: As of September 30, 2026, IDACORP had no variable rate debt.
Fixed Rate Debt: As of September 30, 2026, IDACORP had $3.9 billion in fixed rate debt, with a fair value of approximately $3.4 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $379 million if market interest rates were to decline by one percentage point from their September 30, 2026 levels.
Commodity Price Risk
IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These changes in commodity prices are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. To supplement its supply resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. IDACORP's commodity price risk as of September 30, 2026, had not changed materially from that reported in Item 7A of the 2025 Annual Report. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 11 - "Derivative Financial Instruments" to the condensed consolidated financial statements included in this report.
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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 September 30, 2026, Idaho Power posted $48 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 September 30, 2026, the amount of additional collateral that could have been requested upon a downgrade to below investment grade was approximately $37 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.
IDACORP's credit risk related to uncollectible accounts, net of amounts reserved, as of September 30, 2026, had not changed materially from that reported in Item 7A of the 2025 Annual Report, except as disclosed in Note 4 - "Revenues" to the condensed consolidated financial statements included in this report. Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note 11 - "Derivative Financial Instruments" to the condensed consolidated financial statements included in this report.
Equity Price Risk
IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's 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 the 2025 Annual Report.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
IDACORP: The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (pursuant to Rule 13a-15(b) of the Exchange Act) as of September 30, 2026, have concluded that IDACORP’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) are effective as of that date.
Idaho Power: The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (pursuant to Rule 13a-15(b) of the Exchange Act) as of September 30, 2026, have concluded that Idaho Power’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) are effective as of that date.
Changes in Internal Control over Financial Reporting
There have been no changes in IDACORP's or Idaho Power's internal control over financial reporting during the quarter ended September 30, 2026, that have materially affected, or are reasonably likely to materially affect, IDACORP's or Idaho Power's internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Refer to Note 9 – “Contingencies” to the condensed consolidated financial statements included in this report. SEC regulations require IDACORP and Idaho Power to disclose certain information about proceedings arising under federal, state or local environmental provisions if the companies reasonably believe that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to the SEC regulations, the companies use a threshold of $1 million or more for purposes of determining whether disclosure of any such proceedings is required.
ITEM 1A. RISK FACTORS
The factors discussed in Part I - Item 1A - "Risk Factors" in the 2025 Annual Report, could materially affect IDACORP’s and Idaho Power's business, financial condition, or future results. In addition to those risk factors and other risks discussed in this report, see "Cautionary Note Regarding Forward-Looking Statements" in this report for additional factors that could have a significant impact on IDACORP's or Idaho Power's operations, results of operations, or financial condition and could cause actual results to differ materially from those anticipated in forward-looking statements.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Restrictions on Dividends
See Note 6 - "Common Stock" to the condensed consolidated financial statements included in this report for a description of restrictions on IDACORP's and Idaho Power's payment of dividends.
Issuer Purchases of Equity Securities
IDACORP did not repurchase any shares of its common stock during the quarter ended September 30, 2026.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
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.
ITEM 5. OTHER INFORMATION
During the quarter ended September 30, 2026, none of IDACORP's or Idaho Power's directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted terminated
65
ITEM 6. EXHIBITS
The following exhibits are filed or furnished, as applicable, with the Quarterly Report on Form 10-Q for the quarter ended September 30, 2026:
| Incorporated by Reference | ||||||||||||||||||||
| Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith | ||||||||||||||
| 15.1 | X | |||||||||||||||||||
| 15.2 | X | |||||||||||||||||||
| 31.1 | X | |||||||||||||||||||
| 31.2 | X | |||||||||||||||||||
| 31.3 | X | |||||||||||||||||||
| 31.4 | X | |||||||||||||||||||
| 32.1 | X | |||||||||||||||||||
| 32.2 | X | |||||||||||||||||||
| 32.3 | X | |||||||||||||||||||
| 32.4 | X | |||||||||||||||||||
| 95.1 | X | |||||||||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document | X | ||||||||||||||||||
| 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 | ||||||||||||||||||
66
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
| IDACORP, INC. | |||||||||||
| (Registrant) | |||||||||||
| Date: | October 29, 2026 | By: | /s/ Lisa A. Grow | ||||||||
| Lisa A. Grow | |||||||||||
| President and Chief Executive Officer | |||||||||||
| Date: | October 29, 2026 | By: | /s/ Brian R. Buckham | ||||||||
| Brian R. Buckham | |||||||||||
| Executive Vice President, Chief Financial Officer, and Treasurer | |||||||||||
| IDAHO POWER COMPANY | |||||||||||
| (Registrant) | |||||||||||
| Date: | October 29, 2026 | By: | /s/ Lisa A. Grow | ||||||||
| Lisa A. Grow | |||||||||||
| President and Chief Executive Officer | |||||||||||
| Date: | October 29, 2026 | By: | /s/ Brian R. Buckham | ||||||||
| Brian R. Buckham | |||||||||||
| Executive Vice President, Chief Financial Officer, and Treasurer | |||||||||||
67
Exhibit 15.1
October 29, 2026
The Board of Directors and Shareholders of IDACORP, Inc.
1221 W. Idaho Street
Boise, Idaho 83702
We are aware that our report dated October 29, 2026, on our review of the interim financial information of IDACORP, Inc. appearing in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2026, is incorporated by reference in Registration Statement Nos. 333-287573, 333-125259 and 333-159855 on Form S-8 and Registration Statement Nos. 333-275318 and 333-285140 on Form S-3.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
Exhibit 15.2
October 29, 2026
The Board of Directors and Shareholder of Idaho Power Company
1221 W. Idaho Street
Boise, Idaho 83702
We are aware that our report dated October 29, 2026, on our review of the interim financial information of Idaho Power Company appearing in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2026, is incorporated by reference in Registration Statement No. 333-66496 on Form S-8 and Registration Statement No. 333-285140-01 on Form S-3.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
Exhibit 31.1
CERTIFICATION
I, Lisa A. Grow, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| Date: | October 29, 2026 | By: | /s/ Lisa A. Grow | ||||||||
| Lisa A. Grow | |||||||||||
| President and Chief Executive Officer | |||||||||||
Exhibit 31.2
CERTIFICATION
I, Brian R. Buckham, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| Date: | October 29, 2026 | By: | /s/ Brian R. Buckham | ||||||||
| Brian R. Buckham | |||||||||||
| Executive Vice President, Chief Financial Officer, and Treasurer | |||||||||||
Exhibit 31.3
CERTIFICATION
I, Lisa A. Grow, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| Date: | October 29, 2026 | By: | /s/ Lisa A. Grow | ||||||||
| Lisa A. Grow | |||||||||||
| President and Chief Executive Officer | |||||||||||
Exhibit 31.4
CERTIFICATION
I, Brian R. Buckham, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| Date: | October 29, 2026 | By: | /s/ Brian R. Buckham | ||||||||
| Brian R. Buckham | |||||||||||
| Executive Vice President, Chief Financial Officer, and Treasurer | |||||||||||
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2026 (the "Report"), I, Lisa A. Grow, President and Chief Executive Officer of the Company, certify that:
(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
| /s/ Lisa A. Grow | ||
| Lisa A. Grow | ||
| President and Chief Executive Officer | ||
| October 29, 2026 | ||
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2026 (the "Report"), I, Brian R. Buckham, Executive Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:
(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
| /s/ Brian R. Buckham | ||
| Brian R. Buckham | ||
| Executive Vice President, Chief Financial Officer, and Treasurer | ||
| October 29, 2026 | ||
Exhibit 32.3
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2026 (the "Report"), I, Lisa A. Grow, President and Chief Executive Officer of the Company, certify that:
(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
| /s/ Lisa A. Grow | ||
| Lisa A. Grow | ||
| President and Chief Executive Officer | ||
| October 29, 2026 | ||
Exhibit 32.4
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2026 (the "Report"), I, Brian R. Buckham, Executive Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:
(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
| /s/ Brian R. Buckham | ||
| Brian R. Buckham | ||
| Executive Vice President, Chief Financial Officer, and Treasurer | ||
| October 29, 2026 | ||
Exhibit 95.1
Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act
Idaho Power is the parent company of Idaho Energy Resources Co. (IERCo), a joint-owner of Bridger Coal Company (BCC), which mines coal at the Bridger Coal Mine and processing facility (Mine) near Rock Springs, Wyoming. IERCo owns a one-third interest in BCC. The Mine is comprised of the Bridger surface operations. Underground operations are no longer conducted. Day-to-day operation and management of coal mining and processing operations at the Mine are conducted through BCC's joint owner. Operation of the Mine is regulated by the Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). MSHA inspects the Mine on a regular basis and may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act. Monetary penalties are assessed by MSHA for citations. The severity and assessment of penalties may be reduced or, in some cases, dismissed through the contest and appeal process. Amounts are reported regardless of whether BCC has challenged or appealed the matter.
The table below summarizes the number of citations, notices, and orders issued, and penalties assessed, by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other data for the Mine, during the three-month period ended September 30, 2026. Legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC) are as of September 30, 2026. Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by MSHA at www.msha.gov.
| Three-month period ended September 30, 2026 | |||||||||||||||||
| (unaudited) | |||||||||||||||||
| Surface Mine (MSHA ID No. 4800677) | |||||||||||||||||
| Mine Safety Act Citations and Orders: | |||||||||||||||||
Section 104(a) Significant & Substantial Citations (1) | – | ||||||||||||||||
Section 104(b) Orders (2) | – | ||||||||||||||||
Section 104(d) Citations & Orders (3) | – | ||||||||||||||||
Section 107(a) Imminent Danger Orders (4) | – | ||||||||||||||||
| Total Value of Proposed MSHA Assessments (in thousands) | $ | – | |||||||||||||||
| Legal Actions Pending | – | ||||||||||||||||
| Legal Actions Issued During Period | – | ||||||||||||||||
| Legal Actions Closed During Period | 1 | ||||||||||||||||
| Number of Fatalities | – | ||||||||||||||||
| _________________ | |||||||||||||||||
(1) For alleged violation of a mandatory health or safety standard or regulation that could significantly and substantially contribute to the cause and effect of a safety or health hazard under Section 104 of the Mine Safety Act. | |||||||||||||||||
(2) For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended. | |||||||||||||||||
(3) For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation. | |||||||||||||||||
(4) The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated. | |||||||||||||||||
For the three-month period ended September 30, 2026, the Mine did not receive written notice from MSHA of (i) a flagrant violation under Section 110(b)(2) of the Mine Safety Act; (ii) a pattern of violations of mandatory health or safety standards that are of such a nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Safety Act; or (iii) the potential to have such a pattern.