# EDGAR Filing Document

**Accession Number:** 0000049648
**File Stem:** 0001057877-25-000082
**Filing Date:** 2025-10
**Character Count:** 351951
**Document Hash:** 9cce3562f9d884891add72fd35bfe841
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001057877-25-000082.hdr.sgml**: 20251030

**ACCESSION NUMBER**: 0001057877-25-000082

**CONFORMED SUBMISSION TYPE**: 10-Q

**PUBLIC DOCUMENT COUNT**: 90

**CONFORMED PERIOD OF REPORT**: 20250930

**FILED AS OF DATE**: 20251030

**DATE AS OF CHANGE**: 20251030

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** IDACORP INC
- **CENTRAL INDEX KEY:** 0001057877
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 820505802
- **STATE OF INCORPORATION:** ID
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-Q
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-14465
- **FILM NUMBER:** 251432311

**BUSINESS ADDRESS:**
- **STREET 1:** 1221 WEST IDAHO STREET
- **CITY:** BOISE
- **STATE:** ID
- **ZIP:** 83702-5627
- **BUSINESS PHONE:** 2083882200

**MAIL ADDRESS:**
- **STREET 1:** PO BOX 70
- **STREET 2:** 1221 WEST IDAHO STREET
- **CITY:** BOISE
- **STATE:** ID
- **ZIP:** 83702-5627
**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** IDAHO POWER CO
- **CENTRAL INDEX KEY:** 0000049648
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 820130980
- **STATE OF INCORPORATION:** ID
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-Q
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-03198
- **FILM NUMBER:** 251432312

**BUSINESS ADDRESS:**
- **STREET 1:** 1221 W IDAHO ST
- **STREET 2:** PO BOX 70
- **CITY:** BOISE
- **STATE:** ID
- **ZIP:** 83702
- **BUSINESS PHONE:** 2083882200

**MAIL ADDRESS:**
- **STREET 1:** PO BOX 70
- **STREET 2:** 1221 W IDAHO STREET
- **CITY:** BOISE
- **STATE:** ID
- **ZIP:** 83702-5627

?xml version='1.0' encoding='ASCII'? ida-20250930

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**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 | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
|  | EXCHANGE ACT OF 1934 | EXCHANGE ACT OF 1934 | EXCHANGE ACT OF 1934 |
|  | For the quarterly period ended | September 30, 2025 |  |
|  | OR | OR | OR |
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
|  | EXCHANGE ACT OF 1934 | EXCHANGE ACT OF 1934 | EXCHANGE ACT OF 1934 |
|  | For the transition period from __________ to __________ | For the transition period from __________ to __________ | For the transition period from __________ to __________ |
|  |  | Exact name of registrants as specified | I.R.S. Employer |
| Commission File | Commission File | in their charters, address of principal | Identification |
| Number | Number | executive offices, zip code and telephone number | No. |
| 1-14465 | 1-14465 | **IDACORP, Inc.** | 82-0505802 |
| 1-3198 | 1-3198 | **Idaho Power Company** | 82-0130980 |

---

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| | | | |
|:---|:---|:---|:---|
| 1221 W. Idaho Street | 1221 W. Idaho Street | 1221 W. Idaho Street | 1221 W. Idaho Street |
| Boise, | ID | ID | 83702-5627 |
| (208) | (208) | 388-2200 | 388-2200 |

---

---

| | | |
|:---|:---|:---|
| | State of Incorporation: | Idaho |
| Former name, former address and former fiscal year, if changed since last report | Former name, former address and former fiscal year, if changed since last report | 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 <br> <u>Common Stock</u> <u>IDA</u> <u>New York Stock Exchange</u>

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.: Yes ☒ No ☐ Idaho Power Company: Yes ☒ 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.: Yes ☒ No ☐ Idaho Power Company: Yes ☒ No ☐

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Large accelerated filer | Accelerated filer | Non-accelerated filer | Smaller reporting company | Emerging growth company |
| IDACORP, Inc.: | ☒ | ☐ | ☐ | ☐ | ☐ |
| Idaho Power Company: | ☐ | ☐ | ☒ | ☐ | ☐ |

---

If an emerging growth company, indicate by check mark if the 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

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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 24, 2025:

IDACORP, Inc.: 54,045,224 Idaho Power Company: 39,150,812, all held by IDACORP, Inc.

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** | **TABLE OF CONTENTS** | **TABLE OF CONTENTS** | **TABLE OF CONTENTS** | **TABLE OF CONTENTS** |
| | | | | <u>Page</u> |
| Commonly Used Terms | Commonly Used Terms | Commonly Used Terms | Commonly Used Terms | <u>[4](#i2f2a0092f8b2400b80bef884b6bddd41_13)</u> |
| Cautionary Note Regarding Forward-Looking Statements | Cautionary Note Regarding Forward-Looking Statements | Cautionary Note Regarding Forward-Looking Statements | Cautionary Note Regarding Forward-Looking Statements | <u>[5](#i2f2a0092f8b2400b80bef884b6bddd41_16)</u> |
| Available Information | Available Information | Available Information | Available Information | <u>[7](#i2f2a0092f8b2400b80bef884b6bddd41_19)</u> |
| Part I. Financial Information | Part I. Financial Information | Part I. Financial Information | Part I. Financial Information | |
| | Item 1. Financial Statements (unaudited) | Item 1. Financial Statements (unaudited) | Item 1. Financial Statements (unaudited) | |
| | | IDACORP, Inc.: | IDACORP, Inc.: | |
| | | | Condensed Consolidated Statements of Income | <u>[8](#i2f2a0092f8b2400b80bef884b6bddd41_31)</u> |
| | | | Condensed Consolidated Statements of Comprehensive Income | <u>[9](#i2f2a0092f8b2400b80bef884b6bddd41_34)</u> |
| | | | Condensed Consolidated Balance Sheets | <u>[10](#i2f2a0092f8b2400b80bef884b6bddd41_37)</u> |
| | | | Condensed Consolidated Statements of Cash Flows | <u>[12](#i2f2a0092f8b2400b80bef884b6bddd41_40)</u> |
| | | | Condensed Consolidated Statements of Equity | <u>[13](#i2f2a0092f8b2400b80bef884b6bddd41_43)</u> |
| | | Idaho Power Company: | Idaho Power Company: | |
| | | | Condensed Consolidated Statements of Income | <u>[14](#i2f2a0092f8b2400b80bef884b6bddd41_49)</u> |
| | | | Condensed Consolidated Statements of Comprehensive Income | <u>[15](#i2f2a0092f8b2400b80bef884b6bddd41_52)</u> |
| | | | Condensed Consolidated Balance Sheets | <u>[16](#i2f2a0092f8b2400b80bef884b6bddd41_55)</u> |
| | | | Condensed Consolidated Statements of Cash Flows | <u>[18](#i2f2a0092f8b2400b80bef884b6bddd41_58)</u> |
| | | Notes to Condensed Consolidated Financial Statements | Notes to Condensed Consolidated Financial Statements | <u>[19](#i2f2a0092f8b2400b80bef884b6bddd41_61)</u> |
| | | Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP | Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP | <u>[40](#i2f2a0092f8b2400b80bef884b6bddd41_118)</u> |
| | Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | <u>[42](#i2f2a0092f8b2400b80bef884b6bddd41_121)</u> |
| | Item 3. Quantitative and Qualitative Disclosures About Market Risk | Item 3. Quantitative and Qualitative Disclosures About Market Risk | Item 3. Quantitative and Qualitative Disclosures About Market Risk | <u>[66](#i2f2a0092f8b2400b80bef884b6bddd41_142)</u> |
| | Item 4. Controls and Procedures | Item 4. Controls and Procedures | Item 4. Controls and Procedures | <u>[67](#i2f2a0092f8b2400b80bef884b6bddd41_145)</u> |
| Part II. Other Information | Part II. Other Information | Part II. Other Information | Part II. Other Information | |
| | Item 1. Legal Proceedings | Item 1. Legal Proceedings | Item 1. Legal Proceedings | <u>[68](#i2f2a0092f8b2400b80bef884b6bddd41_151)</u> |
| | Item 1A. Risk Factors | Item 1A. Risk Factors | Item 1A. Risk Factors | <u>[68](#i2f2a0092f8b2400b80bef884b6bddd41_154)</u> |
| | Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | <u>[68](#i2f2a0092f8b2400b80bef884b6bddd41_157)</u> |
| | Item 3. Defaults Upon Senior Securities | Item 3. Defaults Upon Senior Securities | Item 3. Defaults Upon Senior Securities | <u>[68](#i2f2a0092f8b2400b80bef884b6bddd41_160)</u> |
| | Item 4. Mine Safety Disclosures | Item 4. Mine Safety Disclosures | Item 4. Mine Safety Disclosures | <u>[68](#i2f2a0092f8b2400b80bef884b6bddd41_163)</u> |
| | Item 5. Other Information | Item 5. Other Information | Item 5. Other Information | <u>[68](#i2f2a0092f8b2400b80bef884b6bddd41_166)</u> |
| | Item 6. Exhibits | Item 6. Exhibits | Item 6. Exhibits | <u>[69](#i2f2a0092f8b2400b80bef884b6bddd41_169)</u> |
| Signatures | Signatures | Signatures | Signatures | <u>[70](#i2f2a0092f8b2400b80bef884b6bddd41_172)</u> |

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| | | | |
|:---|:---|:---|:---|
| **COMMONLY USED TERMS** | **COMMONLY USED TERMS** | **COMMONLY USED TERMS** | **COMMONLY USED TERMS** |
| The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report: | The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report: | The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report: | 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 | Idaho ROE | Idaho-jurisdiction return on year-end equity |
| 2023 Settlement Stipulation | The settlement stipulation for Idaho Power's 2023 Idaho general rate case | Ida-West | Ida-West Energy Company, a subsidiary of IDACORP, Inc. |
| 2024 Annual Report | IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended<br>December 31, 2024 | IERCo | Idaho Energy Resources Co., a subsidiary of Idaho Power Company |
| 2024 Idaho Limited-Issue Rate Case | A limited-issue rate case Idaho Power filed with the IPUC finalized by order of the IPUC in December 2024 | IFS | IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc. |
| 2025 Settlement Stipulation | The settlement stipulation for Idaho Power's 2025 Idaho general rate case | IPUC | Idaho Public Utilities Commission |
| ADITC | Accumulated Deferred Investment Tax Credits | IRP | Integrated Resource Plan |
| AFUDC | Allowance for Funds Used During Construction | Jim Bridger plant | Jim Bridger power plant |
| AOCI | Accumulated Other Comprehensive Income | MD&A | Management's Discussion and Analysis of Financial Condition and Results of Operations |
| APCU | Annual power cost update | MMBtu | Million British Thermal Units |
| ASU | Accounting Standards Update | MW | Megawatt |
| ATM | At-the-market offering program | MWh | Megawatt-hour |
| B2H | Boardman-to-Hemingway, a high-voltage transmission line project | NAV | Net asset value |
| BCC | Bridger Coal Company, a jointly-owned investment of IERCo | NEPA | National Environmental Policy Act |
| CPCN | Certificate of Public Convenience and Necessity | North Valmy plant | Idaho Power's jointly-owned generating plant in Valmy, Nevada |
| CWA | Clean Water Act | O&M | Operations and Maintenance |
| EPA | U.S. Environmental Protection Agency | OPUC | Public Utility Commission of Oregon |
| ESA | Endangered Species Act | PCA | Idaho-jurisdiction Power Cost Adjustment |
| Exchange Act | U.S. Securities Exchange Act of 1934, as amended | PPA | Power purchase agreement |
| FCA | Idaho Fixed Cost Adjustment | PURPA | Public Utility Regulatory Policies Act of 1978, as amended |
| FERC | Federal Energy Regulatory Commission | RFP | Request for proposals |
| FSA | Forward sale agreement | SEC | U.S. Securities and Exchange Commission |
| GAAP | Accounting principles generally accepted in the United States of America | SMSP | Security Plans for Senior Management Employees I and II |
| GWW | Gateway West, a high-voltage transmission line project | SWIP-N | Southwest Intertie Project-North, a planned high-voltage transmission line |
| HCC | Hells Canyon Complex, composed of the Brownlee, Oxbow, and Hells Canyon facilities | WMP | Wildfire Mitigation Plan |
| IDACORP | IDACORP, Inc., an Idaho corporation | WPSC | Wyoming Public Service Commission |
| Idaho Power | Idaho Power Company, an Idaho corporation |  |  |

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<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**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 2024 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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes to or the elimination of Idaho Power's regulatory cost recovery mechanisms;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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 or other factors, or that may not be deemed prudent by regulators for cost recovery or return on investment;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• expenses and risks associated with supplier and contractor delays and failure to satisfy project quality and performance standards on utility infrastructure projects, including as a result of tariffs and permitting requirements and limitations, and the potential impacts of those delays and failures on Idaho Power's ability to serve customers and generate revenues;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the rapid addition of new industrial and commercial customer load and the volatility and timing of such new load demand, resulting in increased risks and costs of power demand potentially exceeding available supply;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the potential financial impacts of industrial customers not meeting forecasted power usage ramp rates or volumes;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• impacts of economic conditions, including an inflationary or recessionary environment and interest rates, on items such as operations and capital investments, supply costs and delivery delays, supply scarcity and shortages, population growth or decline in Idaho Power's service area, changes in customer demand for electricity, revenue from sales of excess power, credit quality of counterparties and suppliers and their ability to meet financial and operational commitments and on the timing and extent of counterparties' power usage, and collection of receivables;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, and the associated impacts on loads and load growth;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in, failure to comply with, and costs of compliance with laws, regulations, policies, orders, and licenses, which may result in penalties and fines, increase compliance and operational costs, and impact recovery associated with increased costs through rates;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River Basin, which may impact the amount of power generated by Idaho Power's hydropower facilities and power supply costs;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• accidents, electrical contacts, fires (either affecting or caused by Idaho Power facilities or infrastructure), explosions, infrastructure failures, general system damage or dysfunction, and other unplanned events that may occur while operating and maintaining assets, which can cause unplanned outages; reduce generating output; damage company assets, operations, or reputation; subject Idaho Power to third-party claims for property damage, personal injury, or loss of life; or result in the imposition of fines and penalties;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Idaho Power's concentration in one region, and the resulting exposure to regional economic conditions and regional legislation and regulation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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 Idaho, Oregon, or Wyoming public utility commissions, and the companies' past or projected financial performance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in actuarial assumptions, changes in interest rates, increasing health care costs, and the actual and projected return on plan assets for pension and other postretirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities and the companies' cash flows;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• remediation costs associated with planned cessation of coal-fired operations at Idaho Power's co-owned coal plants and conversion of the plants to natural gas;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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 and for complying with their disclosure obligations under Regulation FD. Therefore, IDACORP and Idaho Power encourage investors, the media, and others interested in the companies to review the information the companies make available through such channels. 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.

Investors, the media, and others interested in IDACORP and Idaho Power may also wish to refer to the websites of the IPUC and OPUC at puc.idaho.gov and oregon.gov/puc, respectively, to review documents filed by IDACORP, Idaho Power, and third parties with, and issued by, the respective commissions. No information on the IPUC and OPUC websites is incorporated by reference into this report or into IDACORP's or Idaho Power's other SEC filings.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**PART I – FINANCIAL INFORMATION**

**ITEM 1. FINANCIAL STATEMENTS**

**IDACORP, Inc.**

**Condensed Consolidated Statements of Income**

**(unaudited)**

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| | **(in thousands, except per share amounts)** | **(in thousands, except per share amounts)** | **(in thousands, except per share amounts)** | **(in thousands, except per share amounts)** |
| **Operating Revenues:** |  |  |  |  |
| Electric utility revenues | $523549 | $527487 | $1405173 | $1425606 |
| Other | 868 | 1040 | 2581 | 2896 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating revenues | 524417 | 528527 | 1407754 | 1428502 |
| **Operating Expenses:** |  |  |  |  |
| Electric utility: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Purchased power | 121276 | 114578 | 284163 | 321860 |
| &nbsp;&nbsp;&nbsp;Fuel expense | 74992 | 73471 | 179238 | 188411 |
| &nbsp;&nbsp;&nbsp;Power cost adjustment | (18295) | 20779 | 57967 | 102297 |
| &nbsp;&nbsp;&nbsp;Other operations and maintenance | 120398 | 116168 | 355371 | 332900 |
| &nbsp;&nbsp;&nbsp;Energy efficiency programs | 7460 | 5283 | 18808 | 16699 |
| &nbsp;&nbsp;&nbsp;Depreciation and amortization | 64493 | 56388 | 185407 | 165133 |
| &nbsp;&nbsp;&nbsp;Other electric utility operating expenses, net | 8112 | 7453 | 24053 | 12482 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric utility operating expenses | 378436 | 394120 | 1105007 | 1139782 |
| Other | 1160 | 698 | 2424 | 2145 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating expenses | 379596 | 394818 | 1107431 | 1141927 |
| **Operating Income** | 144821 | 133709 | 300323 | 286575 |
| **Nonoperating (Income) Expense:** |  |  |  |  |
| Allowance for equity funds used during construction | (15569) | (15179) | (45177) | (39610) |
| Earnings of unconsolidated equity-method investments | (2185) | (1978) | (4208) | (3880) |
| Interest on long-term debt and finance leases | 46244 | 35432 | 128733 | 102048 |
| Other interest | 7847 | 6353 | 21696 | 17895 |
| Allowance for borrowed funds used during construction | (9207) | (7639) | (26075) | (20518) |
| Other income, net | (14604) | (13478) | (43582) | (40188) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total nonoperating expense, net | 12526 | 3511 | 31387 | 15747 |
| **Income Before Income Taxes** | 132295 | 130198 | 268936 | 270828 |
| **Income Tax Expense (Benefit)** | 7686 | 16358 | (11460) | 18876 |
| **Net Income** | 124609 | 113840 | 280396 | 251952 |
| &nbsp;&nbsp;&nbsp;Income attributable to noncontrolling interests | (172) | (235) | (531) | (654) |
| **Net Income Attributable to IDACORP, Inc.** | $124437 | $113605 | $279865 | $251298 |
| Weighted Average Common Shares Outstanding - Basic | 54172 | 53386 | 54147 | 52112 |
| Weighted Average Common Shares Outstanding - Diluted | 55055 | 53485 | 54522 | 52179 |
| **Earnings Per Share of Common Stock:** |  |  |  |  |
| Earnings Attributable to IDACORP, Inc. - Basic | $2.30 | $2.13 | $5.17 | $4.82 |
| Earnings Attributable to IDACORP, Inc. - Diluted | $2.26 | $2.12 | $5.13 | $4.82 |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**IDACORP, Inc.**

**Condensed Consolidated Statements of Comprehensive Income**

**(unaudited)**

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| | **(in thousands)** | **(in thousands)** | **(in thousands)** | **(in thousands)** |
| **Net Income** | $124609 | $113840 | $280396 | $251952 |
| **Other Comprehensive Income:** |  |  |  |  |
| Unfunded pension liability adjustment, net of tax of $57, $99, $302, and $296, respectively  | 171 | 285 | 282 | 853 |
| **Total Comprehensive Income** | 124780 | 114125 | 280678 | 252805 |
| Comprehensive Income attributable to noncontrolling interests | (172) | (235) | (531) | (654) |
| **Comprehensive Income Attributable to IDACORP, Inc.** | $124608 | $113890 | $280147 | $252151 |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**IDACORP, Inc.**

**Condensed Consolidated Balance Sheets**

**(unaudited)**

---

| | | |
|:---|:---|:---|
| | **September 30,<br>2025** | **December 31,<br>2024** |
| | **(in thousands)** | **(in thousands)** |
| **Assets** | | |
| **Current Assets:** | | |
| Cash and cash equivalents | $333209 | $368865 |
| Receivables: |  |  |
| &nbsp;&nbsp;Customer (net of allowance of $4,341 and $5,071, respectively) | 139079 | 114824 |
| &nbsp;&nbsp;Other (net of allowance of $703 and $628, respectively) | 49016 | 29627 |
| Income taxes receivable |  | 13932 |
| Accrued unbilled receivables | 90582 | 97711 |
| Materials and supplies (at average cost) | 207103 | 201064 |
| Fuel stock (at average cost) | 29858 | 43656 |
| Prepayments | 30651 | 29461 |
| Current regulatory assets | 80803 | 89315 |
| Other | 104 |  |
| &nbsp;&nbsp;&nbsp;Total current assets | 960405 | 988455 |
| **Investments** | 154896 | 161340 |
| **Property, Plant and Equipment:** |  |  |
| Utility plant in service | 8333801 | 7957763 |
| Accumulated provision for depreciation | (2837096) | (2714706) |
| &nbsp;&nbsp;&nbsp;Utility plant in service - net | 5496705 | 5243057 |
| Construction work in progress | 1619882 | 1244559 |
| Finance lease right-of-use assets | 222445 |  |
| Utility plant held for future use | 19281 | 13211 |
| Other property, net of accumulated depreciation | 16678 | 16491 |
| &nbsp;&nbsp;&nbsp;Property, plant and equipment - net | 7374991 | 6517318 |
| **Other Assets:** |  |  |
| Company-owned life insurance | 101696 | 92062 |
| Regulatory assets | 1429218 | 1418057 |
| Other | 54779 | 62131 |
| &nbsp;&nbsp;&nbsp;Total other assets | 1585693 | 1572250 |
| **Total** | $10075985 | $9239363 |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**IDACORP, Inc.**

**Condensed Consolidated Balance Sheets**

**(unaudited)**

---

| | | |
|:---|:---|:---|
| | **September 30,<br>2025** | **December 31,<br>2024** |
| | **(in thousands)** | **(in thousands)** |
| **Liabilities and Equity** | | |
| **Current Liabilities:** | | |
| Current maturities of long-term debt | $116300 | $19885 |
| Accounts payable | 317375 | 307133 |
| Taxes accrued | 45617 | 6981 |
| Interest accrued | 36586 | 42681 |
| Accrued compensation | 74782 | 70548 |
| Current regulatory liabilities | 40974 | 7523 |
| Advances from customers | 185620 | 165229 |
| Other | 67941 | 80821 |
| &nbsp;&nbsp;&nbsp;Total current liabilities | 885195 | 700801 |
| **Other Liabilities:** |  |  |
| Deferred income taxes | 780060 | 822231 |
| Regulatory liabilities | 1009989 | 976803 |
| Pension and other postretirement benefits | 161247 | 165992 |
| Finance lease liabilities | 218182 |  |
| Other | 201945 | 181804 |
| &nbsp;&nbsp;&nbsp;Total other liabilities | 2371423 | 2146830 |
| **Long-Term Debt** | 3330752 | 3053777 |
| **Commitments and Contingencies** |  |  |
| **Equity:** |  |  |
| IDACORP, Inc. shareholders' equity: |  |  |
|  Common stock, no par value (120,000 shares authorized; 54,045 and 53,962 shares issued and outstanding, respectively) | 1205219 | 1194998 |
| &nbsp;&nbsp;&nbsp;Retained earnings | 2289174 | 2149548 |
| &nbsp;&nbsp;&nbsp;Accumulated other comprehensive loss | (13310) | (13592) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total IDACORP, Inc. shareholders' equity | 3481083 | 3330954 |
| Noncontrolling interests | 7532 | 7001 |
| &nbsp;&nbsp;&nbsp;Total equity | 3488615 | 3337955 |
| **Total** | $10075985 | $9239363 |
| The accompanying notes are an integral part of these statements. | The accompanying notes are an integral part of these statements. | The accompanying notes are an integral part of these statements. |

---

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**IDACORP, Inc.**

**Condensed Consolidated Statements of Cash Flows**

**(unaudited)**

---

| | | |
|:---|:---|:---|
| | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** |
| | **(in thousands)** | **(in thousands)** |
| **Operating Activities:** |  |  |
| Net income | $280396 | $251952 |
| Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
| &nbsp;&nbsp;&nbsp;Depreciation and amortization | 190260 | 168607 |
| &nbsp;&nbsp;&nbsp;Deferred income taxes and investment tax credits | (49721) | (34699) |
| &nbsp;&nbsp;&nbsp;Changes in regulatory assets and liabilities | 92160 | 124549 |
| &nbsp;&nbsp;&nbsp;Pension and postretirement benefit plan expense | 33911 | 34359 |
| &nbsp;&nbsp;&nbsp;Contributions to pension and postretirement benefit plans | (25263) | (23967) |
| &nbsp;&nbsp;&nbsp;Earnings of equity-method investments | (4208) | (3880) |
| &nbsp;&nbsp;&nbsp;Distributions from equity-method investments | 4250 | 3950 |
| &nbsp;&nbsp;&nbsp;Allowance for equity funds used during construction | (45177) | (39610) |
| &nbsp;&nbsp;&nbsp;Other non-cash adjustments to net income, net | 6534 | 4629 |
| &nbsp;&nbsp;&nbsp;Change in: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable and unbilled receivables | (30770) | 658 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Prepayments | (3656) | (7931) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Materials, supplies, and fuel stock | 7759 | (59105) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts and wages payable | (33619) | (33044) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Taxes accrued/receivable | 52568 | 56001 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other assets and liabilities | (11359) | 15513 |
| &nbsp;&nbsp;&nbsp;Net cash provided by operating activities | 464065 | 457982 |
| **Investing Activities:** |  |  |
| Additions to property, plant and equipment, net | (825352) | (823969) |
| Payments received from transmission project joint funding partners | 91966 | 58750 |
| Other | 2625 | 8805 |
| &nbsp;&nbsp;&nbsp;Net cash used in investing activities | (730761) | (756414) |
| **Financing Activities:** |  |  |
| Issuance of long-term debt | 400000 | 300000 |
| Discount on issuance of long-term debt | (3072) | (186) |
| Retirement of long-term debt | (19885) |  |
| Payments on finance lease liabilities | (2368) |  |
| Dividends on common stock | (140000) | (129152) |
| Issuance of common stock | 4541 | 234672 |
| Tax withholdings on net settlements of share-based awards | (3303) | (3782) |
| Other | (4873) | (2599) |
| &nbsp;&nbsp;&nbsp;Net cash provided by financing activities | 231040 | 398953 |
| Net (decrease) increase in cash and cash equivalents | (35656) | 100521 |
| Cash and cash equivalents at beginning of the period | 368865 | 327429 |
| Cash and cash equivalents at end of the period | $333209 | $427950 |
| **Supplemental Disclosure of Cash Flow Information:** |  |  |
| &nbsp;&nbsp;&nbsp;Cash paid for income taxes | $5790 | $8830 |
| &nbsp;&nbsp;&nbsp;Cash paid for interest (net of amount capitalized) | $115138 | $88391 |
| Non-cash investing and financing activities: |  |  |
| &nbsp;&nbsp;&nbsp;Additions to property, plant and equipment in accounts payable | $211545 | $144232 |
| &nbsp;&nbsp;&nbsp;Right-of-use asset obtained in exchange for finance lease liability | $226618 | $— |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**IDACORP, Inc.**

**Condensed Consolidated Statements of Equity**

**(unaudited)**

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| | **(in thousands)** | **(in thousands)** | **(in thousands)** | **(in thousands)** |
| **Common Stock** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Balance at beginning of period | $1201374 | $1123745 | $1194998 | $888615 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Issuance | 1487 | 1494 | 4541 | 234672 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Share-based compensation expense | 2391 | 2709 | 9066 | 8280 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Tax withholdings on net settlements of share-based awards | (9) | (88) | (3303) | (3782) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other | (24) | (117) | (83) | (42) |
| &nbsp;&nbsp;&nbsp;Balance at end of period | 1205219 | 1127743 | 1205219 | 1127743 |
| **Retained Earnings** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Balance at beginning of period | 2211514 | 2089185 | 2149548 | 2036138 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net income attributable to IDACORP, Inc. | 124437 | 113605 | 279865 | 251298 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Common stock dividends ($0.86, $0.83, $2.58, and $2.49 per share, respectively) | (46777) | (44457) | (140239) | (129103) |
| &nbsp;&nbsp;&nbsp;Balance at end of period | 2289174 | 2158333 | 2289174 | 2158333 |
| **Accumulated Other Comprehensive Loss** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Balance at beginning of period | (13481) | (16616) | (13592) | (17184) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Unfunded pension liability adjustment (net of tax) | 171 | 285 | 282 | 853 |
| &nbsp;&nbsp;&nbsp;Balance at end of period | (13310) | (16331) | (13310) | (16331) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total IDACORP, Inc. shareholders' equity at end of period | 3481083 | 3269745 | 3481083 | 3269745 |
| **Noncontrolling Interests** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Balance at beginning of period | 7360 | 7593 | 7001 | 7174 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net income attributable to noncontrolling interests | 172 | 235 | 531 | 654 |
| &nbsp;&nbsp;&nbsp;Balance at end of period | 7532 | 7828 | 7532 | 7828 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total equity at end of period | $3488615 | $3277573 | $3488615 | $3277573 |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**Idaho Power Company**

**Condensed Consolidated Statements of Income**

**(unaudited)**

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| | **(in thousands)** | **(in thousands)** | **(in thousands)** | **(in thousands)** |
| **Operating Revenues** | $523549 | $527487 | $1405173 | $1425606 |
| **Operating Expenses:** |  |  |  |  |
| Operation: |  |  |  |  |
| &nbsp;&nbsp;Purchased power | 121276 | 114578 | 284163 | 321860 |
| &nbsp;&nbsp;Fuel expense | 74992 | 73471 | 179238 | 188411 |
| &nbsp;&nbsp;Power cost adjustment | (18295) | 20779 | 57967 | 102297 |
| &nbsp;&nbsp;Other operations and maintenance | 120398 | 116168 | 355371 | 332900 |
| &nbsp;&nbsp;Energy efficiency programs | 7460 | 5283 | 18808 | 16699 |
| Depreciation and amortization | 64493 | 56388 | 185407 | 165133 |
| Other operating expenses, net | 8112 | 7453 | 24053 | 12482 |
| &nbsp;&nbsp;&nbsp;Total operating expenses | 378436 | 394120 | 1105007 | 1139782 |
| **Operating Income** | 145113 | 133367 | 300166 | 285824 |
| **Nonoperating (Income) Expense:** |  |  |  |  |
| Allowance for equity funds used during construction | (15569) | (15179) | (45177) | (39610) |
| Earnings of unconsolidated equity-method investments | (996) | (841) | (2150) | (1936) |
| Interest on long-term debt and finance leases | 46244 | 35432 | 128733 | 102048 |
| Other interest | 7759 | 6268 | 21361 | 17645 |
| Allowance for borrowed funds used during construction | (9207) | (7639) | (26075) | (20518) |
| Other income, net | (12595) | (12207) | (37563) | (37469) |
| &nbsp;&nbsp;&nbsp;Total nonoperating expense, net | 15636 | 5834 | 39129 | 20160 |
| **Income Before Income Taxes** | 129477 | 127533 | 261037 | 265664 |
| **Income Tax Expense (Benefit)** | 7321 | 16444 | (12084) | 19885 |
| **Net Income** | $122156 | $111089 | $273121 | $245779 |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**Idaho Power Company**

**Condensed Consolidated Statements of Comprehensive Income**

**(unaudited)**

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| | **(in thousands)** | **(in thousands)** | **(in thousands)** | **(in thousands)** |
| **Net Income** | $122156 | $111089 | $273121 | $245779 |
| **Other Comprehensive Income:** |  |  |  |  |
| Unfunded pension liability adjustment, net of tax of $57, $99, $302 and $296, respectively | 171 | 285 | 282 | 853 |
| **Total Comprehensive Income** | $122327 | $111374 | $273403 | $246632 |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**Idaho Power Company**

**Condensed Consolidated Balance Sheets**

**(unaudited)**

---

| | | |
|:---|:---|:---|
| | **September 30,<br>2025** | **December 31,<br>2024** |
| | **(in thousands)** | **(in thousands)** |
| **Assets** | | |
| **Current Assets:** | | |
| Cash and cash equivalents | $167519 | $188916 |
| Receivables: |  |  |
| &nbsp;&nbsp;Customer (net of allowance of $4,341 and $5,071, respectively) | 139079 | 114824 |
| &nbsp;&nbsp;Other (net of allowance of $703 and $628, respectively) | 48308 | 28874 |
| Income taxes receivable |  | 11811 |
| Accrued unbilled receivables | 90582 | 97711 |
| Materials and supplies (at average cost) | 207103 | 201064 |
| Fuel stock (at average cost) | 29858 | 43656 |
| Prepayments | 30531 | 29328 |
| Current regulatory assets | 80803 | 89315 |
| Other | 104 |  |
| &nbsp;&nbsp;&nbsp;Total current assets | 793887 | 805499 |
| **Investments** | 89006 | 92921 |
| **Property, Plant and Equipment:** |  |  |
| Utility plant in service | 8333801 | 7957763 |
| Accumulated provision for depreciation | (2837096) | (2714706) |
| &nbsp;&nbsp;&nbsp;Utility plant in service - net | 5496705 | 5243057 |
| Construction work in progress | 1619882 | 1244559 |
| Finance lease right-of-use assets | 222445 |  |
| Plant held for future use | 19281 | 13211 |
| Other property | 5173 | 4858 |
| &nbsp;&nbsp;&nbsp;Property, plant and equipment, net | 7363486 | 6505685 |
| **Other Assets:** |  |  |
| Company-owned life insurance | 101696 | 92062 |
| Regulatory assets | 1429218 | 1418057 |
| Other | 47819 | 52744 |
| &nbsp;&nbsp;&nbsp;Total other assets | 1578733 | 1562863 |
| **Total** | $9825112 | $8966968 |

---

The accompanying notes are an integral part of these statements.

------

<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**Idaho Power Company**

**Condensed Consolidated Balance Sheets**

**(unaudited)**

---

| | | |
|:---|:---|:---|
| | **September 30,<br>2025** | **December 31,<br>2024** |
| | **(in thousands, except par value)** | **(in thousands, except par value)** |
| **Liabilities and Equity** | | |
| **Current Liabilities:** | | |
| Current maturities of long-term debt | $116300 | $19885 |
| Accounts payable | 316973 | 305248 |
| Accounts payable to affiliates | 21709 | 3403 |
| Taxes accrued | 52731 | 6981 |
| Interest accrued | 36534 | 42681 |
| Accrued compensation | 74467 | 70319 |
| Current regulatory liabilities | 40974 | 7523 |
| Advances from customers | 185620 | 165229 |
| Other | 54309 | 61309 |
| &nbsp;&nbsp;&nbsp;Total current liabilities | 899617 | 682578 |
| **Other Liabilities:** |  |  |
| Deferred income taxes | 786023 | 829446 |
| Regulatory liabilities | 1009989 | 976803 |
| Pension and other postretirement benefits | 161247 | 165992 |
| Finance lease liabilities | 218182 |  |
| Other | 195541 | 167775 |
| &nbsp;&nbsp;&nbsp;Total other liabilities | 2370982 | 2140016 |
| **Long-Term Debt** | 3330752 | 3053777 |
| **Commitments and Contingencies** |  |  |
| **Equity:** |  |  |
| Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares issued and outstanding) | 97877 | 97877 |
| Premium on capital stock | 912258 | 912258 |
| Capital stock expense | (2097) | (2097) |
| Retained earnings | 2229033 | 2096151 |
| Accumulated other comprehensive loss | (13310) | (13592) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total equity | 3223761 | 3090597 |
| **Total** | $9825112 | $8966968 |
| The accompanying notes are an integral part of these statements. | The accompanying notes are an integral part of these statements. | The accompanying notes are an integral part of these statements. |

---

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**Idaho Power Company**

**Condensed Consolidated Statements of Cash Flows**

**(unaudited)**

---

| | | |
|:---|:---|:---|
| | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** |
| | **(in thousands)** | **(in thousands)** |
| **Operating Activities:** |  |  |
| Net income | $273121 | $245779 |
| Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
| &nbsp;&nbsp;&nbsp;Depreciation and amortization | 189807 | 168150 |
| &nbsp;&nbsp;&nbsp;Deferred income taxes and investment tax credits | (57000) | (39823) |
| &nbsp;&nbsp;&nbsp;Changes in regulatory assets and liabilities | 92160 | 124549 |
| &nbsp;&nbsp;&nbsp;Pension and postretirement benefit plan expense | 33911 | 34322 |
| &nbsp;&nbsp;&nbsp;Contributions to pension and postretirement benefit plans | (25263) | (23930) |
| &nbsp;&nbsp;&nbsp;Earnings of equity-method investments | (2150) | (1936) |
| &nbsp;&nbsp;&nbsp;Distributions from equity-method investments | 3350 | 3100 |
| &nbsp;&nbsp;&nbsp;Allowance for equity funds used during construction | (45177) | (39610) |
| &nbsp;&nbsp;&nbsp;Other non-cash adjustments to net income, net | (3060) | (3843) |
| &nbsp;&nbsp;&nbsp;Change in: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable and unbilled receivables | (32366) | 1094 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Prepayments | (3670) | (7938) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Materials, supplies, and fuel stock | 7759 | (59105) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts and wages payable | (12643) | 4644 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Taxes accrued/receivable | 57562 | 48753 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other assets and liabilities | (11322) | 15545 |
| &nbsp;&nbsp;&nbsp;Net cash provided by operating activities | 465019 | 469751 |
| **Investing Activities:** |  |  |
| Additions to utility plant, net | (825100) | (823855) |
| Payments received from transmission project joint funding partners | 91966 | 58750 |
| Other | 16621 | 11999 |
| &nbsp;&nbsp;&nbsp;Net cash used in investing activities | (716513) | (753106) |
| **Financing Activities:** |  |  |
| Issuance of long-term debt | 400000 | 300000 |
| Discount on issuance of long-term debt | (3072) | (186) |
| Retirement of long-term debt | (19885) |  |
| Payments on finance lease liabilities | (2368) |  |
| Dividends on common stock | (140128) | (129268) |
| Capital contribution from parent |  | 200000 |
| Other | (4450) | (2283) |
| &nbsp;&nbsp;&nbsp;Net cash provided by financing activities | 230097 | 368263 |
| Net (decrease) increase in cash and cash equivalents | (21397) | 84908 |
| Cash and cash equivalents at beginning of the period | 188916 | 271791 |
| Cash and cash equivalents at end of the period | $167519 | $356699 |
| **Supplemental Disclosure of Cash Flow Information:** |  |  |
| &nbsp;&nbsp;&nbsp;Cash received from IDACORP related to income taxes | $(21600) | $(15483) |
| &nbsp;&nbsp;&nbsp;Cash paid for interest (net of amount capitalized) | $114854 | $88193 |
| Non-cash investing and financing activities: |  |  |
| &nbsp;&nbsp;&nbsp;Additions to utility plant in accounts payable | $211545 | $144232 |
| &nbsp;&nbsp;&nbsp;Right-of-use asset obtained in exchange for finance lease liability | $226618 | $— |

---

The accompanying notes are an integral part of these statements.

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**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. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the FERC. Idaho Power is the parent of IERCo, a joint-owner of BCC, which mines and supplies coal to the Jim Bridger plant owned in part by Idaho Power.

IDACORP's other notable subsidiaries include IFS, an investor in affordable housing and other real estate tax credit investments, and Ida-West, an operator of small PURPA-qualifying hydropower generation projects.

**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.

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated entity would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3 - "Regulatory Matters."

**Financial Statements**

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's condensed consolidated balance sheets as of September 30, 2025, condensed consolidated statements of income for the three months and nine months ended September 30, 2025 and 2024, and condensed consolidated cash flows for the nine months ended September 30, 2025 and 2024. These adjustments are of a normal and recurring nature. These financial statements do not contain the complete detail or note disclosures concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in the 2024 Annual Report. The statements of income for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective balance sheets and statements of income during the period in which such change occurred.

**Management Estimates**

Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions include, among others, those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled receivables, and the allowance for uncollectible accounts. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. Accordingly, actual results could differ from those estimates.

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**New and Recently Adopted Accounting Pronouncements**

*Recently Adopted Accounting Pronouncements*

In November 2023, the Financial Accounting Standards Board (FASB) issued ASU 2023-07, *Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures,* which expands annual and interim disclosure requirements for reportable segments, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024, with early adoption permitted. IDACORP and Idaho Power adopted this ASU on January 1, 2024, for annual periods, and subsequently on January 1, 2025, for interim periods. The amendments in this ASU have been applied retrospectively, as required. See Note 14 - "Segment Information" for expanded disclosure required by this ASU.

There have been no other recently adopted accounting pronouncements that have had a material impact on IDACORP's or Idaho Power's condensed consolidated financial statements.

*Recent Accounting Pronouncements Not Yet Adopted*

In December 2023, the FASB issued ASU 2023-09, *Income Taxes (Topic 740): Improvements to Income Tax Disclosures* which expands the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. This ASU is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments in this ASU are required to be applied prospectively and are allowed to be applied retrospectively. IDACORP and Idaho Power have evaluated the impact that adoption of this ASU will have on the notes to their respective financial statements, and the companies do not believe the adoption of the new standard will have a material impact.

In November 2024, the FASB issued ASU 2024-03, *Income Statement (Subtopic 220-40): Disaggregation of Income Statement Expenses* which requires disclosure of certain disaggregated income statement expense categories on an annual and interim basis. This ASU is effective for annual periods beginning after December 15, 2026, and for interim periods beginning after December 15, 2027, with early adoption permitted. The amendments in this ASU are required to be applied prospectively and are allowed to be applied retrospectively. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on the notes to their respective financial statements.

In September 2025, the FASB issued ASU 2025-06, *Intangibles (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software,* which amends certain aspects of the accounting for and disclosure of software costs. This ASU is effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. The amendments in this ASU are required to be applied prospectively and may be applied either retrospectively or using a modified prospective transition method. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their respective financial statements.

There have been no other recent accounting pronouncements not yet adopted that are expected to have a material impact on IDACORP's or Idaho Power's 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.

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**Income Tax Expense**

The following table provides a summary of income tax (benefit) expense for the nine months ended September 30, 2025 and 2024 (in thousands):

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **IDACORP** | **IDACORP** | **Idaho Power** | **Idaho Power** |
| | **2025** | **2024** | **2025** | **2024** |
| Income tax at statutory rates (federal and state) | $67179 | $69543 | $65335 | $68382 |
| Excess deferred income tax reversal | (7293) | (7535) | (7293) | (7535) |
| Income tax return adjustments | (8046) | 1875 | (8581) | 1865 |
| Other<sup>(1)</sup> | (24300) | (22507) | (22545) | (20327) |
| Income tax expense before ADITC | $27540 | $41376 | $26916 | $42385 |
| Additional ADITC amortization | (39000) | (22500) | (39000) | (22500) |
| Income tax (benefit) expense | $(11460) | $18876 | $(12084) | $19885 |
| Effective tax rate | (4.3)% | 7.0% | (4.6)% | 7.5% |

---

(1) "Other" primarily consists of the net tax effect of Idaho Power's regulatory flow-through tax adjustments.

**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 2024 Annual Report. On May 30, 2025, Idaho Power filed a general rate case and proposed rate schedules with the IPUC, Case No. IPC-E-25-16. The filing was based on a 2025 test year and requested approximately $199.1 million in additional Idaho-jurisdiction annual revenues, which is net of a $46.8 million PCA decrease. As filed, this request would have resulted in a 13.09 percent overall average net Idaho-jurisdictional revenue increase for Idaho Power's Idaho customers. The filing requested an authorized rate of return on equity of 10.4 percent with an Idaho retail rate base of approximately $5.1 billion, which is not inclusive of rate base associated with Idaho Power's jointly-owned coal facilities, the costs of which are recovered under separate rate mechanisms. In its application, Idaho Power proposed a capitalization structure of approximately 49 percent long-term debt and 51 percent common stock equity. Idaho Power included an average cost of debt of 5.132 percent and an overall cost of capital of 7.818 percent.

On October 24, 2025, Idaho Power filed a motion for approval of the 2025 Settlement Stipulation with the IPUC related to the Idaho general rate case filing. The 2025 Settlement Stipulation was entered into by Idaho Power, the Staff of the IPUC, and several of the intervening parties. If the IPUC approves the 2025 Settlement Stipulation, it will authorize Idaho Power to adjust rates on January 1, 2026, consistent with the terms contained in the 2025 Settlement Stipulation.

The 2025 Settlement Stipulation contains the following significant terms, among other items:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Idaho Power would implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by approximately $110.0 million, or 7.48 percent, effective January 1, 2026. The approximate $110 million of additional annual revenue is inclusive of a PCA rate increase of $13.1 million;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a 9.6 percent return on equity and a 7.410 percent authorized rate of return based on the filed cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $4.9 billion (which is based on the average of monthly average plant balances for January through December 2025);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a base level net power supply expense ("NPSE") of approximately $468.8 million, a decrease of $16.1 million from the currently approved base level NPSE;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• updates to the FCA mechanism rates to reflect approved fixed costs and Idaho Power's proposed rate designs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• continued deferral of certain wildfire mitigation related costs, including incremental vegetation management and insurance costs, as measured from 2024 actual costs, through the earlier of Idaho Power's next general rate case or 2027;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• modifications to Idaho Power's ADITC and revenue sharing mechanism: (1) to include an additional amount of investment tax credits equal to the total of existing ADITCs not currently eligible for accelerated amortization under the mechanism and all investment tax credits generated through the end of calendar-year 2028; (2) to establish an

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annual cap of $55 million on the amount of accelerated amortization of ADITCs for calendar year 2026 and thereafter; (3) to re-affirm the existing minimum specified Idaho ROE of 9.12 percent for additional amortization of ADITCs; (4) to re-affirm the existing 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers; and (5) to continue to implement all revenue sharing through the PCA; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• agreement that Idaho Power's share of capital expenditures at jointly-owned coal-fired plants through year-end 2024 are included for recovery in the stipulated revenue requirement.

At the time of the 2025 Settlement Stipulation, Staff of the IPUC had completed its prudence review of capital projects included in the test year rate base through July 2025. To the extent IPUC Staff identifies potential prudence concerns with investments after July 2025, it will address those in Idaho Power's next Idaho general rate case. The 2025 Settlement Stipulation does not include a tracking mechanism for incremental depreciation and interest expense that Idaho Power requested as part of the initial rate case filing.

The parties to the 2025 Settlement Stipulation have requested that the IPUC issue an order approving the agreed-upon rates effective January 1, 2026. The 2025 Settlement Stipulation does not preclude Idaho Power from filing another general rate case in Idaho at any time in the future. If the IPUC were to deny the 2025 Settlement Stipulation or materially change its terms, no party would be bound by the terms of the stipulation. As of the date of this report, the IPUC's determination in this matter is pending.

**Idaho ADITC Mechanism**

The 2018 Settlement Stipulation and the 2023 Settlement Stipulation are each described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2024 Annual Report. 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. If approved by the IPUC, the 2025 Settlement Stipulation would also modify the 2018 Settlement Stipulation in part as described above in "Idaho and Oregon Rate Cases."

Based on its estimate of full-year 2025 Idaho ROE, in the three months and nine months ended September 30, 2025, Idaho Power recorded $2.5 million and $39.0 million, respectively, in additional ADITC amortization under the 2023 Settlement Stipulation. Accordingly, as of September 30, 2025, approximately $38 million of additional ADITC remained available for future use. Idaho Power recorded $2.5 million and $22.5 million of additional ADITC amortization during the three months and nine months ended September 30, 2024, respectively, based on its then-current estimate of full-year 2024 Idaho ROE.

**Power Cost Adjustment Mechanisms**

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the variability of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheet for future recovery or refund. The power supply costs deferred primarily result from changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho Power's own generation.

In May 2025, the IPUC issued an order approving a $94.8 million decrease in PCA revenues, effective for the 2025-2026 PCA collection period from June 1, 2025, to May 31, 2026, compared to the 2024-2025 PCA collection period. The decrease in PCA revenues is due primarily to the ending of collection of the 2023 PCA balancing adjustment, which was collected over two years as ordered by the IPUC. Increased sales of renewable energy credits also contributed to the decrease. If approved by the IPUC, the 2025 Settlement Stipulation would modify PCA collection effective January 1, 2026, to account for the new base level NPSE of $468.8 million.

In May 2025, the OPUC approved a settlement stipulation between Idaho Power and intervening parties for its APCU in Oregon. The APCU includes both an October update and a March forecast. The results of the October update are reflected as an update to base rates and the results of the March forecast are reflected as an update to APCU rates. The settlement resulted in an overall rate decrease of $1.8 million in Oregon-jurisdictional rates effective June 1, 2025.

**Idaho Fixed Cost Adjustment Mechanism**

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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, Idaho Power recovers a portion of fixed costs through 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 2025, the IPUC issued an order approving a $39.8 million decrease in recovery from the FCA from $36.8 million to negative $3.1 million for the 2024 FCA deferral, reflecting a refund to residential and small commercial customers of the 2024 FCA deferral balance of $3.1 million, with new rates effective for the period from June 1, 2025, to May 31, 2026. Beginning with the 2026 FCA deferral, if approved by the IPUC, the 2025 Settlement Stipulation would update the authorized fixed-cost recovery amount per customer and per unit of energy within the FCA mechanism to support Idaho Power's proposed rate designs, as noted above.

**Recovery of Incremental AFUDC Associated with HCC**

In March 2025, Idaho Power filed an application with the IPUC requesting an order authorizing an increase of $29.7 million in the annual cash collection of incremental financing costs, or AFUDC, associated with relicensing of the HCC project. In September 2025, the IPUC approved Idaho Power's proposed increase in annual cash collection to recover AFUDC associated with relicensing of the HCC project, effective October 1, 2025.

**Wildfire Mitigation Cost Deferral**

In December 2024, Idaho Power filed its 2025 WMP with the OPUC along with an application requesting authorization to defer for future recovery an estimated $3.3 million of newly identified incremental costs expected to be incurred in 2025 associated with expanded wildfire mitigation efforts. The OPUC approved the 2025 WMP in June 2025, and in August 2025, the OPUC granted Idaho Power's request to defer for future recovery the estimated $3.3 million of incremental costs expected to be incurred in 2025 associated with expanded wildfire mitigation efforts. Previously, in December 2023, Idaho Power had filed an application requesting authorization to defer for future recovery an estimated $1.3 million of incremental costs expected to be incurred in 2024 in connection with wildfire mitigation efforts. Such incremental costs related to 2024 were resolved as part of the settlement stipulations for the 2024 Oregon general rate case. In October 2025, Idaho Power filed an application with the OPUC requesting authorization to recover $0.7 million of amortization expense related to deferred 2023 wildfire mitigation costs over a 12-month period beginning January 1, 2026. This request was combined with two other proposed rate adjustments that, if approved, would reflect an overall net decrease of $0.6 million or 0.9 percent.

In September 2025, the IPUC granted Idaho Power's request to defer for future recovery an estimated $22.2 million of newly identified incremental O&M costs expected to be incurred in 2025 associated with expanded wildfire mitigation efforts. The IPUC also authorized the continued deferral of incremental insurance costs above the 2022 base established in the 2023 Settlement Stipulation.

**4. REVENUES**

The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power for the three months and nine months ended September 30, 2025 and 2024 (in thousands):

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| &nbsp;&nbsp;&nbsp;Revenue from contracts with customers | $526424 | $532477 | $1386879 | $1393006 |
| &nbsp;&nbsp;&nbsp;Alternative revenue programs and other revenues | (2875) | (4990) | 18294 | 32600 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total electric utility operating revenues | $523549 | $527487 | $1405173 | $1425606 |

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**Revenues from Contracts with Customers**

The following table presents revenues from contracts with customers disaggregated by revenue source for the three months and nine months ended September 30, 2025 and 2024 (in thousands):

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| &nbsp;&nbsp;&nbsp;Retail revenues: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Residential (includes $(4125), $(6193), $(9194), and $(8982), respectively, related to the FCA)<sup>(1)</sup> | $195445 | $195291 | $535505 | $525353 |
| &nbsp;&nbsp;&nbsp;&nbsp;Commercial (includes $(70), $(66), $(150), and $(158), respectively, related to the FCA)<sup>(1)</sup> | 111510 | 112323 | 304014 | 303031 |
| &nbsp;&nbsp;&nbsp;&nbsp;Industrial | 72079 | 71908 | 205526 | 203990 |
| &nbsp;&nbsp;&nbsp;&nbsp;Irrigation | 101690 | 109861 | 195172 | 191671 |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred revenue related to HCC relicensing AFUDC<sup>(2)</sup> | (2854) | (2881) | (6848) | (6913) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail revenues | 477870 | 486502 | 1233369 | 1217132 |
| &nbsp;&nbsp;Less: FCA mechanism revenues<sup>(1)</sup> | 4195 | 6259 | 9344 | 9140 |
| &nbsp;&nbsp;&nbsp;Wholesale energy sales | 10520 | 6946 | 45443 | 65759 |
| &nbsp;&nbsp;&nbsp;Transmission wheeling-related revenues | 17856 | 19419 | 53624 | 60142 |
| &nbsp;&nbsp;&nbsp;Energy efficiency program revenues | 7460 | 5283 | 18808 | 16699 |
| &nbsp;&nbsp;&nbsp;Other revenues from contracts with customers | 8523 | 8068 | 26291 | 24134 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total revenues from contracts with customers | $526424 | $532477 | $1386879 | $1393006 |

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(1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers.

(2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Effective October 1, 2025, this amount will increase by $29.7 million annually; refer to Note 3 - "Regulatory Matters."

**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.

Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits. Related to these forward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on the condensed consolidated statements of income. For more information on settled electricity swaps, see Note 12 - "Derivative Financial Instruments."

The table below presents the FCA mechanism revenues and other revenues for the three months and nine months ended September 30, 2025 and 2024 (in thousands):

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| &nbsp;&nbsp;&nbsp;FCA mechanism revenues | $(4195) | $(6259) | $(9344) | $(9140) |
| &nbsp;&nbsp;&nbsp;Derivative revenues | 1320 | 1269 | 27638 | 41740 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total alternative revenue programs and other revenues | $(2875) | $(4990) | $18294 | $32600 |

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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 for the nine months ended September 30, 2025 and 2024 (in thousands):

---

| | | |
|:---|:---|:---|
| | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** |
| Balance at beginning of period | $5071 | $4869 |
| Additions to the allowance | 2658 | 1744 |
| Write-offs, net of recoveries | (3388) | (3317) |
| Balance at end of period | $4341 | $3296 |
| Allowance for uncollectible accounts as a percentage of customer receivables | 3.0% | 2.2% |

---

**5. LONG-TERM DEBT**

**Long-Term Debt Issuances, Maturities, and Redemptions**

On February 3, 2025, Idaho Power repaid $19.9 million in aggregate principal amount of maturing variable rate American Falls bonds.

On March 13, 2025, Idaho Power issued $400 million in aggregate principal amount of 5.70% first mortgage bonds, secured medium-term notes, Series O, maturing on March 15, 2055.

**Idaho Power First Mortgage Bonds**

Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and WPSC. In February and March 2024, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through December 31, 2026, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 8 percent. At September 30, 2025, $500 million remained available for debt issuance under the regulatory orders.

In February 2025, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

In February 2025, Idaho Power entered into a selling agency agreement with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $2.1 billion aggregate principal amount of first mortgage bonds, secured medium-term notes, Series O (Series O Notes), under the Indenture. Also in February 2025, Idaho Power entered into the Fifty-third Supplemental Indenture, dated effective as of February 26, 2025, to the Indenture (Fifty-third Supplemental Indenture). The Fifty-third Supplemental Indenture provides for, among other items the issuance of up to $2.1 billion in aggregate principal amount of Series O Notes pursuant to the Indenture and increased the limit of the amount of first mortgage bonds at any one time outstanding to $5.5 billion as provided in the Indenture. The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

The 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, 2025, the maximum amount of additional first mortgage bonds Idaho Power could issue under this test was

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approximately $2.3 billion. The Indenture also imposes a fixed cap of $5.5 billion on the aggregate amount of first mortgage bonds that may be outstanding under the Indenture, which cap may be amended under certain conditions. As of September 30, 2025, Idaho Power could issue approximately $2.0 billion of additional first mortgage bonds under that aggregate cap.

**6. COMMON STOCK**

**IDACORP Common Stock**

During the nine months ended September 30, 2025, IDACORP issued an aggregate of 82,924 shares of common stock using original issuances of shares. IDACORP granted 82,344 restricted stock unit awards and issued 35,475 shares of common stock to employees pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, and issued an additional 9,273 shares of common stock to members of the board of directors. IDACORP issued 38,176 shares of common stock pursuant to its IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan.

***Equity Forward Sale Agreements:*** On May 8, 2025, IDACORP announced a registered public offering of 4,504,505 shares of its common stock at a public offering price of $111.00 per share, for an aggregate amount of $500.0 million. In conjunction with this offering, underwriters exercised an option to purchase 675,675 additional shares for an additional aggregate amount of $75.0 million. The 5,180,180 shares were sold by IDACORP to the underwriters under FSAs, which provide for settlement on a settlement date or dates to be specified at IDACORP's discretion, but which is expected to occur on or prior to November 9, 2026. The forward sale price was initially $107.67 per share and is subject to certain adjustments in accordance with the terms of the FSAs through the date or dates of settlement.

The FSAs will be physically settled with common shares issued by IDACORP, unless IDACORP elects to settle the agreements in net cash or net shares, subject to certain conditions. On a settlement date or dates, if IDACORP elects to physically settle the FSAs, IDACORP will issue shares of common stock to the various counterparties at the then-applicable forward sale price and receive issuance proceeds at that time.

At September 30, 2025, IDACORP could have settled the FSAs with physical delivery of 5,180,180 shares of common stock to the counterparties in exchange for cash of $561.0 million. The FSAs could have also been settled at September 30, 2025, with delivery of approximately $81.6 million of cash or approximately 658,896 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.

***At-the-Market Offering Program:*** On May 20, 2024, IDACORP entered into an Equity Distribution Agreement (EDA) pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $300 million of shares of its common stock through an ATM offering program, which includes the ability to enter into FSAs. During the three months and nine months ended September 30, 2025, IDACORP did not issue common stock pursuant to the EDA.

During the nine months ended September 30, 2025, IDACORP executed FSAs under its ATM offering program with various counterparties who borrowed and sold 452,256 shares of IDACORP's common stock at an aggregate gross sales price of $52.2 million, including approximately $0.7 million in commissions and fees to the counterparties payable by IDACORP when the FSAs are settled. IDACORP did not execute any FSAs under its ATM offering program during the three months ended September 30, 2025. At September 30, 2025, $155.5 million in shares of IDACORP's common stock remained available for issuance through its ATM offering program.

At September 30, 2025, IDACORP had the following FSAs outstanding under its ATM offering program (in thousands of dollars, except for shares and forward price amounts):

---

| | | | |
|:---|:---|:---|:---|
| **Latest Settlement Date** | **Shares** | **Net Proceeds Available** | **Forward Price** |
| November 12, 2025 | 500000 | $57143 | $114.29 |
| December 31, 2025 | 301914 | 34816 | 115.32 |
| March 31, 2026 | 198086 | 22783 | 115.02 |
| March 31, 2026 | 254170 | 28964 | 113.95 |
| &nbsp;&nbsp;&nbsp;Total / Weighted Average Forward Price | 1254170 | $143706 | $114.58 |

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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, 2025, IDACORP could have settled all its outstanding FSAs under the ATM offering program with physical delivery of 1,254,170 shares of common stock to the counterparties in exchange for cash of $143.7 million. At September 30, 2025, IDACORP could have settled the FSAs with net delivery to various counterparties of approximately $11.9 million of cash or approximately 96,141 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.

***FSA Earnings Per Shares Dilution:*** Prior to settlement, the potentially issuable shares pursuant to the FSAs will be reflected in IDACORP's diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of IDACORP's common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the FSAs, less the number of shares that could be purchased by IDACORP in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of IDACORP's stock during the reporting period is higher than the then-applicable forward sale price as of the end of the reporting period. 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 FSAs. For the three months and nine months ended September 30, 2024, approximately 59,000 and 54,000 incremental shares, respectively, were included in the calculation of diluted earnings per share related to the securities under FSAs. See Note 7 - "Earnings Per Share" for additional information concerning IDACORP's diluted earnings per share.

**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, 2025, the leverage ratios for IDACORP and Idaho Power were 52 percent and 54 percent, respectively. Based on these restrictions, IDACORP's and Idaho Power's dividends were limited to $1.4 billion and $1.2 billion, respectively, at September 30, 2025. There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to IDACORP and Idaho Power from any material subsidiary. At September 30, 2025, IDACORP and Idaho Power were in compliance with those covenants.

Idaho Power's Statement of Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital without IPUC approval. At September 30, 2025, Idaho Power's common equity capital was 47 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.

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**7. EARNINGS PER SHARE** 

The table below presents the computation of IDACORP's basic and diluted earnings per share for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except for per share amounts).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Numerator: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Net income attributable to IDACORP, Inc. | $124437 | $113605 | $279865 | $251298 |
| Denominator: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Weighted-average common shares outstanding - basic | 54172 | 53386 | 54147 | 52112 |
| &nbsp;&nbsp;Effect of dilutive securities<sup>(1)</sup> | 883 | 99 | 375 | 67 |
| &nbsp;&nbsp;&nbsp;Weighted-average common shares outstanding - diluted | 55055 | 53485 | 54522 | 52179 |
| Basic earnings per share | $2.30 | $2.13 | $5.17 | $4.82 |
| Diluted earnings per share | $2.26 | $2.12 | $5.13 | $4.82 |

---

(1) Includes the effect of dilutive securities related to FSAs. See Note 6 - "Common Stock" for additional information concerning IDACORP's FSAs.

**8. COMMITMENTS**

**Purchase Obligations** 

During the nine months ended September 30, 2025, Idaho Power entered into:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• an agreement in May 2025 to acquire and own certain equipment and to receive related technical services, which increased Idaho Power's contractual purchase obligations by approximately $127.8 million through the first half of 2029. During the nine months ended September 30, 2025, Idaho Power made a payment of $25.6 million related to this obligation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• an agreement in August 2025 for a non-PURPA-qualifying solar facility PPA with a scheduled online date of June 2027, which increased Idaho Power's contractual purchase obligations by approximately $206.7 million over the 25-year term of the agreement; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• an agreement in September 2025 to replace an expiring PURPA-qualifying hydropower facility PPA, which increased Idaho Power's contractual purchase obligations by approximately $41.4 million over the 20-year term of the agreement.

In September 2025, due to permitting delays and uncertainties, Idaho Power, the counterparty, and its applicable affiliates terminated the agreements for the Jackalope Wind Project, which had been entered into in October 2024. The wind project included a 35-year PPA and a build-transfer agreement (BTA) for a co-located facility to be owned by Idaho Power. Each agreement provided for approximately 300 MW of wind-powered generation capacity. The termination collectively reduced Idaho Power's contractual purchase obligations by approximately $2.5 billion over the 35-year term of the PPA, beginning in June 2027, as well as during 2026 and 2027 under the BTA.

In October 2025, Idaho Power entered into agreements for firm transportation capacity with natural gas transporters, increasing its contractual purchase obligations by approximately $369.4 million. These obligations commence in October 2025 and expire in December 2045.

Except as disclosed above, during the nine months ended September 30, 2025, 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 2024 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 $51.9 million at September 30, 2025, representing IERCo's one-third share of BCC's total reclamation obligation of $155.6 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At September 30, 2025, the value of BCC's reclamation trust fund exceeded WDEQ's guarantee requirement for the total reclamation obligation.

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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, 2025, management believe 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. LEASES**

**Recognition of Lease Assets and Liabilities**

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. Idaho Power determines if an arrangement is a lease and its classification at the lease commencement date. All leases must be recognized as a lease right-of-use (ROU) asset and a lease liability on the balance sheet of the lessee. The ROU asset represents the right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make lease payments. Idaho Power has elected the practical expedient to not separate non-lease components from lease components and instead account for both as a single lease component.

Lease ROU assets and lease liabilities are estimated and recognized at the lease commencement date based on the net present value of fixed lease payments over the lease term. Variable lease payments are expensed as incurred. If the lease does not provide an implicit rate, Idaho Power uses its collateralized incremental borrowing rate based on the information available at the commencement date to determine the present value of fixed lease payments. The implicit rate is used when it is readily determinable. Idaho Power recovers 100 percent of the Idaho-jurisdiction portion of lease payments on all existing arrangements classified as finance leases through the PCA, and recovers the Oregon-jurisdiction portion of lease payments through the APCU. Idaho Power recognizes lease expenses consistent with regulatory cost recovery, so lease expenses in excess of amounts recovered through the PCA and APCU are deferred as a regulatory asset.

**Finance Leases** 

Finance leases are included in finance lease ROU assets, other current liabilities, and finance lease liabilities recognized on the condensed consolidated balance sheets upon the lease commencement date. Amortization of the lease ROU asset is included in depreciation and amortization, and the interest expense associated with the finance lease liabilities is included in interest on long-term debt and finance leases on the condensed consolidated statements of income. Variable lease payments are not recognized on the condensed consolidated balance sheets and are recorded as incurred in other O&M expense on the condensed consolidated statements of income and in operating activities in the condensed consolidated statements of cash flows. Idaho Power's finance lease ROU assets and liabilities relate to the lease discussed below.

***Kuna BESS:*** On April 26, 2023, Idaho Power executed an Energy Storage Agreement with Kuna BESS LLC to utilize the storage capacity of a 150 MW battery storage facility over a 20-year term. The term began May 19, 2025, and has been classified as a finance lease.

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The following table provides a summary of the components of total lease cost included in the condensed consolidated statements of income for the three months and nine months ended September 30, 2025 (in thousands):

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| | | |
|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2025** |
| Finance lease cost: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of ROU asset (Depreciation and amortization) | $1639 | $2368 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest on lease liabilities (Interest on long-term debt and finance leases)<sup>(1)</sup> | 3478 | 5132 |
| Total finance lease cost | 5117 | 7500 |
| Variable lease cost (Other O&M) | 270 | 435 |
| Total lease cost | $5387 | $7935 |

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(1) Included in operating activities in the condensed consolidated statements of cash flows as cash paid for amounts included in the measurement of lease liabilities.

The following table presents the classification of certain lease amounts included in the condensed consolidated balance sheets as of September 30, 2025 (in thousands):

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| | |
|:---|:---|
| | **September 30, 2025** |
| Finance leases: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | $6067 |

---

The following table presents the weighted-average remaining lease term and weighted-average discount rate as of September 30, 2025:

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| | |
|:---|:---|
| | **September 30, 2025** |
| Finance leases: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average remaining lease term | 19.63 years |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average discount rate | 6.17% |

---

The following table presents the maturities of future fixed lease payments and a reconciliation of undiscounted cash flows to lease liabilities recognized on the condensed consolidated balance sheets as of September 30, 2025 (in thousands):

---

| | |
|:---|:---|
| | **Finance Leases** |
| 2025 | $4848 |
| 2026 | 19751 |
| 2027 | 19751 |
| 2028 | 19751 |
| 2029 | 19751 |
| Thereafter | 303657 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total future fixed lease payments<sup>(1)</sup> | 387509 |
| Less: amounts representing interest | (163260) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total present value of lease liabilities | $224249 |

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(1) The aggregate amount of future fixed lease payments represented above, and future variable lease payments, were disclosed as a purchase obligation in Note 9 - "Commitments" to the consolidated financial statements included in the 2024 Annual Report.

**10. CONTINGENCIES**

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where

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(a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted.

IDACORP and Idaho Power are parties to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company's provision of electric service, the operation of its power supply, transmission, and distribution facilities, and other aspects of its business. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the western United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and criminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. Idaho Power has also regularly received claims by governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power's transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims will not have a material adverse effect on their respective condensed consolidated financial statements.

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.

**11. BENEFIT PLANS**

Idaho Power has a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit plans for certain senior management employees called the SMSP. Idaho Power also has a nonqualified defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under the pension plan are based on years of service and the employee's final average earnings. Idaho Power also maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and

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qualifying dependents. 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, 2025 and 2024 (in thousands).

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Pension Plan** | **Pension Plan** | **SMSP** | **SMSP** | **Postretirement<br>Benefits** | **Postretirement<br>Benefits** | **Total** | **Total** |
| | **2025** | **2024** | **2025** | **2024** | **2025** | **2024** | **2025** | **2024** |
| Service cost | $8115 | $9127 | $293 | $262 | $168 | $175 | $8576 | $9564 |
| Interest cost | 14379 | 13549 | 1410 | 1333 | 743 | 706 | 16532 | 15588 |
| Expected return on plan assets | (17229) | (16240) |  |  | (447) | (457) | (17676) | (16697) |
| Amortization of prior service cost | 2 | 1156 | 55 | 55 | 344 | 387 | 401 | 1598 |
| Amortization of net loss |  |  | 173 | 329 | (441) | (374) | (268) | (45) |
| Net periodic benefit cost | 5267 | 7592 | 1931 | 1979 | 367 | 437 | 7565 | 10008 |
| Regulatory deferral of net periodic benefit cost<sup>(1)</sup> | (5058) | (7269) |  |  |  |  | (5058) | (7269) |
| Previously deferred pension costs recognized<sup>(1)</sup> | 8796 | 8796 |  |  |  |  | 8796 | 8796 |
| Net periodic benefit cost recognized for financial reporting<sup>(1)(2)</sup> | $9005 | $9119 | $1931 | $1979 | $367 | $437 | $11303 | $11535 |

---

(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 $9.4 million, respectively, were recognized in "Other operations and maintenance" and $1.5 million and $2.1 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, 2025 and 2024.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). | 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, 2025 and 2024 (in thousands). |
|  | **Pension Plan** | **Pension Plan** | **SMSP** | **SMSP** | **Postretirement<br>Benefits** | **Postretirement<br>Benefits** | **Total** | **Total** |
|  | **2025** | **2024** | **2025** | **2024** | **2025** | **2024** | **2025** | **2024** |
| Service cost | $23830 | $25494 | $879 | $788 | $504 | $524 | $25213 | $26806 |
| Interest cost | 42113 | 39136 | 4230 | 3999 | 2230 | 2118 | 48573 | 45253 |
| Expected return on plan assets | (51698) | (49900) |  |  | (1340) | (1373) | (53038) | (51273) |
| Amortization of prior service cost | 5 | 1280 | 166 | 165 | 1031 | 1161 | 1202 | 2606 |
| Amortization of net loss |  |  | 518 | 984 | (1324) | (1121) | (806) | (137) |
| Net periodic benefit cost | 14250 | 16010 | 5793 | 5936 | 1101 | 1309 | 21144 | 23255 |
| Regulatory deferral of net periodic benefit cost<sup>(1)</sup> | (13620) | (15320) |  |  |  |  | (13620) | (15320) |
| Previously deferred pension costs recognized<sup>(1)</sup> | 26387 | 26387 |  |  |  |  | 26387 | 26387 |
| Net periodic benefit cost recognized for financial reporting<sup>(1)(2)</sup> | $27017 | $27077 | $5793 | $5936 | $1101 | $1309 | $33911 | $34322 |

---

(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, $29.4 million and $28.2 million, respectively, were recognized in "Other operations and maintenance" and $4.5 million and $6.1 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, 2025 and 2024.

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2025, and during the nine months ended September 30, 2025, 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.

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.

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**12. DERIVATIVE FINANCIAL INSTRUMENTS**

**Commodity Price Risk**

Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants' nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power's energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.

All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three months and nine months ended September 30, 2025 and 2024 (in thousands):

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | **Gain/(Loss) on Derivatives Recognized in Income**<sup>(1)</sup> | **Gain/(Loss) on Derivatives Recognized in Income**<sup>(1)</sup> | **Gain/(Loss) on Derivatives Recognized in Income**<sup>(1)</sup> | **Gain/(Loss) on Derivatives Recognized in Income**<sup>(1)</sup> |
| | **Location of Realized Gain/(Loss) on Derivatives Recognized in Income** | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **Location of Realized Gain/(Loss) on Derivatives Recognized in Income** | **2025** | **2024** | **2025** | **2024** |
| Financial swaps | Operating revenues | $270 | $954 | $559 | $4575 |
| Financial swaps | Purchased power | (1948) | (3786) | (2927) | (4311) |
| Financial swaps | Fuel expense | (9145) | (18359) | (21881) | (43544) |
| Forward contracts | Operating revenues | (4) |  | 387 | 1278 |
| Forward contracts | Purchased power | 12 | (1454) | (458) | (3135) |
| Forward contracts | Fuel expense | (322) | (335) | (1153) | (556) |

---

(1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other O&M expense. See Note 13 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power's assets and liabilities from price risk management activities.

**Credit Risk**

At September 30, 2025, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, bonds, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. 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.

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**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, 2025, was $39.0 million. As of September 30, 2025, Idaho Power posted $30.6 million of cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2025, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $28.7 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 at September 30, 2025, and December 31, 2024 (in thousands):

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | | **Asset Derivatives** | **Asset Derivatives** | **Asset Derivatives** | **Asset Derivatives** | **Liability Derivatives** | **Liability Derivatives** | **Liability Derivatives** | **Liability Derivatives** |
| | **Balance Sheet Location** | **Gross Fair Value** | **Amounts Offset** | | **Net Assets** | **Gross Fair Value** | **Amounts Offset** | | **Net Liabilities** |
| | **Balance Sheet Location** | **Gross Fair Value** | **Amounts Offset** | | **Net Assets** | **Gross Fair Value** | **Amounts Offset** | | **Net Liabilities** |
| **September 30, 2025** | | | | | | | | | |
| Current: |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Financial swaps | Other current assets | $106 | $(2) |  | $104 | $2 | $(2) |  | $— |
| &nbsp;&nbsp;&nbsp;&nbsp;Financial swaps | Other current liabilities | 2836 | (2836) |  |  | 20476 | (16421) | <sup>(1)</sup> | 4055 |
| &nbsp;&nbsp;&nbsp;&nbsp;Forward contracts | Other current liabilities |  |  |  |  | 892 |  |  | 892 |
| Long-term: |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Financial swaps | Other liabilities | 1535 | (1535) |  |  | 4788 | (4728) | <sup>(2)</sup> | 60 |
| &nbsp;&nbsp;&nbsp;&nbsp;Forward contracts | Other liabilities |  |  |  |  | 10661 |  |  | 10661 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total |  | $4477 | $(4373) |  | $104 | $36819 | $(21151) |  | $15668 |
| **December 31, 2024** |  |  |  |  |  |  |  |  |  |
| Current: |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Financial swaps | Other current liabilities | 3072 | (3072) |  |  | 18092 | (14931) | <sup>(3)</sup> | 3161 |
| &nbsp;&nbsp;&nbsp;&nbsp;Forward contracts | Other current liabilities |  |  |  |  | 1291 |  |  | 1291 |
| Long-term: |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Financial swaps | Other assets | 1939 | (1939) | <sup>(4)</sup> |  | 409 | (409) |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Financial swaps | Other liabilities | 177 | (177) |  |  | 1019 | (177) |  | 842 |
| &nbsp;&nbsp;&nbsp;&nbsp;Forward contracts | Other liabilities |  |  |  |  | 10965 |  |  | 10965 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total |  | $5188 | $(5188) |  | $— | $31776 | $(15517) |  | $16259 |

---

(1) Current liability derivative amounts offset include $13.6 million of collateral receivable at September 30, 2025.

(2) Long-term liability derivative amounts offset include $3.2 million of collateral receivable at September 30, 2025.

(3) Current liability derivative amounts offset include $11.9 million of collateral receivable at December 31, 2024.

(4) Long-term asset derivative amounts offset include $1.5 million of collateral payable at December 31, 2024.

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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2025 and 2024 (in thousands of units):

---

| | | | |
|:---|:---|:---|:---|
| | | **September 30,** | **September 30,** |
| **Commodity** | **Units** | **2025** | **2024** |
| Electricity purchases | MWh | 208 | 220 |
| Electricity sales | MWh |  | 16 |
| Natural gas purchases | MMBtu | 114725 | 30133 |

---

**13. 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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Level 2: Financial assets and liabilities whose values are based on the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) quoted prices for similar assets or liabilities in active markets;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) quoted prices for identical or similar assets or liabilities in non-active markets;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•&nbsp;&nbsp;&nbsp;&nbsp; Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

IDACORP's and Idaho Power's assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. There were no transfers between levels or material changes in valuation techniques or inputs during the nine months ended September 30, 2025.

Certain instruments have been valued using NAV as a practical expedient. The NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in the fair value disclosures below; however, in accordance with GAAP are not classified within the fair value hierarchy levels.

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The following table presents information about IDACORP's and Idaho Power's assets and liabilities measured at fair value on a recurring basis as of September 30, 2025, and December 31, 2024 (in thousands).

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** | **December 31, 2024** | **December 31, 2024** | **December 31, 2024** | **December 31, 2024** |
| | **Level 1** | **Level 2** | **Level 3** | **Total** | **Level 1** | **Level 2** | **Level 3** | **Total** |
| **Assets:** | | | | | | | | |
| &nbsp;&nbsp;&nbsp;Money market funds and commercial paper | &nbsp;&nbsp;&nbsp;Money market funds and commercial paper |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;IDACORP<sup>(1)</sup> | $129934 | $— | $— | $129934 | $146308 | $— | $— | $146308 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Idaho Power | 137260 |  |  | 137260 | 158999 |  |  | 158999 |
| &nbsp;&nbsp;&nbsp;Derivatives | 104 |  |  | 104 |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Equity securities | 36251 |  |  | 36251 | 39772 |  |  | 39772 |
| &nbsp;&nbsp;IDACORP assets measured at NAV (not subject to hierarchy disclosure)<sup>(1)</sup> |  |  |  | 5989 |  |  |  | 4099 |
| **Liabilities:** |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Derivatives | 4115 | 11553 |  | 15668 | 4003 | 12256 |  | 16259 |

---

(1) Holding company only. Does not include amounts held by Idaho Power.

Idaho Power's derivatives are contracts entered into as part of its management of loads and resources. Electricity swap derivatives are valued on the Intercontinental Exchange (ICE) with quoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forward contract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange (NYMEX) and ICE pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. Equity securities at Idaho Power consist of employee-directed investments related to an executive deferred compensation plan and actively traded money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a rabbi trust.

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value as of September 30, 2025, and December 31, 2024, using available market information and appropriate valuation methodologies (in thousands).

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **September 30, 2025** | **September 30, 2025** | **December 31, 2024** | **December 31, 2024** |
| | **Carrying Amount** | **Estimated Fair Value** | **Carrying Amount** | **Estimated Fair Value** |
| **IDACORP** | | | | |
| &nbsp;&nbsp;&nbsp;**Assets:** | | | | |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Notes receivable<sup>(1)</sup> | $2155 | $2155 | $2155 | $2155 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Held-to-maturity securities<sup>(1)(2)</sup> | 32957 | 31514 | 32151 | 29428 |
| &nbsp;&nbsp;&nbsp;**Liabilities:** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Long-term debt (including current portion)<sup>(1)</sup> | 3447052 | 3299724 | 3073662 | 2807803 |
| **Idaho Power** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;**Assets:** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Held-to-maturity securities<sup>(1)(2)</sup> | $32957 | $31514 | $32151 | $29428 |
| &nbsp;&nbsp;&nbsp;**Liabilities:** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Long-term debt (including current portion)<sup>(1)</sup> | 3447052 | 3299724 | 3073662 | 2807803 |

---

(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 13 - "Fair Value Measurements."

(2) All held-to-maturity securities are carried at amortized cost and were in a gross unrealized holding loss position totaling $1.4 million and $2.7 million as of September 30, 2025, and December 31, 2024, 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, 2025, and December 31, 2024.

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

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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.

**14. 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).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Utility<br>Operations** | **All<br>Other** | **Eliminations** | **Consolidated<br>Total** |
| **Three months ended September 30, 2025:** | | | | |
| &nbsp;&nbsp;&nbsp;Revenues | $523549 | $868 | $— | $524417 |
| &nbsp;&nbsp;&nbsp;Depreciation and amortization | 64493 |  |  | 64493 |
| &nbsp;&nbsp;&nbsp;Other income, net | 19196 | 93 |  | 19289 |
| &nbsp;&nbsp;&nbsp;Interest income including carrying charges on regulatory assets | 8967 | 2678 | (761) | 10884 |
| &nbsp;&nbsp;&nbsp;Earnings of unconsolidated equity-method investments | 996 | 1189 |  | 2185 |
| &nbsp;&nbsp;&nbsp;Interest expense | 44796 | 849 | (761) | 44884 |
| &nbsp;&nbsp;&nbsp;Income tax (benefit) expense | 7321 | 365 |  | 7686 |
| &nbsp;&nbsp;&nbsp;Net income attributable to IDACORP, Inc. | 122156 | 2281 |  | 124437 |
| Expenditures for long-lived assets | 290600 | 123 |  | 290723 |
| Total assets as of September 30, 2025 | 9825112 | 344141 | (93268) | 10075985 |
| **Three months ended September 30, 2024:** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Revenues | $527487 | $1040 | $— | $528527 |
| &nbsp;&nbsp;&nbsp;Depreciation and amortization | 56388 |  |  | 56388 |
| &nbsp;&nbsp;&nbsp;Other income (expense), net | 18828 | (58) |  | 18770 |
| &nbsp;&nbsp;&nbsp;Interest income including carrying charges on regulatory assets | 8558 | 2183 | (854) | 9887 |
| &nbsp;&nbsp;&nbsp;Earnings of unconsolidated equity-method investments | 841 | 1137 |  | 1978 |
| &nbsp;&nbsp;&nbsp;Interest expense | 34061 | 939 | (854) | 34146 |
| &nbsp;&nbsp;&nbsp;Income tax expense (benefit) | 16444 | (86) |  | 16358 |
| &nbsp;&nbsp;&nbsp;Net income attributable to IDACORP, Inc. | 111089 | 2516 |  | 113605 |
| Expenditures for long-lived assets | 218041 | 22 |  | 218063 |
| **Nine months ended September 30, 2025:** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Revenues | $1405173 | $2581 | $— | $1407754 |
| &nbsp;&nbsp;&nbsp;Depreciation and amortization | 185407 |  |  | 185407 |
| &nbsp;&nbsp;&nbsp;Other income (expense), net | 55200 | (144) |  | 55056 |
| &nbsp;&nbsp;&nbsp;Interest income including carrying charges on regulatory assets | 27541 | 8437 | (2275) | 33703 |
| &nbsp;&nbsp;&nbsp;Earnings of unconsolidated equity-method investments | 2150 | 2058 |  | 4208 |
| &nbsp;&nbsp;&nbsp;Interest expense | 124019 | 2610 | (2275) | 124354 |
| &nbsp;&nbsp;&nbsp;Income tax (benefit) expense | (12084) | 624 |  | (11460) |
| &nbsp;&nbsp;&nbsp;Net income attributable to IDACORP, Inc. | 273121 | 6744 |  | 279865 |
| Expenditures for long-lived assets | 825100 | 252 |  | 825352 |
| **Nine months ended September 30, 2024:** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Revenues | $1425606 | $2896 | $— | $1428502 |
| &nbsp;&nbsp;&nbsp;Depreciation and amortization | 165133 |  |  | 165133 |
| &nbsp;&nbsp;&nbsp;Other income (expense), net | 49397 | (191) |  | 49206 |
| &nbsp;&nbsp;&nbsp;Interest income including carrying charges on regulatory assets | 27682 | 5328 | (2418) | 30592 |
| &nbsp;&nbsp;&nbsp;Earnings of unconsolidated equity-method investments | 1936 | 1944 |  | 3880 |
| &nbsp;&nbsp;&nbsp;Interest expense | 99175 | 2668 | (2418) | 99425 |
| &nbsp;&nbsp;&nbsp;Income tax expense (benefit) | 19885 | (1009) |  | 18876 |
| &nbsp;&nbsp;&nbsp;Net income attributable to IDACORP, Inc. | 245779 | 5519 |  | 251298 |
| Expenditures for long-lived assets | 823855 | 114 |  | 823969 |

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**15. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME**

The table below presents changes in components of AOCI, net of tax, during the three months and nine months ended September 30, 2025 and 2024 (in thousands). Items in parentheses indicate charges to AOCI.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Defined benefit pension items |  |  |  |  |
| &nbsp;&nbsp;Balance at beginning of period | $(13481) | $(16616) | $(13592) | $(17184) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other comprehensive income before reclassification |  |  | (229) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Amounts reclassified out of AOCI | 171 | 285 | 511 | 853 |
| &nbsp;&nbsp;Balance at end of period | $(13310) | $(16331) | $(13310) | $(16331) |

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The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three months and nine months ended September 30, 2025 and 2024 (in thousands). Items in parentheses indicate increases to net income.

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Amount Reclassified from AOCI** | **Amount Reclassified from AOCI** | **Amount Reclassified from AOCI** | **Amount Reclassified from AOCI** |
| **Details About AOCI** | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Amortization of defined benefit pension items<sup>(1)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Prior service cost | $55 | $55 | $166 | $165 |
| &nbsp;&nbsp;&nbsp;Net loss | 173 | 329 | 518 | 984 |
| Total before tax | 228 | 384 | 684 | 1149 |
| Tax benefit<sup>(2)</sup> | (57) | (99) | (173) | (296) |
| Total reclassification for the period, net of tax | $171 | $285 | $511 | $853 |

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(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.

**16. CHANGES IN IDAHO POWER RETAINED EARNINGS**

The table below presents changes in Idaho Power retained earnings during the three months and nine months ended September 30, 2025 and 2024 (in thousands).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Balance at beginning of period | $2153655 | $2041364 | $2096151 | $1991319 |
| Net income | 122156 | 111089 | 273121 | 245779 |
| Dividends to parent | (46778) | (44458) | (140239) | (129103) |
| Balance at end of period | $2229033 | $2107995 | $2229033 | $2107995 |

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**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, 2025, the related condensed consolidated statements of income, comprehensive income and equity for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 20, 2025, 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, 2024, 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 30, 2025

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**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, 2025, the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 20, 2025, 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, 2024, 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 30, 2025

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**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 2024 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 2024 Annual Report, IDACORP's and Idaho Power's management included a summary of their business objectives for the companies for 2025 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 some of the discussion in this MD&A. Some notable developments that have occurred since that report include the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Idaho Power continues to focus on timely recovery of costs and earning a reasonable return on investment. In October 2025, Idaho Power reached a settlement stipulation with the IPUC Staff and certain other parties in the Idaho general rate case it filed in May 2025, providing for $110.0 million in additional Idaho-jurisdiction annual revenues, among other items. The settlement stipulation is more fully described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. The IPUC's decision in this matter is pending.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Idaho Power continues to experience and forecast positive customer growth in its service area. During the first nine months of 2025, Idaho Power's customer count grew by over 11,500 customers and for the twelve months ended September 30, 2025, the customer growth rate was 2.3 percent.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• In September 2025, IDACORP's board of directors approved an increase in the regular quarterly cash dividend on IDACORP's common stock from $0.86 per share to $0.88 per share, as a part of a 193 percent increase in quarterly dividends over the last fourteen years.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• To help meet growing capacity and energy needs in 2027 and beyond, Idaho Power entered into the following transactions in 2025, which as of the date of this report remain subject to regulatory approval:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ an agreement to purchase the output of a 100 MW solar facility, coupled with a 100 MW battery energy storage agreement, with a scheduled online date of June 2027;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ an agreement to acquire an ownership interest in 250 MW and for rights to an additional 250 MW of northbound capacity on SWIP-N, a planned 285-mile high-voltage transmission line; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ an agreement to purchase the output of an 80 MW solar facility, with a scheduled online date of June 2027.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• So far in 2025, several key projects achieved notable milestones, underscoring significant progress towards Idaho Power addressing peak capacity and energy needs in 2025 and beyond:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ commenced construction on the B2H transmission line, with an expected in-service date of late 2027;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ a 20-year agreement for Idaho Power to utilize storage capacity from a third-party 150 MW battery storage facility commenced, with the facility fully operational;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ 80 MW of company-owned battery storage facilities came on-line, with another 250 MW of company-owned battery storage commencing construction; and

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Idaho Power filed a CPCN request with the IPUC for a 167 MW expansion of the existing Bennett Mountain natural gas generation facility, with an expected in-service date in 2028.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• In June 2025, Idaho Power filed with the Idaho and Oregon public utility commissions its 2025 IRP, its forecast of load and resources for the next 20 years, including the preferred portfolio of resources necessary to meet predicted demands.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• In September 2025, Idaho Power and the developer of the 600 MW Jackalope Wind project terminated the agreements for the project due to permitting delays and uncertainty around federal land use policies. Accordingly, Idaho Power filed a petition with the IPUC to withdraw the CPCN and approval of the PPA for the project that had previously been approved in June 2025. Idaho Power is pursuing alternative capacity and energy resources to meet the power generation deficit resulting from the termination of these agreements.

**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 for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except earnings per share amounts):

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Idaho Power net income | $122156 | $111089 | $273121 | $245779 |
| Net income attributable to IDACORP, Inc. | $124437 | $113605 | $279865 | $251298 |
| Weighted average outstanding shares – diluted | 55055 | 53485 | 54522 | 52179 |
| IDACORP, Inc. earnings per diluted share | $2.26 | $2.12 | $5.13 | $4.82 |

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The table below provides a reconciliation of net income attributable to IDACORP for the three months and nine months ended September 30, 2025, from the same periods in 2024 (items are in millions and are before related income tax impact unless otherwise noted):

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended** | **Three months ended** | **Nine months ended** | **Nine months ended** |
| **Net income attributable to IDACORP, Inc. - September 30, 2024** |  | $**113.6** |  | $**251.3** |
|  Increase (decrease) in Idaho Power net income: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Retail revenues per MWh, net of power cost adjustment mechanisms | 17.6 |  | 37.2 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Customer growth, net of associated power supply costs and power cost adjustment mechanisms | 7.8 |  | 19.6 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms | (5.7) |  | (0.8) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other O&M expenses | (4.2) |  | (22.5) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation and amortization expense | (8.1) |  | (20.3) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other changes in operating revenues and expenses, net | 4.3 |  | 1.1 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Increase in Idaho Power operating income | 11.7 |  | 14.3 |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Non-operating expense, net | (9.8) |  | (19.0) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Additional ADITC amortization |  |  | 16.5 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Income tax expense, excluding additional ADITC amortization | 9.1 |  | 15.5 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total increase in Idaho Power net income |  | 11.0 |  | 27.3 |
|  Other IDACORP changes (net of tax) |  | (0.2) |  | 1.3 |
| **Net income attributable to IDACORP, Inc. - September 30, 2025** |  | $**124.4** |  | $**279.9** |

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***Net Income - Third Quarter 2025***

IDACORP's net income increased $10.8 million for the third quarter of 2025 compared with the third quarter of 2024, due primarily to higher net income at Idaho Power.

A net increase in retail revenues per MWh, net of power cost adjustment mechanisms, increased operating income by $17.6 million in the third quarter of 2025 compared with the third quarter of 2024. This benefit was due primarily to an overall

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increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. For more information on the 2024 Idaho Limited-Issue Rate Case, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2024 Annual Report.

Customer growth increased operating income by $7.8 million in the third quarter of 2025 compared with the third quarter of 2024, as the number of Idaho Power customers grew by approximately 15,000, or 2.3 percent, during the twelve months ended September 30, 2025. Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms, decreased operating income by $5.7 million in the third quarter of 2025 compared with the third quarter of 2024. Irrigation usage per customer decreased most significantly, as higher precipitation in the third quarter of 2025 compared with the third quarter of 2024 led irrigation customers to use less energy for operating irrigation pumps.

Other O&M expenses in the third quarter of 2025 were $4.2 million higher than the third quarter of 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and an increase in wildfire mitigation program and related insurance expenses.

Depreciation and amortization expense increased $8.1 million in the third quarter of 2025 compared with the third quarter of 2024, due primarily to an increase in plant-in-service. Additionally, the start of operations at a leased battery storage facility in the second quarter of 2025 contributed modestly to the increase through the amortization of a related right-of-use asset.

Other changes in operating revenues and expenses, net, increased operating income by $4.3 million in the third quarter of 2025 compared with the third quarter of 2024, due primarily to a decrease in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms.

Non-operating expense, net, increased $9.8 million in the third quarter of 2025 compared with the third quarter of 2024. Higher long-term debt balances and an increase in transmission customer deposits, on which Idaho Power must pay interest to the customer, led to an increase in interest expense. Interest on a new finance lease also contributed to the increase compared with the third quarter of 2024. This increase was partially offset by an increase in AFUDC in the third quarter of 2025 compared with the third quarter of 2024, as the average construction work in progress balance was higher.

The decrease in income tax expense for the third quarter of 2025, compared with the third quarter of 2024, was primarily due to income tax return adjustments for state taxes and plant-related flow-through items.

***Net Income - Year-To-Date 2025***

IDACORP's net income increased $28.6 million for the first nine months of 2025 compared with the first nine months of 2024, due primarily to higher net income at Idaho Power.

The net increase in retail revenues per MWh, net of power cost adjustment mechanisms, increased operating income by $37.2 million in the first nine months of 2025 compared with the first nine months of 2024. This benefit was due primarily to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case.

Customer growth increased operating income by $19.6 million in the first nine months of 2025 compared with the first nine months of 2024. Overall, usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms, was relatively flat in the first nine months of 2025 compared with the first nine months of 2024.

Total other O&M expenses in the first nine months of 2025 were $22.5 million higher than the first nine months of 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and an increase in wildfire mitigation program and related insurance expenses, as well as higher variable employee compensation based on the expected achievement level of performance-based metrics.

Depreciation and amortization expense increased $20.3 million for the first nine months of 2025 compared with the first nine months of 2024, due primarily to an increase in plant-in-service. Additionally, the start of operations at a leased battery storage facility in the second quarter of 2025 contributed modestly to the increase through the amortization of a related right-of-use asset.

Other changes in operating revenues and expenses, net, increased operating income by $1.1 million in the first nine months of 2025 compared with the first nine months of 2024, due primarily to a decrease in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms, which increased operating

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income compared with the first nine months of 2024. This was partially offset by the timing of recording and adjusting of regulatory accruals and deferrals during the first nine months of 2024 that did not reoccur in 2025.

Non-operating expense, net, increased $19.0 million in the first nine months of 2025 compared with the first nine months of 2024. Higher long-term debt balances and an increase in transmission customer deposits, on which Idaho Power must pay interest to the customer, led to an increase in interest expense. Interest on a new finance lease also contributed to the increase compared with the first nine months of 2024. This increase was partially offset by an increase in AFUDC in the first nine months of 2025 compared with the first nine months of 2024, as the average construction work in progress balance was higher.

The decrease in income tax expense for the first nine months of 2025, compared with the first nine months of 2024, was primarily due to income tax return adjustments for state taxes and plant-related flow-through items as well as a $16.5 million increase in additional ADITC amortization. Based on Idaho Power's current expectations of full-year 2025 financial results, Idaho Power recorded $39.0 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during the first nine months of 2025, compared with $22.5 million of additional ADITC amortization during the same period in 2024.

**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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• ***Regulatory Filings***: The prices that Idaho Power is authorized to charge for its electric and transmission service are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power is focused on timely recovery of its costs through filings with its regulators and prudent management of expenses and investments.

To address the regulatory lag in recovery of costs primarily associated with Idaho Power's current and anticipated significant infrastructure investments, in May 2025 Idaho Power filed a general rate case in Idaho. In October 2025, Idaho Power, the Staff of the IPUC, and several of the intervening parties filed a settlement stipulation with the IPUC related to the 2025 Idaho general rate case filing. The settlement stipulation is subject to approval by the IPUC. The general rate case filing and the settlement stipulation are described more fully in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*•* ***Rate Base Growth and Infrastructure Investment***: The rates established by the IPUC, OPUC, and FERC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on "rate base." Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred income taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation of utility plant and write-offs as authorized by the IPUC and OPUC. Idaho Power is pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and provide service to new customers, including major ongoing transmission projects such as the B2H, GWW, and SWIP-N projects. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company continues a significant relicensing effort for the HCC, its largest hydropower generation resource. Idaho Power is pursuing timely inclusion of completed capital projects into rate base as part of the 2025 general rate case filing and intends to continue to do so in future general rate cases or other appropriate regulatory proceedings.

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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• ***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, 2025, Idaho Power's customer count grew by 2.3 percent. While recessionary or volatile economic conditions could slow the rate of customer growth, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase in the foreseeable future.

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Idaho Power filed its 2025 IRP, its 20-year forecast of load and power supply resource options, with the IPUC and OPUC in June 2025. Included in the below table are the load forecast assumptions the company used in the 2025 IRP and, for comparison purposes, the analogous average annual growth rates Idaho Power used in the prior two IRPs.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **5-Year Forecasted Annual Growth Rate** | **5-Year Forecasted Annual Growth Rate** | **20-Year Forecasted Annual Growth Rate** | **20-Year Forecasted Annual Growth Rate** |
| | **Retail Sales<br>(Billed MWh)** | **Annual Peak<br>(Peak Demand)** | **Retail Sales<br>(Billed MWh)** | **Annual Peak<br>(Peak Demand)** |
| 2025 IRP | 8.3% | 5.1% | 2.7% | 1.9% |
| 2023 IRP | 5.5% | 3.7% | 2.1% | 1.8% |
| 2021 IRP | 2.6% | 2.1% | 1.4% | 1.4% |

---

Customer growth has contributed to increases in peak loads experienced in recent years. For example, Idaho Power's highest all-time winter peak demand of 2,719 MW occurred on January 16, 2024, and on July 22, 2024, Idaho Power reached a new all-time summer peak demand of 3,793 MW. Idaho Power believes that existing and sustained growth in customers, load, and peak demand for electricity, the obligation to maintain a safe and reliable system, along with changes in the regional transmission markets that have constrained the availability of transmission outside Idaho Power's service area to import energy during peak load periods, require Idaho Power to increase its investment in capacity resources, transmission, and distribution infrastructure. This includes the B2H, GWW, and SWIP-N transmission projects, along with other capacity, energy, and transmission resource procurements, described in "Liquidity and Capital Resources" in this MD&A.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*•* ***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 2025, Idaho Power expects generation from its hydropower resources to be in the range of 6.5 million to 7.0 million MWh, compared with actual generation of 7.2 million MWh in 2024 and a 30-year average annual total of approximately 7.7 million MWh.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• ***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.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• ***Regulatory and Environmental Compliance Costs; Coal Plant Retirements***: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Moreover, environmental laws and regulations may increase the cost of constructing new facilities, may increase the cost of operating generation plants, may require that Idaho Power install additional pollution control devices at existing generating plants, may result in penalties for non-compliance, even where inadvertent, or may require that Idaho Power curtail or cease operating certain generation plants. Idaho Power expects to spend significant amounts on environmental compliance and controls for the foreseeable future. Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its North Valmy plant, ceasing participation in coal-fired operations at one unit in 2019 and planning to cease coal-fired operations at the remaining unit by year-end 2025. Idaho Power's jointly-owned coal plant in Boardman, Oregon, ceased operations in October 2020. In 2022, the IPUC approved Idaho Power's request to allow the coal-related assets at the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. Idaho Power's 2025 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of the two units at the North Valmy plant in 2026 and the remaining two units at the Jim Bridger plant in 2030. Units 1 and 2 at the Jim Bridger plant were converted to natural gas in the second quarter of 2024. In June 2024, Idaho Power executed an agreement with its co-owner to facilitate the planned conversion of the two units at the North Valmy plant from coal to natural gas by mid-2026.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;***• Water Management and Relicensing of Hydropower Projects***: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal licenses for the HCC, its largest hydropower generation source, and for American Falls, its second largest hydropower capacity resource. Given the number of parties involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. As of the date of this report, Idaho Power cannot determine the ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls hydropower facilities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• ***Wildfire Mitigation Efforts***: In recent years, the western United States has experienced an increasing number of wildfires of unprecedented severity. A variety of factors have contributed to this trend including increased wildland-urban interfaces, historical land management practices, climate change, and overall wildland and forest health. Idaho Power is taking a proactive approach to wildfire risk in its service area and transmission corridors. Idaho Power has developed and adopted a WMP that outlines actions Idaho Power is taking or is working to implement to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires. 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 2024 Annual Report and the condensed consolidated financial statements included in this report. In July 2025, the Idaho Wildfire Standard of Care Act became effective. In October 2025, Idaho Power filed a new WMP with the IPUC in accordance with the Act. As of the date of this report, the IPUC's decision is pending. See "Other Matters - Idaho Wildfire Standard of Care Act" for additional detail.

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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, 2025. In this analysis, the results for the three months and nine months ended September 30, 2025, are compared with the same periods in 2024.

The table below presents Idaho Power's energy sales and supply (in thousands of MWh) for the three months and nine months ended September 30, 2025 and 2024.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Retail energy sales | 4854 | 4854 | 12677 | 12355 |
| Wholesale energy sales | 193 | 126 | 1230 | 1355 |
| Energy sales bundled with renewable energy credits | 26 |  | 641 | 959 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total energy sales** | 5073 | 4980 | 14548 | 14669 |
| Hydropower generation | 1483 | 1598 | 5751 | 6008 |
| Steam generation<sup>(1)</sup> | 1046 | 1080 | 2183 | 1896 |
| Natural gas and other generation | 1276 | 1261 | 2802 | 2822 |
| &nbsp;&nbsp;&nbsp;**Total system generation** | 3805 | 3939 | 10736 | 10726 |
| Purchased power | 1641 | 1375 | 4849 | 4902 |
| Line losses | (373) | (334) | (1037) | (959) |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total energy supply** | 5073 | 4980 | 14548 | 14669 |

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(1) "Steam generation" is composed of generation from steam plants that are fueled by only coal or by both coal and natural gas.

Weather-related information for Boise, Idaho, for the three months and nine months ended September 30, 2025 and 2024, 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.

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **Normal** <sup>(2)</sup> | **2025** | **2024** | **Normal** <sup>(2)</sup> |
| Heating degree-days<sup>(1)</sup> | 7 | 47 | 94 | 2989 | 2951 | 3181 |
| Cooling degree-days<sup>(1)</sup> | 967 | 1147 | 847 | 1248 | 1419 | 1035 |
| Precipitation (inches) | 1.7 | 0.3 | 0.8 | 8.1 | 11.2 | 8.0 |

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(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 were flat in the third quarter of 2025 compared with the same period in 2024. This was primarily due to growth in the number of Idaho Power customers, which was mostly offset by a decrease in usage per customer in all customer classes. Greater precipitation and moderate temperatures in Idaho Power's service area during the third quarter of 2025, compared with the third quarter of 2024, led irrigation customers to operate irrigation pumps less. Residential and commercial customers also used less energy per customer for cooling purposes compared to the same period in 2024, contributing to the lower volumes. Retail sales volumes increased 3 percent in the first nine months of 2025 compared with the same period in 2024, primarily due to 2.3 percent growth in the number of Idaho Power customers over the prior twelve months. For more information on the changes in sales volume, see the "Operating Revenues" section below in this MD&A.

Total system generation decreased 3 percent for the third quarter of 2025 compared with the third quarter of 2024, due primarily to lower hydropower generation and steam generation, offset partially by an increase in natural gas generation. Total

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system generation increased slightly in the first nine months of 2025 compared with the same period in 2024, which consists of an increase in steam generation, partially offset by decreased hydropower generation and natural gas generation. For more information on the changes in generation, see the "Operating Expenses" section below in this MD&A.

The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms."

**Operating Revenues**

***Retail Revenues:*** The table below presents Idaho Power's retail revenues (in thousands) and MWh sales volumes (in thousands) for the three months and nine months ended September 30, 2025 and 2024, and the number of customers as of September 30, 2025 and 2024.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Retail revenues: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Residential (includes $(4125), $(6193), $(9194), and $(8982), respectively, related to the FCA)<sup>(1)</sup> | $195445 | $195291 | $535505 | $525353 |
| &nbsp;&nbsp;&nbsp;&nbsp; Commercial (includes $(70), $(66), $(150), and $(158), respectively, related to the FCA)<sup>(1)</sup> | 111510 | 112323 | 304014 | 303031 |
| &nbsp;&nbsp;&nbsp;&nbsp; Industrial | 72079 | 71908 | 205526 | 203990 |
| &nbsp;&nbsp;&nbsp;&nbsp; Irrigation | 101690 | 109861 | 195172 | 191671 |
| &nbsp;&nbsp;&nbsp;&nbsp; Deferred revenue related to HCC relicensing AFUDC<sup>(2)</sup> | (2854) | (2881) | (6848) | (6913) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail revenues | $477870 | $486502 | $1233369 | $1217132 |
| Volume of retail sales (MWh) |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Residential | 1621 | 1596 | 4593 | 4451 |
| &nbsp;&nbsp;&nbsp;&nbsp; Commercial | 1191 | 1182 | 3302 | 3262 |
| &nbsp;&nbsp;&nbsp;&nbsp; Industrial | 984 | 954 | 2817 | 2744 |
| &nbsp;&nbsp;&nbsp;&nbsp; Irrigation | 1058 | 1122 | 1965 | 1898 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail MWh sales | 4854 | 4854 | 12677 | 12355 |
| Number of retail customers at period end |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Residential | 557065 | 543520 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Commercial | 80707 | 79328 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Industrial | 150 | 145 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Irrigation | 22620 | 22549 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total customers | 660542 | 645542 |  |  |

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(1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers.

(2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Effective October 1, 2025, this amount will increase by $29.7 million annually; refer to Note 3 - "Regulatory Matters."

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 decreased $8.6 million during the third quarter of 2025, compared with the same period in 2024. Retail revenues increased $16.2 million during the first nine months of 2025, compared with the same period in 2024. The factors affecting retail revenues during the periods are discussed below.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• <u>Rates</u>: Customer rates, excluding revenues related to power cost adjustment mechanisms, increased retail revenues by $17.6 million and $37.2 million, respectively, for the three months and nine months ended September 30, 2025, compared with the same periods in 2024, due primarily to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which decreased revenues by $27.7 million and $51.2 million, in the third quarter and first nine months of 2025, respectively, compared with the same periods of 2024. 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• <u>Customers</u>: Customer growth of 2.3 percent during the twelve months ended September 30, 2025, increased retail revenues by $12.4 million and $30.4 million in the third quarter and first nine months of 2025, respectively, compared with the same periods of 2024.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• <u>Usage</u>: Lower usage (on a per customer basis), in all customer classes decreased retail revenues by $12.9 million in the third quarter of 2025 compared with the same period of 2024, primarily due to weather variations that caused lower usage per customer. Greater precipitation and more moderate temperatures in Idaho Power's service area during the third quarter of 2025 led agricultural irrigation customers to use less energy per customer to operate irrigation pumps and residential and commercial customers to use less energy per customer for cooling purposes compared with the same period in 2024. During the first nine months of 2025, usage in all customer classes was relatively flat, compared with the same period of 2024.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• <u>FCA Mechanism</u>: A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $2.1 million in the third quarter of 2025 compared with the same period in 2024. Conversely, an increase in the deferral of residential and small commercial customer revenues through the FCA mechanism negatively affected retail revenues by $0.2 million during the first nine months of 2025 compared with the same period in 2024.

***Wholesale Energy Sales:*** Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the energy imbalance market in the western United States, and do not include derivative transactions. The table below presents Idaho Power's wholesale energy sales for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except for revenue per MWh amounts).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Wholesale energy revenues | $10520 | $6946 | $45443 | $65759 |
| Wholesale MWh sold | 193 | 126 | 1230 | 1355 |
| Wholesale energy revenues per MWh | $54.51 | $55.13 | $36.95 | $48.53 |

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In the third quarter of 2025, wholesale energy revenues increased $3.6 million compared with the same period of 2024, due primarily to an increase in wholesale energy volumes sold. Wholesale energy revenues decreased $20.3 million in the first nine months of 2025, due primarily to lower wholesale market prices compared with 2024. Wholesale energy prices were lower during the third quarter and first nine months of 2025 compared with 2024 as more moderate winter and summer weather resulted in lower power prices in the wholesale markets in the region. 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 for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except for per MWh amounts).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Purchased power expense | $121276 | $114578 | $284163 | $321860 |
| MWh purchased | 1641 | 1375 | 4849 | 4902 |
| Average cost per MWh | $73.90 | $83.33 | $58.60 | $65.66 |

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Purchased power expense increased $6.7 million, or 6 percent, during the third quarter of 2025 compared with the third quarter of 2024, primarily due to a 19 percent increase in MWh purchased to help meet customer demand. Purchased power expense decreased $37.7 million, or 12 percent, during the first nine months of 2025, compared with the same period of 2024, primarily due to lower wholesale energy market prices in the region.

***Fuel Expense:*** The table below presents Idaho Power's fuel expenses and thermal generation for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except for per MWh amounts).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Fuel Expense |  |  |  |  |
| &nbsp;&nbsp;Steam<sup>(1)</sup> | $37350 | $33145 | $85082 | $74554 |
| &nbsp;&nbsp;Natural gas<sup>(2)</sup> | 37642 | 40326 | 94156 | 113857 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total fuel expense | $74992 | $73471 | $179238 | $188411 |
| MWh generated |  |  |  |  |
| &nbsp;&nbsp;Steam<sup>(1)</sup> | 1046 | 1080 | 2183 | 1896 |
| &nbsp;&nbsp;Natural gas<sup>(2)</sup> | 1276 | 1261 | 2802 | 2822 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total MWh generated | 2322 | 2341 | 4985 | 4718 |
| Average cost per MWh - Steam | $35.71 | $30.69 | $38.97 | $39.32 |
| Average cost per MWh - Natural gas | $29.50 | $31.98 | $33.60 | $40.35 |
| Weighted average, all sources | $32.30 | $31.38 | $35.96 | $39.93 |

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(1) "Steam" is composed of expenses and generation from steam plants that are fueled by only coal or by both coal and natural gas.

(2) Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant.

The majority of the fuel for Idaho Power's jointly-owned 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 increased $1.5 million, or 2 percent, in the third quarter of 2025, but decreased $9.2 million, or 5 percent, in the first nine months of 2025 compared with the same periods of 2024. The increase in fuel expense in the third quarter of 2025 compared with the third quarter of 2024 was primarily due to a 3 percent increase in the total average cost per MWh from all sources and partially offset by a 1 percent decrease in MWh generated from steam and natural gas generation. The decrease in fuel expense in the first nine months of 2025 compared with the same period of 2024, was primarily due to a 10 percent decrease in the total average cost per MWh from all sources and partially offset by a 6 percent increase in MWh generated from steam and natural gas generation to serve load compared with the same period in 2024.

Included in fuel expense are losses and gains on settled financial gas hedges entered into in accordance with Idaho Power's energy risk management policy. For the third quarters of 2025 and 2024, and the first nine months of 2025 and 2024, losses on

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financial gas hedges of $9.1 million and $18.4 million, and $21.9 million and $43.4 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.

***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, battery storage leases, 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 for the three months and nine months ended September 30, 2025 and 2024 (in thousands).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Three months ended<br>September 30,** | **Three months ended<br>September 30,** | **Nine months ended <br>September 30,** | **Nine months ended <br>September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| Idaho power supply cost (deferral) accrual | $(2002) | $(6759) | $46935 | $26761 |
| Oregon power supply cost (deferral) accrual | (523) | 118 | (2317) | 2471 |
| Amortization of prior year authorized balances | (15770) | 27420 | 13349 | 73065 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total power cost adjustment (income statement) | $(18295) | $20779 | $57967 | $102297 |

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The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. During the third quarter of 2025, higher purchased power and fuel costs led to higher actual power supply costs compared with the forecasted amount, which resulted in a deferral of power supply costs by the mechanism. During the first nine months of 2025, purchased power costs led to lower actual power supply costs compared with the forecasted amount, which resulted in an accrual of power supply costs by the mechanism. 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 $4.2 million and $22.5 million in the third quarter and first nine months of 2025, respectively, compared with the same periods of 2024. These increases were primarily driven by inflationary pressures on labor-related costs, professional services, an increase in wildfire mitigation program and related insurance expenses, as well as higher variable employee compensation based on the expected achievement level of performance-based metrics.

**Income Taxes**

IDACORP's and Idaho Power's income tax expense decreased $30.3 million and $32.0 million, respectively, for the nine months ended September 30, 2025, when compared with the same period in 2024, primarily due to income tax return adjustments for state taxes and plant-related flow-through items, and increased 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 2024 Annual Report. 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.

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**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 operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators.

As of October 24, 2025, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• their respective $100 million and $400 million revolving credit facilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• IDACORP's shelf registration statement filed with the SEC on February 21, 2025, which may be used for the issuance of debt securities and common stock, including a remaining aggregate gross sales price of up to $155 million in shares of IDACORP common stock available for issuance through its ATM offering program;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• IDACORP's executed FSAs under its ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of October 24, 2025, would have been approximately $144 million;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• IDACORP's FSAs, independent of the ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of October 24, 2025, would have been approximately $562 million; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Idaho Power's shelf registration statement filed with the SEC on February 21, 2025, which may be used for the issuance of first mortgage bonds and other debt securities; $500 million remains available for issuance pursuant to state regulatory authority.

IDACORP uses original issuances of shares for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and also intends to use original issuances for share purchases within the Idaho Power Company Employee Savings Plan beginning in the fourth quarter of 2025. IDACORP may discontinue using original issuances of shares for these plans at any time.

During 2025, IDACORP executed FSAs under its ATM offering program with various counterparties at an aggregate gross sales price of $52 million. Additionally, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties at an aggregate gross sales price of $575 million. For more detailed information about IDACORP's equity transactions, see below in this MD&A and Note 6 - "Common Stock" to the condensed consolidated financial statements included in this report.

Further, during 2025, Idaho Power issued $400 million in first mortgage bonds and repaid approximately $20 million in maturing variable rate 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.

The proceeds from these issuances of common stock and first mortgage bonds are expected to be used for general corporate purposes, including funding Idaho Power's capital projects.

IDACORP and Idaho Power monitor capital markets with a view toward favorable debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue first mortgage bonds or other debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. IDACORP may also elect to issue common stock, from time to time, under its ATM offering program, depending on market conditions and capital needs. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness.

Based on planned capital expenditures and other O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during at least the next twelve months and thereafter for the foreseeable future with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing credit facilities, access to commercial paper, short-term and long-term debt markets, and equity issuances.

IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent equity. Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of September 30, 2025, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, with no impact to equity from unsettled FSAs, were as follows:

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| | | |
|:---|:---|:---|
| | **IDACORP** | **Idaho Power** |
| Debt | 52% | 54% |
| Equity | 48% | 46% |

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IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.

At September 30, 2025, 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 2025.

**Operating Cash Flows**

IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, income taxes, and plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level currently allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.

IDACORP's and Idaho Power's operating cash inflows for the nine months ended September 30, 2025, were $464 million and $465 million, respectively, an increase in cash flows from operations of $6 million for IDACORP and a decrease of $5 million for Idaho Power, when compared with the same period in 2024. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from the operating cash flows from Idaho Power. Significant items that affected the companies' operating cash flows in the first nine months of 2025 when compared with the same period in 2024 were as follows:

• a $28 million and $27 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 $32 million;

• changes in deferred taxes and taxes accrued and receivable combined to decrease operating cash flows for IDACORP and Idaho Power by $18 million and $8 million, respectively; and

• changes in working capital balances due primarily to timing, including fluctuations as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ the timing of collections of accounts receivable and unbilled receivables decreased operating cash flows by $31 million for IDACORP and $33 million for Idaho Power;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ the changes in prepayments increased operating cash flow by $4 million for IDACORP and Idaho Power, which was primarily due to the timing of insurance prepayments;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ the changes in materials, supplies, and fuel stock increased operating cash flows by $67 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ the changes in accounts and wages payable decreased operating cash flows by $17 million for Idaho Power, which was primarily due to intercompany tax payments; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ the changes in other assets and liabilities decreased operating cash flows by $27 million for IDACORP and Idaho Power. This decrease was primarily related to the timing of refundable transmission network upgrade deposits and a power purchase agreement security deposit.

**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, 2025, were $731 million and $717 million, respectively, decreasing cash outflow by $26 million for IDACORP and by $37 million for Idaho Power when compared with the same period in 2024. Investing cash outflows for 2025 and 2024 were primarily for construction of utility infrastructure needed to address Idaho Power's customer growth and peak resource needs, aging plant and equipment, and environmental and regulatory compliance requirements.

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Investing cash outflows were partially offset in 2025 and 2024 by reimbursements from a B2H project joint permitting participant relating to a portion of the permitting expenditures.

**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, 2025, were $231 million and $230 million, respectively, a decrease of $168 million and $138 million for IDACORP and Idaho Power, respectively, when compared with the same period in 2024. IDACORP and Idaho Power financing cash inflows for 2025 were primarily related to Idaho Power's net proceeds from the issuance of first mortgage bonds, partially offset by the repayment of variable rate bonds and dividend payments. IDACORP and Idaho Power financing cash inflows for 2024 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 dividend payments. 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:*** In March 2025, IDACORP executed FSAs under its ATM offering program with various counterparties, at an aggregate gross sales price of $52 million. IDACORP did not execute any FSAs or otherwise issue shares under the ATM offering program after March 2025. At September 30, 2025, IDACORP's cumulative aggregate gross sales price of executed and outstanding FSAs under its ATM offering program was $145 million, and $155 million in shares of IDACORP's common stock remained available for issuance. If IDACORP had elected to physically settle the FSAs under its ATM offering program as of October 24, 2025, by delivering shares of common stock, cash proceeds would have been approximately $144 million. IDACORP may settle the FSAs under its ATM offering program at any time, up to their respective maturity dates, of approximately one year following execution.

In May 2025, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties at an aggregate gross sales price of $575 million. If IDACORP had elected to physically settle these FSAs as of October 24, 2025, by delivering shares of common stock, cash proceeds would have been approximately $562 million. IDACORP may settle these FSAs at any time, up to 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 February and March 2024, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. At September 30, 2025, $500 million remained available for debt issuance under the regulatory orders. For more detailed information about Idaho Power First Mortgage Bonds, see Note 5 - "Long-term Debt" to the condensed consolidated financial statements included in this report.

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**Available Short-Term Borrowing Liquidity**

The table below outlines available short-term borrowing liquidity as of the dates specified (in thousands).

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| | | | | |
|:---|:---|:---|:---|:---|
| | **September 30, 2025** | **September 30, 2025** | **December 31, 2024** | **December 31, 2024** |
| | **IDACORP**<sup>(2)</sup> | **Idaho Power** | **IDACORP**<sup>(2)</sup> | **Idaho Power** |
| Revolving credit facility | $100000 | $400000 | $100000 | $400000 |
| Commercial paper outstanding |  |  |  |  |
| Identified for other use<sup>(1)</sup> |  |  |  | (19885) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net balance available | $100000 | $400000 | $100000 | $380115 |

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(1) American Falls bonds that Idaho Power could have been required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds had been unable to sell the bonds to third parties. The American Falls bonds were repaid in full on February 3, 2025.

(2) Holding company only.

On October 24, 2025, IDACORP and Idaho Power had no loans outstanding under their 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. There have been no changes to IDACORP's or Idaho Power's ratings by Standard & Poor's Ratings Services or Moody's Investors Service from those included in the 2024 Annual Report. However, any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.

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 $799 million during the nine months ended September 30, 2025. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2025 (including amounts incurred to-date) through 2029 (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. Given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table. The timing and amount of actual constructed projects and capital expenditures could be affected by Idaho Power's ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, permitting, legal processes, regulatory determinations, inflationary pressures, macroeconomic conditions, tariffs, or other issues, including those described below.

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| | | | |
|:---|:---|:---|:---|
| | **2025** | **2026** | **2027-2029** |
| Expected capital expenditures (excluding AFUDC), in billions of dollars | $1.00-$1.10 | $1.25-$1.35 | $3.10-$3.60 |

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***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 2024 Annual Report. The discussion below should be read in conjunction with that report.

<u>Resource Additions to Address Projected Energy and Capacity Deficits</u>: Idaho Power's existing and sustained growth in customers, load, and peak demand for electricity, along with transmission constraints, has created the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs over the next several years. To help meet peak needs in 2025 and beyond, Idaho Power:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• entered into contracts or plans to purchase, own, and operate 330 MW of battery storage assets with expected useful lives of approximately 20 years;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• entered into two 20-year agreements to purchase the storage capacity from battery storage facilities totaling 250 MW;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• entered into five PPAs for the combined 825 MW output of planned third-party solar facilities. Idaho Power plans to sell the output of three of these solar PPAs totaling 645 MW exclusively to a large industrial customer pursuant to an agreement under Idaho Power's Clean Energy Your Way program; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• submitted an application to the IPUC for a CPCN for an expansion of generating capacity at the existing Bennett Mountain power plant of up to 167 MW of natural gas-fueled generation in 2028.

The capital requirements table above includes capital expenditures of more than $730 million from 2025 through 2029 for resource additions to address projected energy and capacity deficits in those years and beyond. 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.

<u>B2H Transmission Line</u>: The B2H line, a planned 300-mile, high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, will 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 transmission line will be in service by late 2027.

As more fully described in the 2024 Annual Report, Idaho Power's ownership interest in the project is approximately 45 percent. Idaho Power has spent approximately $578 million, including Idaho Power's AFUDC, on the B2H project through September 30, 2025. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $300 million in reimbursement as of September 30, 2025, from project co-participants for their share of costs and continues to receive reimbursement as costs are incurred. PacifiCorp is obligated to reimburse Idaho Power for its share of any future project expenditures incurred by Idaho Power under the terms of the joint funding agreement. Idaho Power and PacifiCorp operate under a construction funding agreement filed with the FERC.

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, two parties filed complaints with the OPUC seeking reconsideration of the CPCN granted for B2H. OPUC's case to address these complaints is in its initial stages and remains pending as of the date of this report.

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 $500 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining material procurement and construction of the project. Actual construction costs could differ from Idaho Power's estimates based upon Idaho Power's or its contractors' ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, tariffs, macroeconomic conditions, or other issues.

<u>GWW Transmission Line</u>: Idaho Power and PacifiCorp are pursuing the joint development of the GWW project, a high-voltage transmission line project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho. In 2012, Idaho Power and PacifiCorp entered into a joint funding agreement for permitting of the project.

The permitting phase of the GWW project was subject to review and approval of the Bureau of Land Management (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 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho. Current permitting and pre-construction activities are focused on Segment 8, the section of line between the Hemingway substation and the Midpoint substation near Jerome, Idaho. Idaho Power's ownership interest in Segment 8 is 99 percent. Idaho Power expects the in-service date for this section of line or a portion of this section will be no earlier than 2028. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs including potentially modifying the ownership structure of a few segments of the project.

Idaho Power has expended approximately $84 million, including Idaho Power's AFUDC, for its share of the project through September 30, 2025. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and Segment 8 construction) to be between $900 million and $1.1 billion, including Idaho Power's AFUDC. The estimated cost range is based on assumptions about Idaho Power participation levels in the construction of certain project segments, and any changes in those assumptions or in Idaho Power's actual participation could affect future estimates and actual project costs. The capital requirements table above includes approximately $615 million of Idaho Power's share of estimated

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costs (excluding AFUDC), based on Idaho Power's current estimate that it may commence construction of applicable segments during that time period. Actual construction costs could differ from Idaho Power's estimates based upon the ability of Idaho Power, PacifiCorp, or their respective contractors to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, tariffs, macroeconomic conditions, or other issues.

<u>SWIP-N Transmission Line</u>: In February 2025, Idaho Power entered into a commitment to become a partial owner of SWIP-N, a planned 285-mile high-voltage transmission line between the Robinson Summit Substation near Ely, Nevada, and the Midpoint Substation near Jerome, Idaho. Upon the project being placed into service, the applicable agreements provide that Idaho Power will purchase an approximate 11 percent ownership interest in the project, entitling Idaho Power to approximately 11 percent of the total capacity of the SWIP-N line. In addition, Idaho Power entered into a capacity entitlement agreement entitling Idaho Power to approximately 11 percent of additional capacity on the SWIP-N line over a 40-year term commencing upon the project being placed in service. Idaho Power expects construction of the project to commence in 2026 and take approximately two years to complete. Idaho Power is responsible for approximately 11 percent of the total costs to develop and construct the project. The capital requirements table above includes Idaho Power's share of the costs to develop and construct the project. The project agreements do not require Idaho Power to incur any costs to purchase its ownership interest or begin paying for capacity under the capacity entitlement agreement until the line is in service. Idaho Power has an option to purchase the ownership interest associated with such capacity entitlement upon expiration of the 40-year term.

<u>Jackalope Wind Project</u>: In October 2024, Idaho Power entered into agreements with a counterparty and certain of its affiliates to develop the Jackalope Wind Project, which consisted of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying a capacity of approximately 300 MW of generation to Idaho Power's system from a wind-powered generation facility located in Sweetwater County, Wyoming, and (ii) a co-located wind turbine generator power plant to be owned by Idaho Power, providing a capacity of 300 MW of generation. In September 2025, due to permitting delays and uncertainty around federal land use policies, Idaho Power, the counterparty, and the applicable affiliates of the counterparty terminated the agreements for the Project.

**Defined Benefit Pension Plan Contributions**

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2025, and during the nine months ended September 30, 2025, 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, 2025, 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 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 2024 Annual Report.

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**REGULATORY MATTERS**

**Introduction** 

Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, the OPUC, and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities. As a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its Open Access Transmission Tariff (OATT). Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability, among other items.

Idaho Power develops its regulatory filings taking into consideration short-term and long-term needs for rate relief and several other factors that can affect the structure and timing of those filings. These factors include in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates, as well as other factors.

In 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. In 2024, Idaho Power filed a limited-issue rate case in Idaho, the 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 May 2025, Idaho Power filed a general rate case in Idaho, requesting rates to be effective on or after January 1, 2026. The 2025 Settlement Stipulation was filed for that rate case on October 24, 2025. Refer to Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report for additional information regarding the Idaho general rate case filing and the 2025 Settlement Stipulation. 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 2024 Annual Report for additional information relating to the 2023 Idaho general rate case, 2024 Idaho Limited-Issue Rate Case, and Oregon general rate case.

Between general rate cases, Idaho Power relies upon customer growth, an FCA mechanism, power cost adjustment mechanisms, tariff riders, limited-issue rate proceedings, 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 2024 Annual Report. In addition to the discussion below, which includes notable regulatory developments since the discussion of these matters in the 2024 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 2025, Idaho Power received orders authorizing the rate or revenue changes summarized in the table below.

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| | | | |
|:---|:---|:---|:---|
| **Description** | **Status** | **Estimated Impact**<sup>(1)</sup> | **Notes** |
| PCA - Idaho | New PCA rate became effective June 1, 2025 | $94.8 million PCA decrease for the period from June 1, 2025 to May 31, 2026 | 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 decrease primarily reflects a decrease in the balancing adjustment, which is due primarily to the completed recovery of the 2023 balancing adjustment, which was recovered over two years. |
| FCA - Idaho | New FCA rate became effective June 1, 2025 | $39.8 million FCA decrease for the period from June 1, 2025 to May 31, 2026 | 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, 2025 | $1.8 million APCU decrease for the period from June 1, 2025 to May 31, 2026 | The rate decrease reflects a decrease in expected net power supply expense for the March 2025 APCU forecast combined with an increase in normalized net power supply expense for the October 2024 APCU. |
| HCC - Idaho | New rates became effective October 1, 2025 | $29.7 million increase, effective October 1, 2025 | The requested adjustment increases cash collection of AFUDC associated with relicensing of the HCC project. |

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(1) The annual amount collected in rates is typically not recovered on a straight-line basis (i.e., 1/12th per month), and is instead recovered in proportion to retail sales volumes.

**Idaho Earnings Support and Sharing from Idaho Settlement Stipulations**

The 2018 Settlement Stipulation and the 2023 Settlement Stipulation are each described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2024 Annual Report. The 2023 Settlement Stipulation modified the 2018 Settlement Stipulation in part. IDACORP and Idaho Power believe that the terms allowing additional amortization of ADITC 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 2025 Idaho ROE, in the third quarter and first nine months of 2025, Idaho Power recorded $2.5 million and $39.0 million, respectively, in additional ADITC amortization under the settlement stipulations. If approved by the IPUC, the 2025 Settlement Stipulation would modify the Idaho earnings support and sharing components as described in Note 3 – "Regulatory Matters" to the condensed consolidated financial statements included in this report.

**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, battery storage leases, 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 deferred (accrued) net power supply costs during the nine months ended September 30, 2025 (in millions).

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| | | | |
|:---|:---|:---|:---|
| | **Idaho** | **Oregon** | **Total** |
| Balance at December 31, 2024 | $18.5 | $(3.9) | $14.6 |
| &nbsp;&nbsp;&nbsp;Current period net power supply costs (accrued) deferred | (50.4) | 2.3 | (48.1) |
| &nbsp;&nbsp;&nbsp;Prior amounts (collected) refunded through rates | (14.1) | 0.8 | (13.3) |
| &nbsp;&nbsp;&nbsp;Renewable energy credit sales | (28.2) | (1.2) | (29.4) |
| &nbsp;&nbsp;&nbsp;Interest and other | (1.8) | 0.1 | (1.7) |
| Balance at September 30, 2025 | $(76.0) | $(1.9) | $(77.9) |

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**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 September 2025, Idaho Power filed its 2025 final transmission rate with the FERC, reflecting a transmission rate of $34.16 per kilowatt-year (kW-year), to be effective for the period from October 1, 2025, to September 30, 2026. Idaho Power's final rate was based on a net annual transmission revenue requirement of $148.5 million. The OATT rate in effect from October 1, 2024, to September 30, 2025, was $31.55 per kW-year based on a net annual transmission revenue requirement of $137.9 million. A kW-year is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours.

**Integrated Resource Plan and Resource Procurement Filings**

Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2025, which identified the need for significant resources to meet projected capacity deficits in the near-term.

In August 2024, the OPUC issued an order approving Idaho Power's final RFP to procure resources for its anticipated energy and capacity needs in 2028 and beyond. Idaho Power issued the RFP in August 2024 soliciting resources with a commercial operation date (COD) no later than April 1, 2028 (2028 bids), as well as bids with a COD after April 1, 2028. In March 2025, the OPUC acknowledged the final shortlist of 2028 bids, subject to certain conditions. In July 2025, Idaho Power filed a request for acknowledgement from the OPUC for the final shortlist of bids with a COD no later than June 1, 2029 (2029 bids). Bids from Idaho Power are included in the final shortlist of 2029 bids. In August 2025, the OPUC acknowledged the final shortlist of 2029 bids, subject to certain conditions.

In December 2024, Idaho Power filed an application with the IPUC for the Jackalope Wind Project, consisting of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying a capacity of 300 MW of generation to Idaho Power's system, and (ii) a wind turbine generator power plant to be owned by Idaho Power, providing a capacity of 300 MW of generation. In its application, Idaho Power requested that the IPUC approve the PPA and grant a CPCN for the wind turbine generator power plant. In June 2025, the IPUC approved the PPA and granted the CPCN. However, due to the termination of the agreements for the Jackalope Wind Project following a delay in the planned commercial operation date of the Project, in September 2025, Idaho Power filed a petition with the IPUC to withdraw the CPCN and approval of the PPA for the Project. As of the date of this report, the IPUC's decision is pending.

Also in December 2024, Idaho Power filed an application with the IPUC to grant a CPCN for Idaho Power to acquire and own two battery storage facilities with a total of 100 MW of operating capacity to address Idaho Power's identified capacity deficiency in 2026. In October 2025, the IPUC granted the CPCN.

In March 2025, Idaho Power filed an application with the IPUC to grant a CPCN for Idaho Power to acquire an ownership interest, including the rights to 250 MW of northbound capacity, in SWIP-N, a planned 285-mile, high-voltage transmission line between the Robinson Summit Substation near Ely, Nevada, and the Midpoint Substation near Jerome, Idaho. In its application, Idaho Power also requested that the IPUC approve the company's utilization of an additional 250 MW of rights to northbound capacity on SWIP-N. As of the date of this report, the case remains pending.

In March 2025, Idaho Power filed an application with the IPUC for an order (1) approving the 20-year PPA with Crimson Orchard Solar LLC supplying 100 MW of output to Idaho Power, (2) approving the 20-year energy storage agreement (ESA) with Crimson Orchard Solar for 100 MW of dispatchable energy storage capacity, and (3) acknowledging the lease accounting necessary to facilitate the transaction and that the resulting expenses associated with both the PPA and the ESA are prudently

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incurred for ratemaking purposes. In August 2025, Idaho Power also filed with the IPUC for approval of amendments to the PPA and ESA for Crimson Orchard Solar. As of the date of this report, the IPUC's decision is pending.

In September 2025, Idaho Power filed an application with the IPUC for an order (1) approving the 25-year PPA with Blacks Creek Energy Center, LLC supplying 80 MW of output to Idaho Power and (2) acknowledging that the resulting expenses associated with the PPA are prudently incurred for ratemaking purposes. As of the date of this report, the case remains pending.

In September 2025, Idaho Power filed an application with the IPUC for a CPCN for the expansion of Idaho Power's existing Bennett Mountain power plant to include the addition of a natural gas-fueled facility providing up to 167 MW of generation to meet an identified capacity deficit in 2028, as well as confirmation and approval by the IPUC of Idaho Power's accrual of AFUDC in connection with the expansion. As of the date of this report, the case remains pending.

**Large Customer Rate Proceedings**

In December 2024, Idaho Power filed an application with the IPUC for approval of a special contract for electric service for Micron Idaho Semiconductor Manufacturing (Triton) LLC, a subsidiary of Micron Technology, Inc. (Micron), for electric service for Micron's new memory manufacturing fabrication complex located in Boise, Idaho. The special contract anticipates a significant increase in load on Idaho Power's system that will ramp over a number of years beginning in 2026. As of the date of this report, the case remains pending.

**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 2024 Annual Report in Part II, Item 7 - MD&A – "Liquidity and Capital Resources" and "Regulatory Matters," in July 2020, Idaho Power submitted to the FERC its supplement to the final license application, incorporating the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications. The supplement included feedback on proposed modifications of the 2007 final environmental impact statement (EIS) for the HCC, as well as an updated cost analysis of the HCC and a request that the FERC issue a 50-year license and initiate a supplemental NEPA process at the FERC. In June 2022, the FERC issued a notice of intent to prepare a supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the U.S. Fish and Wildlife Service and the National Marine Fisheries Service under section 7 of the ESA. In April 2025, the FERC issued an updated schedule for the supplemental EIS with target dates for issuance of the draft and final supplemental EIS of September 2025 and May 2026, respectively. As of the date of this report, the FERC has not issued the draft supplemental EIS.

Relicensing costs of $526 million (including AFUDC) for the HCC were included in construction work in progress at September 30, 2025. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $38.5 million of AFUDC annually relating to 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, 2025, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $269 million. As discussed above, in March 2025, Idaho Power filed an application with the IPUC to increase the annual cash collection of AFUDC associated with relicensing of the HCC project from $8.8 million to $38.5 million. In September 2025, the IPUC approved Idaho Power's proposed increase in annual cash collection to recover AFUDC associated with relicensing of the HCC project, effective October 1, 2025.

As of the date of this report, Idaho Power 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 2018, the IPUC issued an order approving a settlement stipulation, in response to an earlier application by Idaho Power, recognizing that a total of $216.5 million in Idaho Power expenditures through year-end 2015 on relicensing of the HCC were prudently incurred, and therefore should be eligible for inclusion in customer rates at a later date.

***American Falls Relicensing:*** In 2020, Idaho Power filed with the FERC a notice of intent to file an application to relicense the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a nameplate generating capacity of 92.3 MW and FERC authorized installed capacity of 67.5 MW. Idaho Power owns the generation facility but not the structural dam or reservoir, which are owned by the U.S. Bureau of Reclamation. Idaho Power filed the final

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relicensing application with the FERC in February 2023. In September 2024, the Idaho Department of Environmental Quality issued a final CWA Section 401 water quality certification. The FERC released its environmental assessment in accordance with NEPA in January 2025. Three parties commented on the environmental assessment, and Idaho Power has responded to those comments.

Idaho Power's previous license at American Falls expired in February 2025. In March 2025, the FERC issued Idaho Power an annual license on the same terms and conditions as its prior license. The annual license is effective until February 28, 2026, or until the FERC issues a new license for the American Falls facility. As of the date of this report, Idaho Power anticipates the FERC will issue a new license for this facility in 2025.

**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-fired power plant, its co-owned coal- and gas-fired power plant, and its three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's hydropower projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• increase the operating costs of generating plants;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• increase the construction costs and lead time for new facilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• require the modification of existing generating plants, which could result in additional costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• require the curtailment, fuel-switching, or shut-down of existing generating plants;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• reduce the output from current generating facilities; or

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

Current and future environmental laws and regulations could significantly increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation or conversion to natural gas, as the cost of compliance makes coal plants uneconomical to operate. The decision to cease operation of the Boardman power plant in 2020 was based in part on the significant cost of compliance with environmental laws and regulations. The decision to end participation in coal-fired operations at the North Valmy plant was also based in part on the economics of continuing coal-fired generation at the plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.

Part I, Item 1 - "Business - Utility Operations - Environmental Regulation and Costs" in the 2024 Annual Report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2025 to 2027. Given the uncertainty of future environmental regulations and technological advances, Idaho Power cannot make near-term estimates with certainty and is also unable to predict its environmental-related expenditures beyond 2027, 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 2024 Annual Report. Recent developments in certain environmental matters relevant to Idaho Power are described below.

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**EPA Proposed Regulatory Actions**

In March 2025, the EPA announced a set of proposed regulatory actions relating to environmental laws and regulations, many of which will impact Idaho Power if they are implemented. The proposed regulatory actions relate to the following laws and regulations, among others: the EPA's 2009 endangerment finding regarding six greenhouse gases; the Clean Air Act Section 111 rulemaking for new and existing generation units (also known as the Clean Power Plan 2.0); the Mercury and Air Toxics Standards (MATS); 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.

In June 2025, the EPA published proposed rules to repeal greenhouse gas emissions standards for fossil fuel-fired power plants and to repeal certain amendments to the MATS, including the revised filterable particulate matter (fPM) emission standard; the revised fPM emission standard compliance demonstration requirements; and the revised mercury emission standard for lignite-fired electric utility steam generating units. In August 2025, the EPA proposed a rule to reconsider the EPA's 2009 greenhouse gas endangerment finding. The proposed rules are subject to public comment and remain pending as of the date of this report. The EPA has not yet taken official action on any of the other items mentioned in its March 2025 announcement. Idaho Power will continue to actively monitor these proposals and any other pending or potential environmental regulations related to environmental matters that may have an impact on its future operations. Given uncertainties regarding the outcome and timing for these EPA proposals, Idaho Power is unable to estimate the impact on Idaho Power of any such proposals.

**National Environmental Policy Act Matters**

NEPA is a federal law that requires federal agencies to consider the environmental impacts of their actions and decisions. NEPA applies to Idaho Power's transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions. The Council on Environmental Quality (CEQ) under previous Presidential Administrations had issued guidance to federal agencies in issuing their own regulations regarding the implementation of NEPA for projects under their jurisdiction. However, a CEQ interim final rule effective in April 2025 removed all CEQ NEPA implementing regulations.

In addition, the U.S. Supreme Court clarified in the *Seven County Infrastructure Coalition v. Eagle County, Colorado* case in May 2025 that NEPA imposes no substantive environmental obligations or restrictions, but rather is a procedural statute that requires federal agencies to weigh environmental consequences as the agency reasonably sees fit under its governing statute and any relevant substantive environmental laws.

In July 2025, a number of federal agencies, including the Department of the Interior, the Department of Energy, the Army Corps of Engineers, and the Department of Transportation, issued interim final rules revising their procedures for implementing NEPA. These interim final rules were issued in response to the Supreme Court's *Seven County* decision, the removal of the CEQ's NEPA implementing regulations, and the current Presidential Administration's executive orders regarding the energy industry.

These actions may result in significant changes to the way federal environmental laws and regulations are enforced, but as of the date of this report, Idaho Power is unable to predict the ultimate impact of these actions on Idaho Power and its operations.

**Endangered Species Act Matters**

In April 2025, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service issued a proposed rule to rescind the definition of "harm" under the ESA in their respective regulations. If adopted, the proposed rescission of the definition of harm would likely have the effect of reducing the applicability of the ESA in some contexts. As of the date of this report, Idaho Power is unable to determine with any specificity the impact on Idaho Power of the proposed rule.

**Invasive Species Management**

Quagga mussels are an invasive species that were first detected in the Snake River system in 2023 in the mid-Snake River near Twin Falls, Idaho, in Idaho Power's service area. Quagga mussel infestations can clog and damage irrigation, hydropower, and water delivery facilities and increase the costs to maintain such facilities. The Idaho State Department of Agriculture (ISDA) treated the affected area in 2023 and 2024 with a copper-based, EPA-approved treatment. ISDA sampling in 2025 detected the continued presence of quagga mussels. As a result, the ISDA performed additional treatments in September and October 2025 in an effort to eradicate quagga mussels in the affected area. As of the date of this report, Idaho Power cannot predict the extent

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to which the additional treatments will be successful in eradicating quagga mussels from the Snake River or the potential increase in other O&M expenses related to quagga mussel mitigation efforts. If a quagga mussel infestation occurs, it may result in increased other O&M costs for mitigation efforts and other adverse impacts for Idaho Power's operation of its hydropower facilities in any infested areas.

**OTHER MATTERS**

**One Big Beautiful Bill Act** 

On July 4, 2025, the One Big Beautiful Bill Act (OBBB) was signed into law. Among its key provisions, the OBBB updates renewable energy tax incentives originally established under the Inflation Reduction Act of 2022, including the Clean Electricity Production Tax Credit and the Investment Tax Credit. Under the new law, solar and wind facilities that begin construction before July 4, 2026, will remain eligible for the credits, consistent with existing guidance on construction start dates. Projects that commence after this deadline must be placed in service by a specified date to qualify. For certain other eligible technologies, a gradual phase-out of the credits will begin in 2034, with no credits available for projects that begin construction after 2035. The OBBB also introduces new restrictions for facilities that receive material support from a prohibited foreign entity as well as other corporate-related income tax law changes. IDACORP and Idaho Power continue to evaluate the OBBB and, as of the date of this report, do not anticipate material impacts from the OBBB to projects for which Idaho Power has already executed agreements to own generation resources.

**Executive Orders of the Current Presidential Administration**

Beginning in January 2025, the Administration has released several executive orders that may impact Idaho Power. These executive orders include, but are not limited to, orders regarding tariffs, the electric grid, the coal industry, revocation of executive orders of prior Presidential Administrations, federal grantmaking, and other orders intended to regulate international trade, strengthen the U.S. energy industry, and/or promote deregulation, including with respect to environmental and energy-related regulations. The outcome of these executive orders and U.S. federal agencies' review of regulations covered by executive orders is generally difficult to predict. However, in some instances, federal grants which Idaho Power has been awarded have been delayed or withdrawn, and other federal grants to Idaho Power may experience similar treatment in the future.

In addition, the court system has become more active in reviewing Presidential and agency actions, resulting in even less certainty as to the outcome and durability of rules that are administratively implemented. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and constructing transmission lines, due to the reduction of potential environmental infrastructure upgrades or conversions or reduction or elimination of permitting requirements. More strict or robust regulations, or additional regulations, such as tariffs on supplies and materials that Idaho Power purchases, on the other hand, would likely increase Idaho Power's costs of operating and maintaining its facilities, and could impact Idaho Power's plans and construction activities related to its capital projects, which could lead to substantially higher costs and delays in construction.

Executive orders may be affected by Congressional action. Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level. Therefore, as of the date of this report, and except as specifically described in this MD&A, Idaho Power is uncertain whether and to what extent the executive orders, any future executive orders, and the implementation of these and any future executive orders could affect its business, results of operations, and financial condition. Idaho Power will continue to monitor actions associated with or resulting from executive orders and new or revised legislation or regulation.

**Idaho Wildfire Standard of Care Act**

In April 2025, Idaho enacted the Wildfire Standard of Care Act (Idaho Code § 61-1801 through 1808), which became effective in July 2025. The Act requires Idaho electric public utilities to prepare wildfire mitigation plans annually to mitigate wildfire risk, submit the plans to the IPUC for review and approval, and implement the plans upon IPUC approval. An electric utility's wildfire mitigation plan approved by the IPUC establishes the utility's duty to its shareholders and the public with respect to wildfire risk. On September 30, 2025, the IPUC issued an order establishing a filing schedule permitting Idaho Power to file its WMP with the IPUC no earlier than October 1, 2025. Idaho Power filed its WMP with the IPUC on October 10, 2025. The Act provides up to six months for the IPUC to review and approve a WMP after it is filed. As of the date of this report, the IPUC's decision is pending.

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**Critical Accounting Policies and Estimates**

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 2024 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, 2024, 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, 2025. 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, 2025, IDACORP had no variable rate debt.

***Fixed Rate Debt*:** As of September 30, 2025, IDACORP had $3.5 billion in fixed rate debt, with a fair value of approximately $3.3 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $398 million if market interest rates were to decline by one percentage point from their September 30, 2025 levels.

**Commodity Price Risk**

IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. 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, 2025, had not changed materially from that reported in Item 7A of the 2024 Annual Report. Information regarding Idaho Power's use of derivative instruments to manage commodity price risk can be found in Note 12 - "Derivative Financial Instruments" to the condensed consolidated financial statements included in this report.

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<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**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, 2025, Idaho Power posted $31 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, 2025, the amount of additional collateral that could have been requested upon a downgrade to below investment grade was approximately $34 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, 2025, had not changed materially from that reported in Item 7A of the 2024 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 12 - "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 defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 11 - "Benefit Plans" to the consolidated financial statements included in the 2024 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, 2025, 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, 2025, 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, 2025, 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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<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**PART II – OTHER INFORMATION**

**ITEM 1. LEGAL PROCEEDINGS**

Refer to Note 10 – "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 2024 Annual Report, could materially affect IDACORP's and Idaho Power's business, financial condition, or future results. In addition to those risk factors, the risk factor set forth in Part II - Item 1A - "Risk Factors" of IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended March 31, 2025, 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, 2025.

**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, 2025, none of IDACORP's or Idaho Power's directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted or terminated a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

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<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**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, 2025:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | **Incorporated by Reference** | **Incorporated by Reference** | **Incorporated by Reference** | **Incorporated by Reference** | |
|<br>**Exhibit No.** |<br>**Exhibit Description** | **Form** | **File No.** | **Exhibit No.** | **Date** |<br>**Included Herewith** |
| 10.1<sup>1</sup> | <u>[IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended](ida93025ex101.htm)</u> |  |  |  |  | X |
| 15.1 | <u>[Letter Re: Unaudited Interim Financial Information](ida93025ex151.htm)</u> |  |  |  |  | X |
| 15.2 | <u>[Letter Re: Unaudited Interim Financial Information](ida93025ex152.htm)</u> |  |  |  |  | X |
| 31.1 | <u>[Certification of IDACORP, Inc. Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002](ida93025ex311.htm)</u> |  |  |  |  | X |
| 31.2 | <u>[Certification of IDACORP, Inc. Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002](ida93025ex312.htm)</u> |  |  |  |  | X |
| 31.3 | <u>[Certification of Idaho Power Company Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002](ida93025ex313.htm)</u> |  |  |  |  | X |
| 31.4 | <u>[Certification of Idaho Power Company Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002](ida93025ex314.htm)</u> |  |  |  |  | X |
| 32.1 | <u>[Certification of IDACORP, Inc. Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002](ida93025ex321.htm)</u> |  |  |  |  | X |
| 32.2 | <u>[Certification of IDACORP, Inc. Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002](ida93025ex322.htm)</u> |  |  |  |  | X |
| 32.3 | <u>[Certification of Idaho Power Company Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002](ida93025ex323.htm)</u> |  |  |  |  | X |
| 32.4 | <u>[Certification of Idaho Power Company Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002](ida93025ex324.htm)</u> |  |  |  |  | X |
| 95.1 | <u>[Mine Safety Disclosures](ida93025ex951-minesafety.htm)</u> |  |  |  |  | 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 |
| (1) Management contract or compensatory plan or arrangement | (1) Management contract or compensatory plan or arrangement | (1) Management contract or compensatory plan or arrangement | (1) Management contract or compensatory plan or arrangement | (1) Management contract or compensatory plan or arrangement | (1) Management contract or compensatory plan or arrangement | (1) Management contract or compensatory plan or arrangement |

---

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<u>[**Table of Contents**](#i2f2a0092f8b2400b80bef884b6bddd41_10)</u> **&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**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. | IDACORP, INC. |
| | | (Registrant) | (Registrant) |
| Date: | October 30, 2025 | By: | */s/ Lisa A. Grow* |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;Lisa A. Grow |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;President and Chief Executive Officer |
| Date: | October 30, 2025 | By: | */s/ Brian R. Buckham* |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;Brian R. Buckham |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;Senior Vice President, Chief Financial Officer, and Treasurer |
|  |  | IDAHO POWER COMPANY | IDAHO POWER COMPANY |
|  |  | (Registrant) | (Registrant) |
| Date: | October 30, 2025 | By: | */s/ Lisa A. Grow* |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;Lisa A. Grow |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;President and Chief Executive Officer |
| Date: | October 30, 2025 | By: | */s/ Brian R. Buckham* |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;Brian R. Buckham |
|  |  |  | &nbsp;&nbsp;&nbsp;&nbsp;Senior Vice President, Chief Financial Officer, and Treasurer |

---

## Exhibit 10.1

**Exhibit 10.1**

**NON-EMPLOYEE DIRECTORS STOCK COMPENSATION PLAN**

**(As Amended September 16, 2025)**

I.&nbsp;&nbsp;&nbsp;&nbsp;<u>Purpose</u>

The purpose of the IDACORP, Inc. Non-Employee Directors Stock Compensation Plan is to provide ownership of the Company's stock to non-employee members of the Board of Directors and to strengthen the commonality of interest between directors and shareholders.

II.&nbsp;&nbsp;&nbsp;&nbsp;<u>Definitions</u>

When used herein, the following terms shall have the respective meanings set forth below:

<u>"Annual Retainer"</u> means the annual retainer payable by the Company to Non-Employee Directors and shall include, for purposes of this Plan, meeting fees, cash retainers and any other cash compensation payable to Non-Employee Directors by the Company for services as a director.

<u>"Annual Meeting of Shareholders"</u> means the annual meeting of shareholders of the Company at which directors of the Company are elected.

<u>"Board"</u> or <u>"Board of Directors"</u> means the Board of Directors of the Company.

<u>"Change in Control"</u> means the earliest of the following to occur: (a) any person (which shall not include the Company, any Subsidiary or any employee benefit plan of the Company or of any Subsidiary) ("Person") or group (as that term is defined in Treasury Regulation Section 1.409A-3(i)(5)(v)(B)) acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person or Persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; (b) any Person or group (as that term is defined in Treasury Regulation Section 1.409A-3(i)(5)(v)(B)) acquires ownership of the stock of the Company that, together with stock held by such Person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company (this part (b) applies only when there is a transfer of stock of the Company and the Company's stock remains outstanding after the transaction); (c) a majority of the members of the Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Board; or (d) any Person or group (as that term is defined in Treasury Regulation Section 1.409A-3(i)(5)(v)(B)) acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person or Persons) assets from the Company that have a gross fair market value equal to or more than 40% of the total gross fair market value of all of the assets of the Company immediately before such acquisition or acquisitions.

Notwithstanding anything contained herein to the contrary, no transaction or event shall constitute a Change in Control for purposes of the Plan unless the transaction or event constitutes a change in the ownership of a corporation (as defined in Treasury Regulation Section 1.409A-3(i)(5)(v)), a change in effective control of a corporation (as defined in Treasury Regulation Section 1.409A-3(i)(5)(vi)) or a change in the ownership of a substantial portion of the assets of a corporation (as defined in Treasury Regulation Section 1.409A-3(i)(5)(vii)) and the term Change in Control shall be interpreted in a manner consistent with the proper interpretation of the similar provisions in the Section 409A Treasury Regulations.

<u>"Code"</u> means the Internal Revenue Code of 1986, as amended.

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<u>"Committee"</u> means the Compensation and Human Resources Committee of the Board of Directors.

<u>"Common Stock"</u> means the common stock, without par value, of the Company.

<u>"Company"</u> means IDACORP, Inc., an Idaho corporation, and any successor corporation.

<u>"Deferral Account"</u> means an account maintained by the Company in the name of a Participant that is used to track the Deferred Stock Units of a Participant who elects to defer receipt of his or her Stock Payments pursuant to Section VI hereof.

<u>"Deferral Election"</u> means a Participant's deferral election, as defined in Section VI(A) hereof.

<u>"Deferred Stock Unit"</u> means a notional entry in a Participant's Deferral Account representing one share of Common Stock.

<u>"Effective Date"</u> means May 17, 1999.

<u>"Employee"</u> means any officer or other common law employee of the Company or of any Subsidiary.

<u>"Exchange Act"</u> means the Securities Exchange Act of 1934, as amended.

<u>"Non-Employee Director"</u> or <u>"Participant"</u> means any person who is elected or appointed to the Board of Directors of the Company and who is not an Employee.

<u>"Plan"</u> means the Company's Non-Employee Directors Stock Compensation Plan, adopted by the Board on May 5, 1999, as it may be amended from time to time.

<u>"Separation from Service"</u> means a Participant's separation from service (as that term is used in Section 409A(a)(2)(A)(i) of the Code) with the Company.

<u>"Stock Payment"</u> means that portion of the Annual Retainer to be paid to Non-Employee Directors in shares of Common Stock rather than cash for services rendered as a director of the Company, as provided in Section V hereof.

<u>"Subsidiary"</u> means any corporation (other than the Company) in an unbroken chain of corporations beginning with the Company if each of the corporations other than the last corporation in the unbroken chain owns stock possessing 50 percent or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.

III.&nbsp;&nbsp;&nbsp;&nbsp;<u>Shares of Common Stock Subject to the Plan</u>

Subject to Section VII below, the maximum aggregate number of shares of Common Stock that may be delivered under the Plan is 100,000 shares. The Common Stock to be delivered under the Plan will be made available from treasury stock or shares of Common Stock purchased on the open market.

IV.&nbsp;&nbsp;&nbsp;&nbsp;<u>Administration</u>

The Plan shall be administered by the Compensation and Human Resources Committee of the Board of Directors. The Company shall pay all costs of administration of the Plan. Subject to and not inconsistent with the express provisions of the Plan, the Committee has and may exercise such powers and authority of the Board as may be necessary or appropriate for the Committee to carry out its functions under the Plan. Without limiting the generality of the foregoing, the Committee shall have full power and authority (i) to determine all questions of fact that may arise under the Plan, (ii) to interpret the Plan and to make all other determinations necessary or

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advisable for the administration of the Plan and (iii) to prescribe, amend and rescind rules and regulations relating to the Plan, including, without limitation, any rules which the Committee determines are necessary or appropriate to ensure that the Company and the Plan will be able to comply with all applicable provisions of any federal, state or local law. All interpretations, determinations and actions by the Committee will be final and binding upon all persons, including the Company, the Participants and their estates and beneficiaries.

V.&nbsp;&nbsp;&nbsp;&nbsp;<u>Determination of Annual Retainer and Stock Payments</u>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;A.&nbsp;&nbsp;&nbsp;&nbsp;<u>Annual Retainer</u>

The Board shall determine the Annual Retainer payable to all Non-Employee Directors of the Company.

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;B.&nbsp;&nbsp;&nbsp;&nbsp;<u>Stock Payments</u>

Subject to the provisions of Section V(C) below, each director who is a Non-Employee Director on March 1 of each year shall receive, on March 1 or the first business day thereafter, as a portion of the Annual Retainer, a Stock Payment of $145,000 in value of Common Stock. Non-Employee Directors may elect to defer receipt of the Stock Payment in accordance with the provisions of Section VI hereof. The number of shares granted (or credited as Deferred Stock Units pursuant to a Deferral Election in accordance with Section VI hereof) shall be determined based on (i) for shares granted from treasury stock and Deferred Stock Units, the closing price of the Common Stock on the consolidated transaction reporting system on the business day immediately preceding the date paid to the Non-Employee Director or credited to his or her Deferral Account, as the case may be, and (ii) for open market purchases, the actual price paid to purchase the shares.

Non-Employee Directors who are initially elected to the Board after March 1 in any year shall receive a prorated Stock Payment on the first business day of the month following the effective date of their election to the Board, but in no event later than March 15 of the year following the year in which they are initially elected to the Board. The Stock Payment will be prorated by multiplying $145,000 by a fraction, the numerator of which equals the number of months (with a partial month counted as a full month) remaining in the calendar year and the denominator of which is twelve.

At the time of payment (or, if applicable, at the time of distribution of any shares of Common Stock pursuant to Section VI hereof), a certificate evidencing the shares of Common Stock shall be registered in the name of the Participant and issued to the Participant.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;C.&nbsp;&nbsp;&nbsp;&nbsp;<u>Non-Employee Directors on April 1, 2007 and Thereafter</u>

A Non-Employee Director initially elected to the Board effective on or after April 1, 2007 shall receive, on March 1 or the first business day thereafter, a prorated Stock Payment if the Board is aware on March 1 that the Non-Employee Director will not continue to serve on the Board for the entire year. The number of shares granted (or credited as Deferred Stock Units pursuant to a Deferral Election) shall be calculated by multiplying $145,000 by a fraction, the numerator of which is the number of actual or expected months (with a partial month counted as a full month) of service on the Board during the year and the denominator of which is twelve. If the Board is not aware on March 1 that a Non-Employee Director initially elected to the Board effective on or after April 1, 2007 will not serve on the Board for the entire year, such Non-Employee Director shall receive a full Stock Payment and shall not be required to forfeit or otherwise return any shares of Common Stock granted as a Stock Payment or credited as Deferred Stock Units pursuant to the Plan notwithstanding any change in status of such Non-Employee Director which renders him or her ineligible to continue as a Participant in the Plan.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;D.&nbsp;&nbsp;&nbsp;&nbsp;<u>Non-Employee Directors Prior to April 1, 2007</u>

A Non-Employee Director initially elected to the Board effective prior to April 1, 2007 will not receive a prorated Stock Payment as set forth in the immediately preceding Section V(C), but rather will receive a full Stock Payment on March 1 or the first business day thereafter, notwithstanding the fact that the Board may be aware that the Non-Employee Director will not continue to serve on the Board for the entire year. The number of shares granted (or credited as Deferred Stock Units pursuant to a Deferral Election) shall be calculated in the manner set forth in Section V(B) hereof. No Non-Employee Director who was a member of the Board effective prior to April 1, 2007 shall be required to forfeit or otherwise return any shares of Common Stock granted as a Stock Payment or credited as Deferred Stock Units pursuant to the Plan notwithstanding any change in status of such Non-Employee Director which renders him or her ineligible to continue as a Participant in the Plan.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;E.&nbsp;&nbsp;&nbsp;&nbsp;<u>No Further Stock Payments</u>

Notwithstanding the foregoing, Non-Employee Directors will not receive a Stock Payment under the Plan on or after February 26, 2010.

VI.&nbsp;&nbsp;&nbsp;&nbsp;<u>Deferral of Stock Payment</u>

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;A.&nbsp;&nbsp;&nbsp;&nbsp;<u>Deferral Elections</u>

A Participant may elect to defer receipt of his or her Stock Payment by timely filing a deferral election (a "Deferral Election") in accordance with such procedures as may from time to time be prescribed by the Committee. A Deferral Election shall be valid only if it is delivered prior to the first day of the calendar year in which the services giving rise to the Stock Payment being deferred are to be performed.

A Participant's Deferral Election shall become irrevocable as of the last date the Deferral Election could be delivered or such earlier date as may be established by the Committee. A Participant may revoke or change a Deferral Election at any time prior to the date the election becomes irrevocable, subject to such restrictions as the Committee may establish from time to time. Any such revocation or change shall be in a form and manner determined by the Committee. A Participant's Deferral Election shall remain in effect and will apply to Stock Payments in future years (beyond the first year to which it relates) unless and until the Participant revokes the Deferral Election. The deadline for revocation of a Deferral Election for this purpose shall be the same as the deadline for delivering a Deferral Election with respect to the year or such earlier date as may be established by the Committee. Revocation shall be effected by the Participant's delivery of a Termination of Deferral Election Agreement or such other document as the Committee may prescribe for such purpose.

If a valid Deferral Election is timely filed by a Participant, a Deferral Account shall be established for the Participant and credited with a number of Deferred Stock Units equal to the number of shares of Common Stock that would have been received by the Participant pursuant to Section V hereof absent the Deferral Election.

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;B.&nbsp;&nbsp;&nbsp;&nbsp;<u>Dividends</u>

If dividends are paid on shares of Common Stock, a Participant's Deferral Account shall be credited on the dividend payment date with a number of additional Deferred Stock Units (and/or fraction thereof) determined by dividing (i) the dividends that would have been paid on the Deferred Stock Units held in the Participant's Deferral Account as of the dividend record date as if they were actual shares of Common Stock by (ii) the closing price of the Common Stock on the consolidated transaction reporting system on the dividend payment date.

&nbsp;&nbsp;&nbsp;&nbsp;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;C.&nbsp;&nbsp;&nbsp;&nbsp;<u>Deferred Stock Units</u>

Amounts in a Participant's Deferral Account shall remain denominated in the form of Deferred Stock Units until distributed.

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;D.&nbsp;&nbsp;&nbsp;&nbsp;<u>Time of Distribution</u>

Deferral Accounts shall be distributed (or, in the case of installments, distributions shall commence) upon Separation from Service. Participants shall elect in their Deferral Elections whether distributions shall be in a lump sum or in installments, subject to such terms and conditions as the Committee may from time to time prescribe. In the case of a Participant's death, whether before or after distributions have commenced, the Participant's Deferral Account balance shall be distributed in a lump sum as soon as practicable (but in all events within 90 days) thereafter to the Participant's estate or, if applicable, designated beneficiary.

Upon a Change in Control, the Participant's Deferral Account balance shall be distributed in a lump sum as soon as practicable (but in all events within 90 days) thereafter to the Participant.

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;E.&nbsp;&nbsp;&nbsp;&nbsp;<u>Beneficiaries</u>

A Participant may designate a beneficiary or beneficiaries (which may be an entity other than a natural person) to receive any payments to be made under Section VI hereof upon the Participant's death. At any time, and from time to time, any such designation may be changed or canceled by the Participant without the consent of any beneficiary. Any such designation, change or cancellation must be by written notice filed with the Secretary of the Company and shall not be effective until received by the Secretary of the Company. If a Participant designates more than one beneficiary, any payments under Section VI hereof to such beneficiaries shall be made in equal amounts unless the Participant has designated otherwise, in which case the payments shall be made in the amounts designated by the Participant. If no beneficiary has been designated by the Participant, or the designated beneficiaries have predeceased the Participant, payment shall be made to the Participant's estate. If any dispute shall arise as to the entitlement of any person to any portion of the Participant's Deferral Account balance, the Company's obligations under this Plan will be satisfied if it makes payment to the Participant's estate.

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;F.&nbsp;&nbsp;&nbsp;&nbsp;<u>Distribution of Deferral Accounts</u>

Distribution shall be in shares of Common Stock, with each Deferred Stock Unit equal to one share of Common Stock and any fractional shares paid in cash.

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;G.&nbsp;&nbsp;&nbsp;&nbsp;<u>Section 409A</u>

To the extent applicable, it is intended that this Plan will comply with Section 409A of the Code and any regulations and guidance issued thereunder, and the Plan shall be interpreted accordingly.

VII.&nbsp;&nbsp;&nbsp;&nbsp;<u>Adjustments in Authorized Shares and Deferred Stock Units</u>

In the event of any equity restructuring (within the meaning of Financial Accounting Standards No. 123(R)), such as a stock dividend, stock split, spinoff, rights offering or recapitalization through a large, nonrecurring cash dividend, the Committee shall cause an equitable adjustment to be made in (i) the number and kind of shares of Common Stock that may be delivered under the Plan and (ii) the number and kind of Deferred Stock Units in Participants' Deferral Accounts, in either case to prevent dilution or enlargement of rights. In the event of any other change in corporate capitalization, such as a merger, consolidation or liquidation, the Committee may, in its sole discretion, cause an equitable adjustment as described in the foregoing sentence to be made, to prevent dilution or enlargement of rights. The maximum number of shares

------

issuable under the Plan and the number of Deferred Stock Units allocated to a Participant's Deferral Account as a result of any such adjustment shall be rounded down to the nearest whole share or unit. Adjustments made by the Committee pursuant to this Section VII shall be final, binding and conclusive.

VIII.&nbsp;&nbsp;&nbsp;&nbsp;<u>Amendment and Termination of Plan</u>

The Board will have the power, in its discretion, to amend, suspend or terminate the Plan at any time, subject to the satisfaction of all obligations under the Plan to Participants (and Participants' estates and beneficiaries). However, no such termination, suspension or amendment or other action with respect to the Plan shall adversely affect the Participants' Deferral Account balances which have accrued prior to such action.

IX.&nbsp;&nbsp;&nbsp;&nbsp;<u>Effective Date and Duration of the Plan</u>

The Plan will become effective upon the Effective Date and shall remain in effect, subject to the right of the Board of Directors to terminate the Plan at any time pursuant to Section VIII, until all shares subject to the Plan have been granted or distributed according to the Plan's provisions.

X.&nbsp;&nbsp;&nbsp;&nbsp;<u>Miscellaneous Provisions</u>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;A.&nbsp;&nbsp;&nbsp;&nbsp;<u>Continuation of Directors in Same Status</u>

Nothing in the Plan or any action taken pursuant to the Plan shall be construed as creating or constituting evidence of any agreement or understanding, express or implied, that the Company will retain a Non-Employee Director as a director or in any other capacity for any period of time or at a particular retainer or other rate of compensation, as conferring upon any Participant any legal or other right to continue as a director or in any other capacity, or as limiting, interfering with or otherwise affecting the right of the Company to terminate a Participant in his or her capacity as a director or otherwise at any time for any reason, with or without cause, and without regard to the effect that such termination might have upon him or her as a Participant under the Plan.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;B.&nbsp;&nbsp;&nbsp;&nbsp;<u>Compliance with Government Regulations</u>

Neither the Plan nor the Company shall be obligated to issue any shares of Common Stock pursuant to the Plan at any time unless and until all applicable requirements imposed by any federal and state securities and other laws, rules and regulations, by any regulatory agencies or by any stock exchanges upon which the Common Stock may be listed have been fully met. As a condition precedent to any issuance of shares of Common Stock pursuant to the Plan, the Board or the Committee may require a Participant to take any such action and to make any such covenants, agreements and representations as the Board or the Committee, as the case may be, in its discretion deems necessary or advisable to ensure compliance with such requirements. The Company shall in no event be obligated to register the shares of Common Stock deliverable under the Plan pursuant to the Securities Act of 1933, as amended, or to qualify or register such shares under any securities laws of any state upon their issuance under the Plan or at any time thereafter, or to take any other action in order to cause the issuance and delivery of such shares under the Plan or any subsequent offer, sale or other transfer of such shares to comply with any such law, regulation or requirement. Participants are responsible for complying with all applicable federal and state securities and other laws, rules and regulations in connection with any offer, sale or other transfer of the shares of Common Stock issued under the Plan or any interest therein including, without limitation, compliance with the registration requirements of the Securities Act of 1933, as amended (unless an exemption therefrom is available), or with the provisions of Rule 144 promulgated thereunder, if applicable, or any successor provisions. Certificates for shares of Common Stock may be legended as the Committee shall deem appropriate.

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;C.&nbsp;&nbsp;&nbsp;&nbsp;<u>Nontransferability of Rights</u>

No Participant shall have the right to assign the right to receive any Stock Payment or any other right or interest under the Plan, contingent or otherwise, or to cause or permit any encumbrance, pledge or charge of any nature to be imposed on any such Stock Payment or any such right or interest (prior to the issuance of stock certificates evidencing such Stock Payment).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;D.&nbsp;&nbsp;&nbsp;&nbsp;<u>Successor Entities</u>

All obligations of the Company or any Subsidiary under the Plan shall be binding on any successor to the Company or any Subsidiary, respectively, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, reorganization or other transaction involving all or substantially all of the business and/or assets of the Company or any Subsidiary. References to the Company or Subsidiary in the Plan shall be deemed to refer to the successors thereto, as applicable.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;E.&nbsp;&nbsp;&nbsp;&nbsp;<u>Severability</u>

In the event that any provision of the Plan is held invalid, void or unenforceable, the same shall not affect, in any respect whatsoever, the validity of any other provision of the Plan.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;F.&nbsp;&nbsp;&nbsp;&nbsp;<u>Governing Law</u>

To the extent not preempted by Federal law, the Plan and all rights and obligations hereunder shall be governed by and interpreted in accordance with the laws of the State of Idaho, without regard to conflicts of law provisions.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;G.&nbsp;&nbsp;&nbsp;&nbsp;<u>No Right to Company Assets</u>

Nothing in this Plan shall be construed as giving the Participant, Participant's beneficiaries or any other person any equity or interest of any kind in the assets of the Company or creating a trust of any kind or a fiduciary relationship of any kind between the Company and any such person. As to any claim for payments due under the provisions of this Plan, the Participant, Participant's beneficiaries and any other persons having a claim for payments shall be unsecured creditors of the Company.

___________________________________________________________

Amended as of September 20, 2007 to add proration

Amended as of November 15, 2007 to increase stock payment from $40,000 to $45,000 effective January 1, 2008

Amended as of November 20, 2008 to permit deferrals

Amended as of February 26, 2010 to permit no further Stock Payments

Amended as of January 19, 2012 to increase stock payment from $45,000 to $60,000 effective January 1, 2012

Amended as of January 16, 2014 to increase stock payment from $60,000 to $75,000 effective January 1, 2014

Amended as of November 20, 2014 to increase stock payment from $75,000 to $80,000 effective January 1, 2015

------

Amended as of November 19, 2015 to increase stock payment from $80,000 to $100,000 effective January 1, 2016

Amended as of November 16, 2017 to increase stock payment from $100,000 to $105,000 effective January 1, 2018

Amended as of November 21, 2019 to increase stock payment from $105,000 to $110,000 effective January 1, 2020

Amended as of November 18, 2021 to increase stock payment from $110,000 to $120,000 effective January 1, 2022

Amended as of November 15, 2023 to increase stock payment from $120,000 to $140,000 effective January 1, 2024

Amended as of September 16, 2025 to increase stock payment from $140,000 to $145,000 effective January 1, 2026

## Exhibit 15.1

**Exhibit 15.1**

October 30, 2025

The Board of Directors and Shareholders of IDACORP, Inc.

1221 W. Idaho Street

Boise, Idaho 83702

We are aware that our report dated October 30, 2025, 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, 2025, 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

**Exhibit 15.2**

October 30, 2025

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 30, 2025, 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, 2025, 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

**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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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 30, 2025 | By: | */s/ Lisa A. Grow* |
|  |  |  | Lisa A. Grow |
|  |  |  | President and Chief Executive Officer |

---

## Exhibit 31.2

**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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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 30, 2025 | By: | */s/ Brian R. Buckham* |
|  |  |  | Brian R. Buckham |
|  |  |  | Senior Vice President, Chief Financial Officer, and Treasurer |

---

## Exhibit 31.3

**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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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 30, 2025 | By: | */s/ Lisa A. Grow* |
|  |  |  | Lisa A. Grow |
|  |  |  | President and Chief Executive Officer |

---

## Exhibit 31.4

**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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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 30, 2025 | By: | */s/ Brian R. Buckham* |
|  |  |  | Brian R. Buckham |
|  |  |  | Senior Vice President, Chief Financial Officer, and Treasurer |

---

## Exhibit 32.1

**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, 2025 (the "Report"), I, Lisa A. Grow, President and Chief Executive Officer of the Company, certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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* |
| &nbsp;&nbsp;&nbsp;&nbsp;Lisa A. Grow |
| &nbsp;&nbsp;&nbsp;&nbsp;President and Chief Executive Officer |
| &nbsp;&nbsp;&nbsp;&nbsp;October 30, 2025 |

---

## Exhibit 32.2

**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, 2025 (the "Report"), I, Brian R. Buckham, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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* |
| &nbsp;&nbsp;&nbsp;&nbsp;Brian R. Buckham |
| &nbsp;&nbsp;&nbsp;&nbsp;Senior Vice President, Chief Financial Officer, and Treasurer |
| &nbsp;&nbsp;&nbsp;&nbsp;October 30, 2025 |

---

## Exhibit 32.3

**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, 2025 (the "Report"), I, Lisa A. Grow, President and Chief Executive Officer of the Company, certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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* |
| &nbsp;&nbsp;&nbsp;&nbsp;Lisa A. Grow |
| &nbsp;&nbsp;&nbsp;&nbsp;President and Chief Executive Officer |
| &nbsp;&nbsp;&nbsp;&nbsp;October 30, 2025 |

---

## Exhibit 34.4

**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, 2025 (the "Report"), I, Brian R. Buckham, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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* |
| &nbsp;&nbsp;&nbsp;&nbsp;Brian R. Buckham |
| &nbsp;&nbsp;&nbsp;&nbsp;Senior Vice President, Chief Financial Officer, and Treasurer |
| &nbsp;&nbsp;&nbsp;&nbsp;October 30, 2025 |

---

## Exhibit 95.1

**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, 2025. Legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC) are as of September 30, 2025. 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<br>September 30, 2025** |
| | **(unaudited)** |
| | Surface Mine<br>(MSHA ID No. 4800677) |
| Mine Safety Act Citations and Orders: |  |
| Section 104(a) Significant & Substantial Citations <sup>(1)</sup> | 1 |
| Section 104(b) Orders <sup>(2)</sup> |  |
| Section 104(d) Citations & Orders <sup>(3)</sup> |  |
| Section 107(a) Imminent Danger Orders <sup>(4)</sup> |  |
| Total Value of Proposed MSHA Assessments (in thousands) | $— |
| Legal Actions Pending |  |
| Legal Actions Issued During Period |  |
| Legal Actions Closed During Period |  |
| Number of Fatalities |  |
| _________________ |  |
| &nbsp;&nbsp;&nbsp;&nbsp; <sup>(1)</sup> For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.  | &nbsp;&nbsp;&nbsp;&nbsp; <sup>(1)</sup> For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.  |
| &nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> 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. | &nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> 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. |
| &nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.  | &nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.  |
| &nbsp;&nbsp;&nbsp;&nbsp;<sup>(4)</sup> 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.  | &nbsp;&nbsp;&nbsp;&nbsp;<sup>(4)</sup> 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.  |

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For the three-month period ended September 30, 2025, 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.

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