IDACORP INC (IDA)

CIK: 0001057877. SIC: 4911 Electric Services. Latest 10-K as of: 2026-02-19.

SIC breadcrumb: Transportation, Communications, Electric, Gas, And Sanitary Services > Electric, Gas, And Sanitary Services > SIC 4911 Electric Services

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1057877. Latest filing source: 0001057877-26-000028.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-19. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001057877.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-19. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001057877.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001057877-26-000098.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-04-30. Report date: 2026-03-31.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

In MD&A in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. While reading this MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report. This discussion updates the MD&A included in the 2025 Annual Report, and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year, particularly in light of the seasonality of Idaho Power's sales volumes, as discussed below.

INTRODUCTION

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the IPUC, OPUC, and FERC. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity. Idaho Power experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.

Idaho Power is the parent of IERCo, a joint-owner of BCC, which mines and supplies coal to the Jim Bridger plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IFS, an investor in affordable housing and other real estate tax credit investments, and Ida-West, an operator of small PURPA-qualifying hydropower generation projects.

EXECUTIVE OVERVIEW

Management's Outlook and Company Objectives

In the 2025 Annual Report, IDACORP's and Idaho Power's management included a summary of their business objectives for the companies for 2026 and beyond, under the heading "Executive Overview" in the MD&A. As of the date of this report, management's outlook and strategy remain consistent with that discussion, as updated by the discussion in this MD&A. Some notable developments that have occurred since that report include the following:

•Idaho Power continues to experience and forecast positive customer growth in its service area. During the twelve months ended March 31, 2026, Idaho Power's customer count grew by approximately 15,000 customers and the customer growth rate was 2.3 percent.

•So far in 2026, Idaho Power achieved notable milestones for several key projects, underscoring significant progress towards addressing peak capacity and energy needs in 2027 and beyond:

◦In March, the IPUC approved Idaho Power's agreement to purchase the output of an 80 MW solar facility, with a scheduled online date of June 2027.

◦In March, the IPUC approved Idaho Power's CPCN request for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant, with an expected in-service date in 2028.

◦In March, Idaho Power filed a CPCN request with the IPUC for a 222 MW natural gas-fueled facility, with an expected in-service date in 2029 and a 430 MW natural gas-fueled facility, with an expected in-service date in 2030. As of the date of this report, both requests are pending IPUC approval.

◦In April, Idaho Power, jointly with co-owner PacifiCorp, filed a CPCN request for Segment E-8 for the GWW transmission line, which would create up to 2,000 MW of additional transmission capacity and the ability to interconnect new generation resources across Idaho.

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Summary of Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share (in thousands of dollars and shares, except earnings per share amounts):

Three months ended

March 31,

2026

2025

Idaho Power net income

$

66,658 

$

58,127 

Net income attributable to IDACORP, Inc.

$

67,981 

$

59,647 

Weighted average outstanding shares – diluted

56,289 

54,126 

IDACORP, Inc. earnings per diluted share

$

1.21 

$

1.10 

The table below provides a reconciliation of net income attributable to IDACORP for the three months ended March 31, 2026, from the same period in 2025 (items are in millions of dollars and are before related income tax impact unless otherwise noted):

Three months ended

Net income attributable to IDACORP, Inc. - March 31, 2025

$

59.6 

 Increase (decrease) in Idaho Power net income:

Retail revenues per MWh, net of power cost adjustment mechanisms

18.0 

Customer growth, net of associated power supply costs and power cost adjustment mechanisms

5.0 

Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms

(10.7)

Idaho fixed cost adjustment (FCA) revenues

19.1 

Other O&M expenses

(13.1)

Depreciation and amortization expense

(5.7)

Other changes in operating revenues and expenses, net

13.6 

Increase in Idaho Power operating income

26.2 

 Non-operating expense, net

(4.1)

Additional ADITC amortization

(13.0)

Income tax expense, excluding additional ADITC amortization

(0.6)

Total increase in Idaho Power net income

8.5 

 Other IDACORP changes (net of tax)

(0.1)

Net income attributable to IDACORP, Inc. - March 31, 2026

$

68.0 

Net Income - First Quarter 2026

IDACORP's net income increased $8.4 million for the first quarter of 2026 compared with the first quarter of 2025, 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 $18.0 million in the first quarter of 2026 compared with the first quarter of 2025. This benefit was due primarily to an overall increase in Idaho base rates, effective January 1, 2026, from the outcome of the 2025 Settlement Stipulation. For more information on the 2025 Settlement Stipulation, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report.

Customer growth increased operating income by $5.0 million in the first quarter of 2026 compared with the first quarter of 2025, as the number of Idaho Power customers grew by approximately 15,000, or 2.3 percent, during the twelve months ended March 31, 2026. Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms, decreased operating income by $10.7 million in the first quarter of 2026 compared with the first quarter of 2025. Usage per residential and commercial customers decreased most significantly, as more moderate temperatures in the first quarter of 2026 compared with the first quarter of 2025 led these customers to use less energy for heating purposes. These decreases were partially offset by increases in usage per irrigation and industrial customers, as lower precipitation in the first quarter of 2026 compared with the first quarter of 2025 led irrigation customers to use more energy for operating irrigation pumps, and a large

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load industrial customer increased energy use as it ramped up operation of its facility. An increase in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $19.1 million.

Other O&M expenses in the first quarter of 2026 were $13.1 million higher than the first quarter of 2025. This increase was primarily the result of increased wildfire mitigation program expenses and the amortization of previously deferred costs related to the conversion of generating units at the Jim Bridger plant from coal to natural gas, much of which is recovered in customer rates and reflected in revenues pursuant to the 2025 Settlement Stipulation.

Depreciation and amortization expense increased $5.7 million in the first quarter of 2026 compared with the first quarter of 2025, 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 $13.6 million in the first quarter of 2026 compared with the first quarter of 2025, due primarily to a decrease in net power supply expenses that were not accrued for future refund in rates through Idaho Power's power cost adjustment mechanisms. Also contributing to the increase in other changes in operating revenues and expenses, net, was a decrease in property tax expense due to property tax legislative changes in Idaho.

Non-operating expense, net, increased $4.1 million in the first quarter of 2026 compared with the first quarter of 2025. Higher long-term debt balances led to an increase in interest expense, while lower interest-bearing cash investments led to a decrease in interest income. Interest expense recorded on a new finance lease also contributed to the increase compared with the first quarter of 2025. This increase was partially offset by an increase in AFUDC in the first quarter of 2026 compared with the first quarter of 2025, as the average construction work in progress balance was higher.

The increase in income tax expense for the first quarter of 2026, compared with the first quarter of 2025, was primarily due to a decrease in additional ADITC amortization under the Idaho regulatory settlement stipulation. Based on Idaho Power's current expectations of full-year 2026 financial results, Idaho Power recorded $6.3 million of additional ADITC amortization during the first quarter of 2026, compared with $19.3 million of additional ADITC amortization during the same period in 2025.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition are affected by several factors and trends, and the impact of those factors and trends is discussed in more detail below in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors and trends are as follows:

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

Idaho Power filed its most recent general rate case in Idaho in May 2025. The IPUC approved a settlement stipulation for the general rate case in December 2025, with rates effective January 1, 2026. The general rate case filing and the settlement stipulation are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. Idaho Power continues to evaluate the timing of its next general rate cases in Idaho and Oregon.

•Rate Base Growth and Infrastructure Investment: The rates established by the IPUC, OPUC, and FERC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-19. Report date: 2025-12-31.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

In this MD&A section of this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 2024 compared with 2023 can be found in their Annual Report on Form 10-K for the year ended December 31, 2024. See Part II - Item 7 - MD&A in that report for further information on the companies' prior period results of operations. While reading this MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part I - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A section and elsewhere in this report.

INTRODUCTION

IDACORP is a holding company whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the IPUC, OPUC, and FERC. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity. On February 13, 2026, Idaho Power entered into a definitive agreement to sell its Oregon electric distribution business and associated distribution assets, as well as certain Oregon transmission assets, to OTEC. The closing of the transaction is subject to various conditions, including approvals of the OPUC, IPUC, and FERC. For further information regarding the proposed transaction, see Note 22 - "Sale of Oregon Assets" to the consolidated financial statements included in this report.

Idaho Power is the parent of IERCo, a joint-owner of BCC, which mines and supplies coal to the Jim Bridger plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IFS, an investor in affordable housing and other real estate tax credit investments; and Ida-West, an operator of small PURPA-qualifying hydropower generation projects.

EXECUTIVE OVERVIEW

IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, since Idaho Power’s regulated electric utility operations are the primary driver of IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements, notable events, and milestones during 2025 include the following:

•IDACORP achieved net income growth for an eighteenth consecutive year in 2025.

•Idaho Power continues to focus on timely recovery of costs and earning a reasonable return on investment. In December 2025, the IPUC approved a settlement stipulation (2025 Settlement Stipulation) related to the Idaho general rate case that Idaho Power had filed in May 2025, with new rates effective January 1, 2026. The 2025 Settlement Stipulation is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and in "Regulatory Matters" in this MD&A.

•Idaho Power's customer count grew 2.3 percent in 2025 and Idaho Power's MWh sales to retail customers in 2025 were the highest in its history, surpassing the previous record set in 2024, reflecting continued growth in its service area.

•In 2025, Idaho Power’s reliability metrics continued to be among the best in company history, as Idaho Power provided uninterrupted service to its retail customers 99.97 percent of the time.

•Idaho Power’s residential and business customer satisfaction remain strong – in 2025, it was the highest ranked utility among peers in the segment for overall customer satisfaction in a third-party survey, and was the second highest in the segment for business customer satisfaction, and the second highest in the segment for residential customer satisfaction in a separate third-party survey.

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

•To help meet growing capacity and energy needs in 2027 and beyond, Idaho Power entered into the following transactions in 2025:

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

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

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

•During 2025, several key projects achieved notable milestones, underscoring significant progress towards Idaho Power addressing peak capacity and energy needs in 2025 and beyond, including the following:

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

◦Idaho Power began receiving power under a 20-year agreement to utilize storage capacity from a third-party 150 MW battery storage facility;

◦80 MW of company-owned battery storage facilities came online, with another 250 MW of company-owned battery storage commencing construction; and

◦Idaho Power filed a CPCN request with the IPUC for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant, with an expected in-service date in 2028.

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

•Idaho Power's estimate of capital expenditures from 2026 to 2030 is in the range of $6.3 billion to $7.2 billion. Part of the magnitude of capital expenditures is driven by Idaho Power's need to acquire additional power supply and transmission resources to meet growing demand.

Summary of 2025 Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2025, 2024, and 2023 (in thousands of dollars and shares, except earnings per share amounts):

Year Ended December 31,

2025

2024

2023

Idaho Power net income

$

315,862 

$

280,605 

$

256,810 

Net income attributable to IDACORP, Inc.

$

323,472 

$

289,174 

$

261,195 

Weighted average outstanding shares – diluted

54,806 

52,615 

50,806 

IDACORP, Inc. earnings per diluted share

$

5.90 

$

5.50 

$

5.14 

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

Net income attributable to IDACORP, Inc. - December 31, 2024

$

289.2 

Increase (decrease) in Idaho Power net income:

Retail revenues per MWh, net of power cost adjustment mechanisms

49.6 

Customer growth, net of associated power supply costs and power cost adjustment mechanisms

25.2 

Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms

(6.5)

Other O&M expenses

(9.6)

Depreciation and amortization expense

(27.7)

Other changes in operating revenues and expenses, net

(3.8)

Increase in Idaho Power operating income

27.2 

Non-operating expense, net

(22.8)

Additional ADITC amortization

10.5 

Income tax expense, excluding additional ADITC amortization

20.4 

Total increase in Idaho Power net income

35.3 

Other IDACORP changes (net of tax)

(1.0)

Net income attributable to IDACORP, Inc. - December 31, 2025

$

323.5 

IDACORP's net income increased $34.3 million for 2025 compared with 2024, due primarily to higher net income at Idaho Power.

The net increase in retail revenues per MWh, net of power cost adjustment mechanisms, increased operating income by $49.6 million in 2025 compared with 2024. This benefit was primarily due to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. For more information on the 2024 Idaho Limited-Issue Rate Case, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Idaho Power's customer growth of 2.3 percent added $25.2 million to Idaho Power's operating income in 2025 compared with 2024. Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms, decreased operating income by $6.5 million in 2025 compared with 2024. During 2025, usage per customer decreased for most customer classes. Milder temperatures during the year reduced the demand for both space heating and air conditioning. This decrease was partially offset by an increase in irrigation usage per customer, as lower precipitation during the summer led irrigation customers to run irrigation pumps more frequently. Partially offsetting the revenue impact of decreased usage per customer, a decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively impacted retail revenues by $6.8 million.

Other O&M expenses in 2025 were $9.6 million higher than in 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and increases in statutory fees assessed by regulators.

Depreciation and amortization expense increased $27.7 million in 2025 compared with 2024, due primarily to an increase in plant-in-service. Additionally, the start of operations at a leased battery storage facility in the second quarter of 2025 contributed modestly to the increase through amortization of a related right-of-use asset.

Other changes in operating revenues and expenses, net, decreased operating income by $3.8 million in 2025 compared with 2024, due primarily to the successful conclusion of multi-year litigation efforts challenging Idaho and Oregon property tax valuations, which resulted in refunds of prior year taxes being finalized in 2024, which did not reoccur in 2025. In addition, the timing of recording and adjusting regulatory accruals and deferrals positively impacted 2024 results, but did not reoccur in 2025. These decreases were partially offset by recovery of costs of a new finance lease through Idaho Power's power cost adjustment mechanism rates and a decrease in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms.

Non-operating expense, net, increased $22.8 million in 2025 compared with 2024. Higher long-term debt balances and an increase in transmission customer deposits, on which Idaho Power must pay interest to the customer, led to an increase in interest expense. Interest on a new finance lease also contributed to the increased interest expense compared with 2024. This

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increase was partially offset by an increase in AFUDC during 2025 compared with 2024, as the average construction work in progress balance was higher.

Idaho Power recorded $40.3 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during 2025, compared with $29.8 million in 2024. The $20.4 million decrease in income tax expense, excluding additional ADITC amortization, in 2025 compared with 2024 was primarily due to income tax return adjustments for state taxes and plant-related flow-through items.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition are affected by a number of factors, and the impact of those factors is discussed in more detail below in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors include the following:

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

To address the regulatory lag in recovery of costs primarily associated with Idaho Power’s current and anticipated significant infrastructure investments, in May 2025 Idaho Power filed a general rate case in Idaho and in October 2025 Idaho Power, the IPUC Staff, and intervening parties filed the 2025 Settlement Stipulation with the IPUC. In December 2025, the IPUC approved the 2025 Settlement Stipulation. The IPUC order related to the 2025 Settlement Stipulation is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. The 2025 general rate case followed a limited-scope rate case that Idaho Power filed in Idaho in 2024, as well as general rate cases that Idaho Power filed in Oregon and Idaho in 2023. In light of the regulatory lag in recovery of costs within Idaho Power's substantial capital expenditures to address growth, maintain system reliability, and ensure an adequate supply of electricity, Idaho Power is evaluating its potential rate case filings for 2026.

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

Idaho Power expects its capital expenditures on infrastructure investments in the next five years or more will be considerable as it works to address projected energy and capacity deficits. For more information about forecasted capital expenditures and expected rate base growth, see the "Liquidity and Capital Resources" section of this MD&A.

•Economic Conditions and Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. In recent years, Idaho Power has seen significant growth in the number of customers in its service area. In 2025, Idaho Power's customer count grew by 2.3 percent. While recessionary or volatile economic conditions could slow the rate of customer growth, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase for the foreseeable future.

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

5-Year Forecasted Annual Growth Rate

20-Year Forecasted Annual Growth Rate

Retail Sales

(Billed MWh)

Annual Peak

(Peak Demand)

Retail Sales

(Billed MWh)

Annual Peak

(Peak Demand)

2025 IRP

8.3%

5.1%

2.7%

1.9%

2023 IRP

5.5%

3.7%

2.1%

1.8%

2021 IRP

2.6%

2.1%

1.4%

1.4%

Customer growth has contributed to increases in peak loads experienced in recent years. For example, Idaho Power's highest all-time winter peak demand of 2,719 MW occurred on January 16, 2024, and on July 22, 2024, Idaho Power reached a new all-time summer peak demand of 3,793 MW. Idaho Power believes that existing and sustained growth in customers, load, and peak demand for electricity, the obligation to maintain a safe and reliable system, along with changes in the regional transmission markets that have constrained the availability of transmission outside Idaho Power’s service area to import energy during peak load periods, require Idaho Power to increase its investment in capacity resources, transmission, and distribution infrastructure. This includes the B2H, GWW, and SWIP-N transmission projects, along with other capacity, energy, and transmission resource procurements, described in "Liquidity and Capital Resources" in this MD&A. Idaho Power has begun preparation of its 2027 IRP and expects to prepare an updated load forecast during 2026 as the basis for the 2027 IRP, which Idaho Power expects to file in the summer of 2027.

•Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters of each year, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Further, as Idaho Power's hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydropower generation decreases, Idaho Power must rely on more expensive generation resources and purchased power. When favorable hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms, which mitigate in large part the impact on earnings. For 2026, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 7.5 million MWh, compared with 7.0 million MWh in 2025 and average total annual hydropower generation of approximately 7.3 million MWh over the last 20 years.

•Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies significantly on natural gas and coal to fuel its generation facilities, long-term PPAs (including PURPA agreements), and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, generation resource maintenance outages, wholesale energy market prices, transmission availability, and the outcome of Idaho Power’s hedging programs. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse earnings impacts to Idaho Power of fluctuations in power supply costs. However, collection from customers or return to customers of most of the difference between actual power supply costs compared with those included in retail rates

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is deferred to a subsequent period, which can affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from or returned to customers.

•Wildfire Mitigation Efforts: In recent years, the western United States has experienced severe wildfires. A variety of factors have contributed to this trend including increased wildland-urban interfaces, historical land management practices, climate change, and overall wildland and forest health. Idaho Power is taking a proactive approach to wildfire risk in its service area and transmission corridors. Several years ago, Idaho Power adopted a WMP that outlines actions Idaho Power is taking or is working to implement to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires, and Idaho Power has refined that WMP over time. Idaho Power's approach to wildfire mitigation includes identifying areas subject to elevated risk; system hardening programs, vegetation management, and field personnel practices to mitigate wildfire risk; incorporating current and forecasted weather and field conditions into operational practices; public safety power shutoff protocols; and evaluating the performance and effectiveness of its approach through metrics and monitoring. Idaho Power has regulatory authorization in both Idaho and Oregon to defer, for potential future amortization, certain actual incremental O&M expenses necessary to implement the WMP. The WMP regulatory deferrals are described in more detail in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. In July 2025, the Wildfire Standard of Care Act became effective in Idaho. In October 2025, Idaho Power filed a new WMP with the IPUC in accordance with Idaho's Wildfire Standard of Care Act. As of the date of this report, the IPUC's decision on the filing is pending. See "Other Matters - Idaho's Wildfire Standard of Care Act" for additional details.

RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s financial results of operations for 2025, compared with 2024.

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last two years ended December 31.

2025

2024

Retail energy sales

16,177 

15,971 

Wholesale energy sales

1,381 

1,412 

Energy sales bundled with RECs

1,516 

1,406 

Total energy sales

19,074 

18,789 

Hydropower generation

7,021 

7,203 

Jointly-owned thermal generation(1)

2,906 

2,474 

Natural gas-fired and other generation

3,685 

3,843 

Total system generation

13,612 

13,520 

Purchased power

6,783 

6,541 

Line losses

(1,321)

(1,272)

Total energy supply

19,074 

18,789 

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

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For purposes of illustration, Boise, Idaho weather-related information for the last two years ended December 31 is presented in the table that follows.

2025

2024

Normal(2)

Heating degree-days(1)

4,639 

4,844 

5,321 

Cooling degree-days(1)

1,255 

1,432 

1,045 

Precipitation (inches)

11.8 

15.6 

11.5 

(1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree above 65 degrees is counted as one cooling degree-day, and each degree below 65 degrees is counted as one heating degree-day. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service area, the greater Boise area has the majority of Idaho Power's customers.

(2) Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The annual normal amounts are the sum of the 12 monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration.

Sales Volume and Generation: In 2025, retail sales volumes increased 1 percent compared with the prior year, primarily due to growth in the number of Idaho Power customers. The number of Idaho Power customers grew by 2.3 percent in 2025. For more information on the changes in sales volume, see the "Operating Revenues" section below in this MD&A.

Total system generation increased 1 percent in 2025 compared with 2024, due primarily to higher jointly-owned thermal generation, mostly offset by lower natural gas generation and hydropower generation. For more information on the changes in sales volume, see the "Operating Expenses" section below in this MD&A.

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

Operating Revenues

Retail Revenues: The tables below present Idaho Power’s retail revenues (in thousands of dollars), MWh sales (in thousands of MWh), and number of retail customers for the last two years ended December 31.

2025

2024

Retail revenues:

Residential (includes $3,972 and ($2,686), respectively, related to the FCA(1))

$

708,126 

$

700,586 

Commercial (includes ($76) and ($170), respectively, related to the FCA(1))

394,313 

397,385 

Industrial

270,571 

267,211 

Irrigation

198,468 

196,401 

Deferred revenue related to HCC relicensing AFUDC(2)

(15,120)

(8,803)

Total retail revenues

$

1,556,358 

$

1,552,780 

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

(2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process in its Idaho jurisdiction, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Effective October 1, 2025, Idaho Power began collecting $38.5 million annually. Prior to October 1, 2025, Idaho Power collected $8.8 million annually. For more information refer to Note 3 - "Regulatory Matters" to the consolidated financial statements in this report. Amounts collected in the Idaho jurisdiction are recognized as deferred revenue until the license is issued and the accumulated license costs approved for recovery are placed in service.

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MWh Sales

Retail Customers

2025

2024

2025

2024

Residential

6,010 

5,964 

560,606 

547,010 

Commercial

4,348 

4,332 

80,832 

79,496 

Industrial

3,775 

3,680 

149 

145 

Irrigation

2,044 

1,995 

22,627 

22,554 

Total

16,177 

15,971 

664,214 

649,205 

Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last two years. The primary influences on customer demand for electricity are weather, economic conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while mild temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted, providing for higher rates during summer peak load periods, and residential customer rates are tiered, providing for higher rates based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.

Retail Revenues: Retail revenues increased $3.6 million in 2025 compared with 2024. The primary factors affecting retail revenues during the period were the following:

•Rates: Customer rates, excluding revenues related to power cost adjustment mechanisms, increased retail revenues by $49.6 million in 2025 compared with 2024, due primarily to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which decreased revenues by $71.2 million in 2025 compared with 2024. The adjustments related to the Idaho-jurisdiction PCA in rates do not have a significant effect on operating income as a corresponding amount is recorded in expense in the same period it is collected through rates.

•Customers: Customer growth of 2.3 percent increased retail revenues by $39.4 million in 2025 compared with 2024.

•Usage: Lower usage (on a per customer basis) in most customer classes decreased retail revenues by $20.9 million during 2025 compared with 2024, primarily due to weather variations that caused lower usage per customer. Milder temperatures during the year reduced the demand for both space heating and air conditioning. This decrease was partially offset by an increase in irrigation usage per customer, as lower precipitation during the summer led irrigation customers to run irrigation pumps more frequently.

•FCA Mechanism: A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $6.8 million in 2025 compared with 2024.

Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the western EIM, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales for the last two years ended December 31 (in thousands of dollars and MWh, except for revenue per MWh amounts). 

2025

2024

Wholesale energy revenues

$

55,989 

$

73,908 

Wholesale MWh sold

1,381 

1,412 

Wholesale energy revenues per MWh

$

40.54 

$

52.34 

In 2025, wholesale energy revenue decreased by $17.9 million, or 24 percent, compared with 2024, due primarily to lower wholesale market prices. Wholesale energy prices were lower during 2025 compared with 2024 as more moderate winter and summer weather resulted in lower natural gas fuel costs in the wholesale markets in the region. The financial impacts of

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fluctuations in wholesale energy sales are largely mitigated by Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms" in this MD&A.

Energy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency riders fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. The cumulative variances between expenditures and amounts collected through the riders are recorded as regulatory assets or liabilities. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2025, Idaho Power's energy efficiency rider balances were a $13.4 million regulatory liability in the Idaho jurisdiction and a $3.1 million regulatory liability in the Oregon jurisdiction.

Operating Expenses

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last two years ended December 31 (in thousands of dollars and MWh, except for per MWh amounts). 

2025

2024

Purchased power expense

$

392,462 

$

425,082 

MWh purchased

6,783 

6,541 

Average cost per MWh

$

57.86 

$

64.99 

Purchased power expense decreased $32.6 million, or 8 percent, in 2025 compared with 2024. The decrease in purchased power expense in 2025 is primarily due to lower wholesale energy market prices as milder winter and summer weather resulted in lower fuel costs (natural gas and coal) in the wholesale markets in the region. For further information on purchased power activities, see Part I, Item 1 – Utility Operations – "Power Supply – Purchased Power."

Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last two years ended December 31 (in thousands of dollars and MWh, except for per MWh amounts).

Fuel Expense

MWh Generated

Cost per MWh

2025

2024

2025

2024

2025

2024

Jointly-owned thermal(1)

$

115,924 

$

97,427 

2,906 

2,474 

$

39.89 

$

39.38 

Natural gas(2)

137,312 

161,777 

3,685 

3,843 

37.26 

42.10 

Total/Weighted average, all

$

253,236 

$

259,204 

6,591 

6,317 

$

38.42 

$

41.03 

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

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

The majority of the fuel for Idaho Power’s jointly-owned thermal plants is purchased through long-term contracts, including coal purchases from BCC, a one-third owned investment of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies the majority of the coal used by the Jim Bridger plant and BCC does not have significant sales to third parties. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods.

Fuel expense decreased $6.0 million, or 2 percent, in 2025 compared with 2024. In 2025, jointly-owned thermal generation increased 17 percent to serve load and provide power for wholesale energy sales compared with 2024. The impact of this generation increase on fuel expense was more than offset during 2025 by lower natural gas market prices compared with 2024.

Included in fuel expense are losses and gains on settled financial gas hedges entered into in accordance with Idaho Power's energy risk management policy. In 2025 and 2024, losses on financial gas hedges of $37.7 million and $63.3 million, respectively, increased natural gas fuel expense. Most of these realized hedging losses and gains are passed on to customers through the power cost adjustment mechanisms described below.

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Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases, export credit mechanisms, a battery storage lease, and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. However, the IPUC directed Idaho Power to spread recovery of the March 31, 2023 PCA deferral balance over a two-year period from June 1, 2023 to May 31, 2025. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.

The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last two years ended December 31 (in thousands of dollars). 

2025

2024

Idaho power supply cost accrual (deferral)

$

25,448 

$

(5,606)

Oregon power supply cost (deferral) accrual

(2,787)

1,954 

Amortization of prior year authorized balances

2,336 

93,409 

Total power cost adjustment (income statement)

$

24,997 

$

89,757 

The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. During 2025, purchased power costs led to lower actual power supply costs compared with the forecasted amount, which resulted in an accrual of power supply costs by the mechanism. In 2024, higher purchased power expense and fuel costs led to higher actual power supply costs compared with the forecasted amount, which resulted in the deferral of power supply costs. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior power cost adjustment year (the true-up component of the power cost adjustment mechanism).

Other Operations and Maintenance Expenses: Other O&M expenses increased $9.6 million in 2025 compared with 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and increases in statutory fees assessed by regulators.

Income Taxes

IDACORP and Idaho Power's income tax expense decreased $28.8 million and $30.9 million, respectively, when compared with 2024. The changes were primarily due to income tax return adjustments for state taxes and plant-related flow-through items, and increased ADITC amortization at Idaho Power under its Idaho regulatory mechanism, described in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report. The decreases were offset partially by an increase in income taxes due to higher income before income taxes. For additional information relating to IDACORP's and Idaho Power's income taxes, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Idaho Power continues to pursue significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and component replacement. Cash capital expenditures, excluding AFUDC and net costs of removing assets from service, were $1.1 billion in 2025 and $981 million in 2024. Idaho Power

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expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $7.2 billion over the period from 2026 through 2030.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP.

As of February 13, 2026, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included the following:

•their respective $100 million and $400 million revolving Credit Facilities;

•their issuance of commercial paper, with program sizes of $100 million and $300 million, respectively. Idaho Power's commercial paper program may be increased up to the $400 million capacity of its credit facility;

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

•IDACORP's executed FSAs under its ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of February 13, 2026, would have been approximately $52 million;

•IDACORP's FSAs, independent of the ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of February 13, 2026, would have been approximately $558 million; and

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

IDACORP uses original issuances of shares for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and also intends to potentially use original issuances for share purchases within the Idaho Power Company Employee Savings Plan beginning in the first half of 2026. IDACORP may discontinue using original issuances of shares for these plans at any time.

In March 2025, IDACORP executed FSAs under its ATM offering program with various counterparties at an aggregate gross sales price of $52 million. Additionally, in May 2025, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties at an aggregate gross sales price of $575 million. IDACORP may settle the FSAs at any time up to their respective maturity dates. As of February 13, 2026, if IDACORP had elected to physically settle by delivering shares of common stock, aggregate cash proceeds from all outstanding FSAs would have been approximately $610 million.

As described in the "Financing Cash Flows" section below, during 2025, IDACORP physically settled FSAs under its ATM offering program with shares of common stock in exchange for cash proceeds and contributed a portion of the net proceeds to Idaho Power. For more detailed information about IDACORP's and Idaho Power's equity transactions, see Note 6 - "Common Stock" to the consolidated financial statements included in this report. Further, during 2025, Idaho Power issued first mortgage bonds and repaid maturing variable rate bonds. For more detailed information about Idaho Power's long-term debt transactions, see Note 5 - "Long-Term Debt" to the consolidated financial statements included in this report.

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

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

IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent equity. Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2025, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, with no impact to equity from unsettled FSAs, were as follows:

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IDACORP

Idaho Power

Debt

52%

52%

Equity

48%

48%

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

Operating Cash Flows

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

IDACORP’s and Idaho Power’s operating cash inflows in 2025 were $602 million and $568 million, respectively, an increase in cash flows from operations of $7 million for IDACORP and Idaho Power, when compared with the same period in 2024. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from the operating cash flows from Idaho Power. Significant items that affected the companies' operating cash flows in 2025 when compared with the same period in 2024 were as follows:

•a $34 million and $35 million increase in IDACORP and Idaho Power net income, respectively;

•changes in regulatory assets and liabilities, mostly related to the relative amounts of costs deferred and collected under the PCA and FCA mechanisms, decreased IDACORP and Idaho Power operating cash flows by $84 million;

•changes in deferred taxes and taxes accrued and receivable combined to decrease operating cash flows for IDACORP and Idaho Power by $19 million; and

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

◦the timing of collections of accounts receivable and unbilled receivables decreased operating cash flows by $22 million for IDACORP and $23 million for Idaho Power;

◦the changes in materials, supplies, and fuel stock increased operating cash flows by $103 million for IDACORP and Idaho Power, which was primarily due to the timing of purchases and consumption of materials and supplies inventory at Idaho Power and coal at Idaho Power's jointly-owned coal-fired generating plants;

◦the changes in accounts and wages payable decreased operating cash flows by $33 million for IDACORP and Idaho Power, which was primarily due to timing of payments and higher quarterly cutoff accruals; and

◦the changes in other assets and liabilities increased operating cash flows by $5 million for IDACORP and Idaho Power, primarily due to a third-party deposit and a deferred termination payment.

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction of, and improvements to, Idaho Power’s power supply, transmission, and distribution facilities. IDACORP's and Idaho Power's net investing cash outflows for 2025 was $1.0 billion, increasing cash outflow by $111 million for IDACORP and by $98 million for Idaho Power when compared with the same period in 2024. Investing cash outflows for 2025 and 2024 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth and peak resource needs, aging plant and equipment, and environmental and regulatory compliance requirements. Significant items and transactions that affected investing cash flows in 2025 and 2024 included:

•$1.2 billion and $1.0 billion, respectively, of additions to property, plant, and equipment;

•$152 million and $84 million, respectively, from B2H project joint permitting participants relating to a portion of the permitting expenditures;

•$16 million and $4 million, respectively, of tax credit investments in affordable housing and other real estate, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits at IDACORP; and

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•IDACORP and Idaho Power paid $11 million and $8 million in 2025, respectively, and $12 million and $11 million in 2024, respectively, for purchases of equity securities, $3 million in 2025 and $2 million in 2024 for purchases of held-to-maturity securities, and received $12 million in 2025 and $11 million in 2024 from sales of equity securities, held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's SMSP.

Financing Cash Flows

Financing activities primarily provide supplemental cash for both day-to-day operations and capital requirements as needed. IDACORP's and Idaho Power's net financing cash inflows for 2025 were $274 million and $376 million, respectively, a decrease of $91 million for IDACORP and an increase of $104 million for Idaho Power, when compared with the same period in 2024. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, dividends, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, payment of dividends, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. Significant items and transactions that affected financing cash flows in 2025 and 2024 were as follows:

•in 2025 and 2024, Idaho Power issued $400 million and $300 million, respectively, in aggregate principal amount of first mortgage bonds;

•in 2025 and 2024, Idaho Power repaid $20 million in principal amount of maturing variable rate bonds and $50 million in principal amount of pollution control revenue bonds, respectively;

•in 2025, IDACORP received $92 million of aggregate cash proceeds from the settlement of FSAs under its ATM offering program;

•in 2024, IDACORP received $292 million of aggregate cash proceeds from the settlement of FSAs, independent of the ATM offering program;

•in 2025 and 2024, Idaho Power received $195 million and $200 million, respectively, of capital contributed from IDACORP; and

•IDACORP and Idaho Power paid dividends of $188 million each in 2025, and $177 million and $176 million, respectively, in 2024.

Financing Programs and Available Liquidity

IDACORP Equity Programs: As of February 13, 2026, IDACORP's cumulative aggregate gross sales price of executed and outstanding FSAs under its ATM offering program was $52 million, and $155 million in shares of IDACORP’s common stock remained available for issuance. If IDACORP had elected to physically settle the FSAs under its ATM offering program as of February 13, 2026, by delivering shares of common stock, cash proceeds would have been approximately $52 million. IDACORP may settle the FSAs under its ATM offering program at any time, up to their respective maturity dates of March 31, 2026.

In May 2025, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties in connection with a completed $575 million registered public offering of approximately 5.2 million shares of its common stock. If IDACORP had elected to physically settle these FSAs as of February 13, 2026, by delivering shares of its common stock, cash proceeds would have been approximately $558 million. IDACORP may settle these FSAs at any time, up to their maturity date of November 9, 2026.

As described elsewhere in this MD&A, IDACORP has significant planned capital expenditures in the near-term, and the company may settle the FSAs at any time up to the maturity date. See Note 6 - "Common Stock" to the consolidated financial statements included in this report for more information on IDACORP's equity programs. Depending on market conditions, its financial and regulatory strategy, and other factors, IDACORP could determine to issue additional equity securities in 2026.

Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and WPSC. In February and March 2024, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. At December 31, 2025, $500 million remained available for debt issuance under the regulatory orders. For more detailed information about Idaho Power First Mortgage Bonds, see Note 5 - "Long-Term Debt" to the consolidated financial statements included in this report.

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IDACORP and Idaho Power Credit Facilities: In December 2023, IDACORP and Idaho Power entered into credit agreements for $100 million and $400 million Credit Facilities, respectively. These facilities replaced IDACORP's and Idaho Power's then existing credit agreements. The IDACORP Credit Facility, which may be used for general corporate purposes, consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. The Idaho Power Credit Facility, which may be used for general corporate purposes, consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $400 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $50 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $600 million, respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power Credit Facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or Term Secured Overnight Financing Rate (SOFR) plus 1.0 percent, or 1.0 percent, or (2) the Term SOFR, plus, in each case an applicable margin, provided that the Term SOFR will not be less than 0.0 percent. If during any period the Term SOFR rate is unavailable or unascertainable, an alternate benchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by rating agencies, as set forth on a schedule to the credit agreements. Under their respective Credit Facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt. In December 2025, IDACORP and Idaho Power entered into an extension and amendment to each credit agreement, extending the maturity date under both credit agreements to December 6, 2030, and providing for two additional one-year extensions, in each case subject to certain conditions.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2025, the leverage ratios for IDACORP and Idaho Power were 52 percent. IDACORP's and Idaho Power's ability to utilize their respective Credit Facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the Credit Facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2025, IDACORP and Idaho Power believe they were in compliance with all of their respective Credit Facility covenants and, as of the date of this report, do not believe they will be in violation or breach of such covenants during 2026.

The events of default under the Credit Facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the occurrence of certain events related to the environment, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders), or the administrative agent with the consent of the required lenders, may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.

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In November and December 2023, Idaho Power obtained approval from the IPUC, OPUC, and WPSC for unsecured short-term borrowings at any one time outstanding not to exceed $600 million through December 2030, subject to certain requirements under the order.

IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective Credit Facilities, described above. IDACORP's and Idaho Power's Credit Facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity

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

December 31, 2025

December 31, 2024

IDACORP(1)

Idaho Power

IDACORP(1)

Idaho Power

Revolving credit facility

$

100,000 

$

400,000 

$

100,000 

$

400,000 

Commercial paper outstanding

— 

— 

— 

— 

Identified for other use(2)

— 

— 

— 

(19,885)

Net balance available

$

100,000 

$

400,000 

$

100,000 

$

380,115 

(1) Holding company only.

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

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

2025

2024

IDACORP(1)

Idaho Power

IDACORP(1)

Idaho Power

Commercial Paper:

Period end:

Amount outstanding

$

— 

$

— 

$

— 

$

— 

Weighted average interest rate

— 

%

— 

%

— 

%

— 

%

Daily average amount outstanding during the period

$

— 

$

— 

$

— 

$

191 

Weighted average interest rate during the period

— 

%

— 

%

— 

%

5.62 

%

Maximum month-end balance

$

— 

$

— 

$

— 

$

10,000 

(1) Holding company only.

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Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depend in part on their respective credit ratings. The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody's and Standard & Poor’s Ratings Services as of the date of this report:

Moody's

Standard & Poor's

IDACORP

Idaho Power

IDACORP

Idaho Power

Rating Outlook

Negative

Negative

Stable

Stable

Issuer Rating/Corporate

Baa2

Baa1

BBB

BBB

First Mortgage Bonds

None

A2

Senior Secured Debt

None

A2

None

A-

Commercial Paper/Short-Term

P-2

P-2

A-2

A-2

These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties, which are discussed further in Part II - Item 7A "Quantitative and Qualitative Disclosures About Market Risk" included in this report.

Capital Requirements

Idaho Power's cash capital expenditures, excluding AFUDC, were $1.1 billion during the year ended December 31, 2025. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2026 through 2030 (in billions of dollars). The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings. Actual expenditures and timing may differ substantially from the estimates in the table due to factors such as Idaho Power’s ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, regulatory determinations, inflationary pressures, macroeconomic conditions, or other issues, including those described below.

2026

2027

2028-2030

Expected capital expenditures (excluding AFUDC), in billions of dollars

$

1.3 - 1.5

$

1.4 - 1.6

$

3.6 - 4.1

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of relatively small projects as Idaho Power continues to add to its system to accommodate growth and maintain reliability and operational effectiveness. These projects involve significant capital expenditures in the aggregate. Examples of anticipated system enhancements planned for 2026 through 2030 and estimated costs include the following:

•$220-$310 million per year for construction and replacement of transmission lines and stations other than the B2H, GWW, and SWIP-N projects discussed below;

•$230-$325 million per year for construction and replacement of distribution lines and stations;

•$20-$60 million per year for ongoing improvements and replacements at thermal plants;

•$115-$150 million per year for hydropower plant improvement programs, including relicensing costs; and

•$75-$100 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.

Other Major Infrastructure Projects: Idaho Power is developing a number of significant infrastructure projects, including some developed jointly with third parties. The most notable projects are described below.

Resource Additions to Address Projected Energy and Capacity Deficits: Idaho Power's existing and sustained growth in customers, load, and peak demand for electricity, along with transmission constraints, has created the need for Idaho Power to

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acquire significant generation, transmission, and storage resources to meet energy and capacity needs in recent years and continuing over the next several years. In addition to resources already placed in service through 2025, Idaho Power has undertaken the following efforts to help meet peak needs in 2026 and beyond:

•entered into contracts or plans to construct, own, and operate 250 MW of battery storage assets with expected useful lives of approximately 20 years;

•entered into a 20-year agreement to purchase the storage capacity from a 100 MW battery storage facility;

•entered into an energy and capacity market purchase agreement with an energy marketer giving Idaho Power the right to acquire 200 MW on a daily basis during summer months beginning in 2026 for a term of at least five years;

•entered into four PPAs for a combined 625 MW output of planned third-party solar facilities. Idaho Power plans to sell the output of two of these solar PPAs totaling 445 MW exclusively to a large industrial customer pursuant to an agreement under Idaho Power’s Clean Energy Your Way program; and

•submitted an application to the IPUC for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant in 2028.

The capital requirements table above includes capital expenditures of more than $1.7 billion from 2026 through 2030 for resource additions to address projected energy and capacity deficits in those years and beyond. Included in this amount are estimates of costs of resource additions for which Idaho Power has received CPCNs or has entered into significant financial commitments and expects to request a CPCN for the resource in the near future. Idaho Power continues to evaluate resource needs and outstanding RFPs. Actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures depending on factors such as RFP results, the timing of project in-service dates, estimated load and resource balances and customer growth, the nature and quantity of resources owned versus acquired under PPAs or similar agreements, and the outcome of regulatory proceedings.

B2H Transmission Line: The B2H line, a 300-mile high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, is expected to provide transmission service to meet future resource needs. Idaho Power began construction in June 2025 and, based on the anticipated construction schedule as of the date of this report, expects the in-service date for the transmission line will be by late 2027.

In 2023, Idaho Power entered an agreement with BPA to transfer BPA's 21 percent ownership interest in the project to Idaho Power, increasing Idaho Power's interest to approximately 45 percent. PacifiCorp's ownership interest in the project is approximately 55 percent. Idaho Power has spent approximately $671 million, including Idaho Power's AFUDC, on the B2H project through December 31, 2025. Pursuant to the terms of joint funding arrangements, Idaho Power has received $360 million in reimbursement as of December 31, 2025, from project co-participants for their share of costs and continues to receive reimbursement as costs are incurred. PacifiCorp is obligated to reimburse Idaho Power for its share of any future project expenditures incurred by Idaho Power under the terms of the joint funding agreement. Idaho Power and PacifiCorp operate under a construction funding agreement filed with the FERC.

The permitting phase of the B2H project was subject to federal review and approval by various federal agencies. Federal agency records of decision have been received and all lawsuits challenging the federal rights-of-way have been resolved. In the separate State of Oregon permitting process, Oregon's Energy Facility Siting Council approved Idaho Power's site certificate in 2022 followed by a final order and two amendments to the site certificate, both contested but upheld in subsequent judicial proceedings. In 2023, the IPUC, OPUC, and WPSC granted Idaho Power and PacifiCorp their respective CPCNs related to the construction of the B2H project. In June 2025, three parties filed complaints with the OPUC seeking reconsideration of the CPCN granted for B2H, but in November 2025, the OPUC upheld the B2H CPCN. Those parties have now filed three complaints in the Baker County and Union County Circuit Courts challenging the OPUC decision. These cases remain pending. In addition, in September 2025, two parties filed complaints in Morrow County Circuit Court alleging that the Oregon Department of Energy and the Oregon Energy Facility Siting Council improperly modified the Fire Protection and Suppression Plan. Idaho Power has moved to dismiss that claim, and the case remains pending.

Total cost estimates for the project are between $1.5 billion and $1.7 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $415 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining material procurement and construction of the project.

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

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has expended approximately $91 million, including Idaho Power's AFUDC, for its share of the project costs through December 31, 2025.

The permitting phase of the GWW project was subject to review and approval of the BLM. The BLM has published its records of decision for all segments of the transmission line. In 2020 and 2024, PacifiCorp completed construction and commissioned segments of its portion of the project in Wyoming. In March 2023, PacifiCorp initiated the pre-construction phase of approximately 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho. Idaho Power has ownership interest in four segments within this area, totaling approximately 330 miles of new line.

Current permitting and pre-construction activities are focused on the segment of line between the Hemingway substation and the Midpoint substation, near Jerome, Idaho. Idaho Power is the majority owner of the approximately 130-mile segment, and, as of the date of this report, Idaho Power estimates the total cost for its share of this segment and the associated substation work to be between $900 million and $1.1 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $790 million of Idaho Power's share of estimated costs (excluding AFUDC) for the permitting and construction phases of the project based on Idaho Power's assumption that it may commence construction of this segment during that time period. Idaho Power expects the in-service date for this segment of line or a portion of this segment will be 2028 or later. Idaho Power and PacifiCorp continue to coordinate the timing of next steps of the remaining co-owned segments to best meet customer and system needs, including potentially modifying the ownership structure of those segments of the project.

SWIP-N: In February 2025, Idaho Power entered into a commitment to become a partial owner of SWIP-N, a planned 285-mile, high-voltage transmission line between the Robinson Summit Substation near Ely, Nevada, and the Midpoint Substation near Jerome, Idaho. Upon the project being placed into service, the applicable agreements provide that Idaho Power will purchase an approximate 11 percent ownership interest in the project, entitling Idaho Power to approximately 11 percent of the total capacity of the SWIP-N line. In addition, Idaho Power entered into a capacity entitlement agreement entitling Idaho Power to approximately 11 percent of additional capacity on the SWIP-N line over a 40-year term commencing upon the project being placed in service. Idaho Power expects construction of the project to commence in 2026 and to be completed in 2028 or thereafter. Idaho Power is responsible for approximately 11 percent of the total costs to develop and construct the project. The capital requirements table above includes Idaho Power's share of the costs to develop and construct the project. The project agreements do not require Idaho Power to incur any costs to purchase its ownership interest or begin paying for capacity under the capacity entitlement agreement until the line is in service. Idaho Power has an option to purchase the ownership interest associated with such capacity entitlement upon expiration of the 40-year term. On December 12, 2025, the IPUC issued its order approving a CPCN for the project. SWIP-N has received various required governmental approvals, including from the FERC and the Public Utilities Commission of Nevada, while certain other approvals and permits remain in process.

Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 36 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining a new long-term license for the HCC from the FERC. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant. Costs for the relicensing of Idaho Power's hydropower projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through the regulatory process.

Relicensing costs of $536 million (including AFUDC) for the HCC were included in construction work in progress at December 31, 2025. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $38.5 million of AFUDC annually relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of December 31, 2025, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $281 million. As discussed in Note 3 – “Regulatory Matters – Notable Idaho Base Rate Adjustments – Recovery of Incremental AFUDC Associated with HCC" to the consolidated financial statements included in this report, in March 2025, Idaho Power filed an application with the IPUC to increase the annual cash collection of AFUDC associated with relicensing of the HCC project from $8.8 million to $38.5 million. In September 2025, the IPUC approved Idaho Power's proposed increase in annual cash collection to recover AFUDC associated with relicensing of the HCC project, effective October 1, 2025.

As of the date of this report, Idaho Power anticipates that the FERC could issue a new HCC license in 2027 or thereafter. However, the exact timing, as well as the total capital investment and ongoing operating and maintenance costs required to comply with the new license remain uncertain. Idaho Power estimates that annual costs to obtain a new long-term license, including AFUDC but excluding post-issuance compliance cost, will range from $35 million to $45 million until the license is

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issued. Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses to meet the long-term license's terms and conditions could also be significant. Following Idaho Power's application, the IPUC issued an order in April 2018 approving a settlement stipulation among the parties recognizing that a total of $216.5 million in expenditures were prudently incurred and, therefore, should be eligible for inclusion in customer rates in a future rate proceeding.

In December 2025, Idaho Power filed an application with the IPUC requesting a determination that $305 million of additional costs between January 1, 2016 and September 30, 2025, to relicense the HCC were also prudently incurred. Idaho Power plans to file a supplemental application in this case in 2026 for the inclusion of additional costs incurred during the final three months of 2025. This case remains pending.

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

Environmental Regulation Costs: Idaho Power anticipates that it will continue to incur significant expenditures for its compliance with environmental regulations related to the operation of its hydropower and thermal generation facilities. In addition, Idaho Power expects it will continue to incur significant expenditures for its hydropower relicensing efforts. The near-term cost estimates for environmental matters are summarized in Part I, Item 1 - "Business - Environmental Regulation and Costs" of this report. The capital portion of these amounts is included in the capital requirements table above but does not include costs related to possible changes in current or new environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.

Defined Benefit Pension Plan Contributions and Recovery

Idaho Power contributed $20 million in 2025 and 2024 to its defined benefit pension plan. Idaho Power estimates that it has no minimum required contribution to be made during 2026. Depending on market conditions and cash flow considerations, Idaho Power expects that it could contribute up to $30 million to the pension plan during 2026. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position. Beyond 2026, Idaho Power expects continuing contributions under the pension plan could be significant. Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.

Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. At December 31, 2025 and 2024, Idaho Power's deferral balance associated with the Idaho jurisdiction was $247 million and $252 million, respectively. Deferred pension costs are amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. The IPUC has authorized Idaho Power to recover and amortize $35 million of deferred pension costs annually. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Contractual Obligations

IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2025, include long-term debt, interest payments, purchase obligations, leases, pension and post-retirement benefit plans, and other long-term liabilities specific to IDACORP, most of which are discussed throughout this MD&A. Refer to Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to purchase obligations and other long-term liabilities.

Dividends

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of

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IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is generally dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power.

IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 60 percent and 70 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of directors' dividend decisions. In September 2025, IDACORP adjusted the near-term target payout ratio to between 50 percent and 60 percent of IDACORP earnings, considering Idaho Power's financing needs to fund its capital investments and ongoing operations. Notwithstanding IDACORP's dividend policy, the dividends IDACORP pays remain in the discretion of the board of directors, which, when evaluating the dividend amount, will continue to take into account the factors above, among others. In September 2025 and 2024, IDACORP's board of directors voted to increase the quarterly dividend to $0.88 per share and $0.86 per share of IDACORP common stock, respectively. IDACORP's dividends during 2025 were 58.6 percent of actual 2025 earnings.

For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 – “Common Stock” to the consolidated financial statements included in this report.

Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business that could affect their future results of operations and financial condition. In many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of potential new regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

Off-Balance Sheet Arrangements

IDACORP’s and Idaho Power’s off-balance sheet arrangements as of December 31, 2025, include guarantees of Idaho Power's portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. See Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to off-balance sheet arrangements.

REGULATORY MATTERS

Introduction

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

Idaho Power develops its regulatory filings taking into consideration short-term and long-term needs for rate relief and several other factors that can affect the structure and timing of those filings. These factors include in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates, as well as other factors. Idaho Power filed a general rate case in Idaho in 2025, which was resolved by the 2025 Settlement Stipulation, as approved by the IPUC in December 2025. The 2025 Settlement Stipulation provided for Idaho Power to implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by approximately $110.0 million, or 7.48 percent, effective January 1, 2026. In light of the regulatory lag in recovery of costs within Idaho Power's substantial capital

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expenditures to address growth, maintain system reliability, and ensure an adequate supply of electricity, Idaho Power is evaluating its potential rate case filings for 2026.

Previously, Idaho Power filed the 2024 Idaho Limited-Issue Rate Case in May 2024, focused on revenue requirements for 2024 incremental plant additions and incremental ongoing labor costs, which was resolved by an IPUC order in December 2024. Idaho Power also filed general rate cases in Idaho and Oregon in 2023, which were resolved by the 2023 Settlement Stipulation in Idaho and the 2024 Oregon Settlement Stipulations in Oregon.

Between general rate cases, Idaho Power relies upon customer growth, an FCA mechanism in Idaho, power cost adjustment mechanisms, limited-issue rate cases, WMP cost deferrals, project-specific cases, tariff riders, and other mechanisms to mitigate the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return.

Notable Retail Rate Changes in Idaho and Oregon

The table below presents notable recent retail rate changes that affected Idaho Power's results for the periods of this report or that will likely affect future periods. Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanisms and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A.

Description

Effective Date

Estimated Annualized Rate Impact (in millions of dollars)(1)

2025 Idaho general rate case

1/1/2026

$

110.0 

2025 Oregon rate adjustment

1/1/2026

(0.6)

2025 Idaho PCA

6/1/2025

(94.8)

2025 Idaho FCA

6/1/2025

(39.8)

2024 Idaho limited-issue rate case

1/1/2025

50.1 

2023 Oregon general rate case

10/15/2024

6.7 

2024 Idaho PCA

6/1/2024

(35.7)

2024 Idaho FCA

6/1/2024

11.7 

2023 Idaho general rate case

1/1/2024

54.7 

(1) The annual amount collected or refunded in rates is typically not recovered or refunded on a linear basis (i.e., 1/12th per month), and is instead recovered or refunded in proportion to retail sales volumes. The rate changes for the Idaho PCA and FCA are applicable only for one-year periods and represent the net change to the deferral balance from the prior year's filing, as well as a forecast component for the PCA.

Idaho and Oregon Rate Cases

As noted above, in December 2025, the IPUC issued an order approving the 2025 Settlement Stipulation, which resolved the Idaho general rate case Idaho Power had filed in May 2025. The 2025 Settlement Stipulation provided for Idaho Power to implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by approximately $110.0 million, or 7.48 percent, effective January 1, 2026. The approximate $110.0 million of additional annual revenue is inclusive of a PCA rate increase of $13.1 million. The ADITC and Revenue Sharing mechanism was updated as part of the 2025 Settlement Stipulation. At December 31, 2025, Idaho Power estimates that it had $167.8 million of deferred credits available for future use under the updated ADITC and Revenue Sharing mechanism.

In December 2024 and January 2025, the IPUC issued an order and subsequent errata in connection with Idaho Power's 2024 Idaho Limited-Issue Rate Case, providing for Idaho Power to implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $50.1 million, or 3.7 percent, effective January 1, 2025.

The 2023 Settlement Stipulation in connection with Idaho Power's 2023 Idaho general rate case provided for revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, effective January 1, 2024, net of an Idaho-jurisdiction PCA rate decrease of $168.3 million and a reduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates.

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In December 2023, Idaho Power filed a general rate case with the OPUC. In September 2024, the OPUC issued an order approving the 2024 Oregon Settlement Stipulations to settle the general rate case. The OPUC order and the 2024 Oregon Settlement Stipulations provided for revised tariff schedules designed to increase annual Oregon-jurisdiction revenue by $6.7 million, or 12.14 percent, effective October 15, 2024.

For more information on these rate cases, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Other Notable Regulatory Matters

Integrated Resource Plan and Resource Procurement Filings: Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2025, as described in Part 1, Item 1 - "Business - Resource Planning" in this report. The 2025 IRP identified the need for resources to meet projected capacity deficits in the near-term. The OPUC and the IPUC acknowledged the 2025 IRP in December 2025 and February 2026, respectively.

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

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

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

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

In March 2025, Idaho Power filed an application with the IPUC for an order (1) approving the 20-year PPA with Crimson Orchard Solar LLC supplying 100 MW of output to Idaho Power, (2) approving the 20-year energy storage agreement (SA) with Crimson Orchard Solar for 100 MW of dispatchable energy storage capacity, and (3) acknowledging the lease accounting necessary to facilitate the transaction and that the resulting expenses associated with both the PPA and the SA are prudently incurred for ratemaking purposes. In August 2025, Idaho Power also filed with the IPUC for approval of amendments to the PPA and SA for Crimson Orchard Solar. In December 2025 and February 2026, the IPUC issued an order and subsequent clarification approving the PPA, the SA, and the amendments and acknowledging that the SA may require the application of lease accounting, in each case subject to certain conditions.

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

In September 2025, Idaho Power filed an application with the IPUC for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant to meet an identified capacity deficit in 2028, as well as

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confirmation and approval by the IPUC of Idaho Power's accrual of AFUDC in connection with the project. As of the date of this report, the case remains pending.

Filing for Approval of Conversion of North Valmy Plant to Natural Gas: In January 2025, Idaho Power filed an application with the IPUC to grant approval of an agreement between Idaho Power and the co-owner of the North Valmy plant, NV Energy, to convert the two coal-fired units at the North Valmy plant to natural gas-fired steam turbines by mid-2026. In July 2025, the IPUC approved the agreement with NV Energy for the conversion of the two coal-fired units at the North Valmy plant to natural gas.

Filing for Approval of Wildfire Mitigation Plan: In October 2025, Idaho Power filed an application with the IPUC for approval of the Company's WMP in accordance with Idaho's Wildfire Standard of Care Act, which became effective in 2025. In December 2025, Idaho Power filed an application with the OPUC for approval of the company's 2026-2028 WMP. As of the date of this report, both cases remain pending.

Idaho Oversight Process for the Acquisition of Large Supply-Side Electrical Resources: In January 2026, the IPUC issued an order (1) rescinding its prior order requiring Idaho Power to comply with Oregon’s RFP guidelines, and (2) adopting an IPUC procedure for electric utilities to solicit large supply-side resources.

For more information on other notable regulatory matters, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Large Customer Rate Proceedings

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

Brisbie, LLC (Brisbie) Data Center and Clean Energy Your Way Special Contract: In May 2023, the IPUC approved a special contract (Brisbie Special Contract) between Idaho Power and a large load customer, Brisbie, a wholly-owned subsidiary of Meta Platforms, Inc., for service to a new enterprise data center. The Brisbie Special Contract allows Idaho Power to procure enough renewable resources to provide Brisbie with 100 percent renewable energy on an annual basis for Brisbie's facility. In November 2024, Idaho Power filed for IPUC approval of a PPA for Brisbie with a 320 MW solar project to be online as early as December 2027. Idaho Power will assign the cost and renewable attributes of the energy from the solar facility to Brisbie in accordance with the Brisbie Special Contract. In April 2025, the IPUC approved the PPA.

Deferred Net Power Supply Costs

Deferred (accrued) power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred (accrued) power supply costs are recorded on the balance sheets for future recovery or refund through customer rates.

Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The power cost adjustment mechanisms and associated financial impacts are described in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Factors that have influenced power cost adjustment rate changes in recent years include year-to-year volatility in hydropower generation conditions, market energy prices and the volume of wholesale energy sales, power purchase costs from renewable energy projects, and income tax reform. From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms. The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" in this MD&A are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.

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The following table summarizes the change in deferred (accrued) net power supply costs during 2025 (in millions of dollars):

Idaho

Oregon

Total

Balance at December 31, 2024

$

18.5 

$

(3.9)

$

14.6 

Current period net power supply costs (accrued) deferred

(25.4)

2.8 

(22.6)

Prior amounts (collected) refunded through rates

(3.2)

0.9 

(2.3)

REC sales

(28.2)

(1.2)

(29.4)

Interest and other

(2.7)

— 

(2.7)

Balance at December 31, 2025

$

(41.0)

$

(1.4)

$

(42.4)

Open Access Transmission Tariff Rate

Idaho Power uses a formula rate for transmission service provided under its OATT, which provides that transmission rates will be updated annually based primarily on financial and operational data that Idaho Power files with the FERC. In September 2025, Idaho Power filed its 2025 final transmission rate with the FERC, reflecting a transmission rate of $34.16 per kilowatt-year (kW-year), to be effective for the period from October 1, 2025 to September 30, 2026. Idaho Power's final rate was based on a net annual transmission revenue requirement of $148.5 million. The OATT rate in effect from October 1, 2024 to September 30, 2025, was $31.55 per kW-year based on a net annual transmission revenue requirement of $137.9 million. A kW-year is a unit of electrical capacity equivalent to 1 kW of power used for 8,760 hours.

Relicensing of Hydropower Projects

Overview: Idaho Power, like other utilities that operate non-federal hydropower projects on qualified waterways, obtains licenses for its hydropower projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. See Note 13 - "Property, Plant and Equipment and Jointly-Owned Projects" to the consolidated financial statements included in this report for information regarding relicensing costs for the HCC. In addition to the discussion below, refer to “Hells Canyon Complex Relicensing” in “Liquidity and Capital Resources” in this MD&A for a discussion of the costs and expected timing of an HCC license and "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydropower generating plants.

Hells Canyon Complex Relicensing: In 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In 2004, Idaho Power and eleven other parties involved in the HCC relicensing process, including NMFS and USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA-listed species pending the relicensing of the project. The FERC staff issued a final EIS in 2007.

In connection with its relicensing efforts, Idaho Power filed annual water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards. Challenges regarding how to meet water temperature standards below the HCC for spawning fall Chinook salmon, and a conflict in laws between Oregon and Idaho regarding the reintroduction and passage of fish above the HCC, delayed the issuance of the 401 certifications from the states for several years. In 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the FPA pre-empts the Oregon state law requiring reintroduction and passage, which the FERC denied in 2017. In 2018, Idaho Power appealed the FERC's 2017 order with the United States Court of Appeals for the District of Columbia Circuit, which is pending.

In 2019, the states of Idaho and Oregon, along with Idaho Power, reached a settlement pertaining to the CWA Section 401 certification that requires Idaho Power, among other measures, to implement a 20-year program to study the success of non-volitional passage of non-ESA listed anadromous fish into Pine Creek, an Oregon tributary to Hells Canyon Reservoir, and increase the number of Chinook salmon it releases each year through expanded hatchery production. In 2019, Oregon and Idaho issued final CWA Section 401 certifications which have been submitted to the FERC as part of the relicensing process. Also in 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the settlement among Idaho, Oregon, and Idaho Power. The FERC's decision relating to the Offer of Settlement is pending as of the date of this report.

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In 2020, Idaho Power submitted to the FERC its supplement to the final license application, incorporating the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications. The supplement included feedback on proposed modifications of the 2007 final EIS for the HCC, as well as an updated cost analysis of the HCC and a request that the FERC issue a 50-year license and initiate a supplemental NEPA process at the FERC. In 2022, the FERC issued a notice of intent to prepare a supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the USFWS and the NMFS under section 7 of the ESA. In April 2025, the FERC issued an updated schedule for the supplemental EIS with target dates for issuance of the draft and final supplemental EIS of September 2025 and May 2026, respectively. The FERC issued the draft supplemental EIS on January 14, 2026, which initiated a comment period until March 2, 2026. Idaho Power is reviewing the draft supplemental EIS. As part of issuing the draft supplemental EIS, the FERC also requested that USFWS and NMFS initiate formal consultation under section 7 of the ESA, indicating that it considered the draft supplemental EIS its biological assessment.

In February 2025, Idaho Power submitted to the FERC, to be included in the final HCC license, agreed-upon language between Idaho Power and the U.S. Army Corps of Engineers regarding flood control requirements applicable to the HCC.

American Falls Relicensing: In 2020, Idaho Power filed with the FERC a notice of intent to file an application to relicense the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a nameplate generating capacity of 92.3 MW and FERC authorized installed capacity of 67.5 MW. Idaho Power owns the generation facility but not the structural dam or reservoir, which are owned by the U.S. Bureau of Reclamation. Idaho Power filed the final relicensing application with the FERC in February 2023. In September 2024, the Idaho Department of Environmental Quality issued a final CWA Section 401 water quality certification. The FERC released its environmental assessment in accordance with NEPA in January 2025. Three parties commented on the environmental assessment, and Idaho Power has responded to those comments.

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

ENVIRONMENTAL MATTERS

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the CAA, the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's co-owned coal- and gas-fired power plant, its co-owned gas-fired power plant, and its three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's hydropower projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:

•increase the operating costs of generating plants;

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

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

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

•reduce the output from current generating facilities; or

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

Current and future environmental laws and regulations could significantly increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation or conversion to natural gas, as the cost of compliance makes coal plants uneconomical to operate. The

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decision to end coal-fired operations at the North Valmy plant was based in part on the economics of continuing coal-fired generation at the plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.

Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2026 to 2028. Given the uncertainty of future environmental regulations and technological advances, there is uncertainty around near-term estimates, and Idaho Power is also unable to predict its environmental-related expenditures beyond 2028, though they could be substantial. Changes in Presidential Administrations and Congressional elections since 2017 have resulted, and in the future could result, in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. Executive orders that could be issued by the current Presidential Administration and the outcome of U.S. federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict.

In addition, the court system has become more active in reviewing agency actions, resulting in even less certainty as to the outcome and durability of rules that are administratively implemented. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or conversions, or reduction or elimination of permitting requirements. More strict or robust regulations, or additional regulations, on the other hand, would likely increase Idaho Power's costs of operating and maintaining its facilities, and could impact Idaho Power's plans and pre-construction activities related to its major transmission projects, which could lead to substantially higher construction and permitting costs and could delay construction. Executive orders may be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level. Therefore, as of the date of this report, and except as specifically described below in this MD&A, Idaho Power is uncertain whether and to what extent current executive orders, any future executive orders, and the implementation of these and any future executive orders could affect its business, results of operations, and financial condition. Idaho Power will continue to monitor actions associated with or resulting from executive orders and new or revised legislation or regulation.

EPA Proposed Regulatory Actions

In March 2025, the EPA announced a set of proposed regulatory actions relating to environmental laws and regulations, many of which will impact Idaho Power if they are implemented. The proposed regulatory actions relate to the following laws and regulations, among others: the EPA's 2009 endangerment finding regarding six greenhouse gases; the Clean Air Act Section 111 rulemaking for new and existing generation units (also known as the Clean Power Plan 2.0); the MATS Rule; the Greenhouse Gas Reporting Program; effluent limitations guidelines and standards for the Steam Electric Power Generating Industry; the National Ambient Air Quality Standards for Particulate Matter (PM2.5); the Regional Haze Program; the “Good Neighbor Plan” and related State Implementation Plans; the coal ash program; and the definition of "Waters of the United States," which impacts applicability of the CWA to certain wetlands and water bodies.

The EPA has published proposed rules for several of the items mentioned in its March 2025 announcement, including the following:

•in June 2025, the EPA proposed rules to repeal greenhouse gas emissions standards for fossil fuel-fired power plants and to repeal certain amendments to the MATS Rule, including the revised filterable particulate matter (fPM) emission standard; the revised fPM emission standard compliance demonstration requirements; and the revised mercury emission standard for lignite-fired electric utility steam generating units;

•in September 2025, the EPA proposed revisions to the greenhouse gas reporting program to remove program obligations for most source categories, including for electric power generation;

•in November 2025, the EPA and the U.S. Department of the Army proposed revisions to the CWA, including the definition of "Waters of the United States"; and

•in January 2026, the EPA proposed to approve the SIPs of eight states, including Nevada.

The proposals are subject to public comment and remain pending as of the date of this report. In February 2026, the EPA finalized a rule rescinding the EPA's 2009 greenhouse gas endangerment finding The EPA has not yet taken official action on the other items mentioned in its March 2025 announcement. Idaho Power will continue to actively monitor these proposals and any other pending or potential environmental regulations related to environmental matters that may have an impact on its future

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operations. Given uncertainties regarding the outcome and timing for these EPA proposals, Idaho Power is unable to estimate the impact on Idaho Power of any such proposals.

National Environmental Policy Act Matters

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

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

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

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

Endangered Species Act Matters

Overview: The listing of a species of fish, wildlife, or plants as threatened or endangered under the ESA may have an adverse impact on Idaho Power's ability to construct power supply, transmission, or distribution facilities or relicense or operate its hydropower facilities.

Over the past few years and as a result of changes in Presidential Administrations, regulatory developments and executive orders have called into question the existing requirements under the ESA. Subsequent federal court decisions have in some cases undermined the effectiveness of those regulations and orders. The uncertainty in the regulatory landscape makes it difficult to predict the scope, timing and complexity of project-related ESA matters to be addressed.

There are a number of threatened or endangered species within Idaho Power's service area located in waterways in which Idaho Power has hydropower facilities, and within or near proposed transmission line routes. To date, efforts to protect these species have not significantly affected generation levels or operating costs at any of Idaho Power's hydropower facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases. These ESA regulations could impact the timing and feasibility of the HCC relicensing project and the GWW transmission project and other infrastructure projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay or prevent construction.

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

Developments in Regulation of Sage Grouse Habitat: In 2016, a group of lawsuits were filed in federal court to challenge the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuits challenge the plans and associated EISs across the sage grouse range, including in Idaho, and allege that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the lawsuits challenge certain exemptions provided for the B2H and GWW transmission line projects. Idaho Power has intervened in the proceedings to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, which

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could lead to substantially higher construction and permitting costs and could delay construction. As of the date of this report, the above lawsuits are stayed, as the parties and the courts have agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for the lawsuits.

In June 2017, the Secretary of the Interior directed the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. Following a series of interim measures, in February 2022, the BLM issued a notice of intent to amend its land use plans regarding sage grouse conservation and prepare associated EISs, and in November 2024, the BLM issued a proposed resource management plan amendment and final EIS. Idaho Power protested the 2024 plan amendment and EIS. In December 2025, the BLM published an updated resource management plan amendment and record of decision for Idaho and various other states. As of the date of this report, Idaho Power is unable to estimate the impact on Idaho Power of the updated resource management plan amendment and record of decision.

Revocation of "Blanket Rule" for Threatened Species and Revisions to Critical Habitat Designation Process: The listing of a species, or changes to the critical habitat designations, of fish, wildlife, or plants as threatened or endangered under the ESA and the associated mitigation policies may have an adverse impact on Idaho Power's ability to construct power supply, transmission, or distribution facilities or relicense or operate its hydropower facilities. In March 2024, the USFWS published a final rule which, among other items, reinstated the “blanket rule” that allows the USFWS to treat threatened species the same (or similar) as endangered species under Section 4(d) of the ESA. Subsequently, in November 2025, the USFWS and NMFS jointly published proposed rules, among other items, to revoke the "blanket rule" for threatened species and revise the process for designation of critical habitat. Based on ESA listings as of the date of this report, Idaho Power anticipates that the proposed changes will have limited or no impact on its projects.

ESA Issues Related to Specific Projects:

Hells Canyon Relicensing Project: In December 2004, Idaho Power and eleven other parties, including the NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Idaho Power prepared draft biological assessments in consultation with the USFWS and the NMFS and filed those with the FERC in October 2020; the biological assessments were subsequently updated in July 2025. In June 2022, the FERC issued a notice of intent to prepare a draft supplemental EIS and a final supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the USFWS and NMFS under section 7 of the ESA. As of the date of this report, Idaho Power anticipates that the final biological opinions will likely be issued after the FERC issues a final supplemental EIS, which is scheduled for May 2026 according to the FERC's updated schedule for issuance of the supplemental EIS. The FERC issued the draft supplemental EIS on January 14, 2026, which initiated a comment period until March 2, 2026. Idaho Power is reviewing the draft supplemental EIS.

GWW and B2H Transmission Projects and Other Infrastructure - Slickspot Peppergrass Designation: In 2016, the USFWS re-instated the threatened species status of slickspot peppergrass under the ESA. In 2020, the USFWS published a revised proposed rule designating critical habitat for the species, most of which are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed route for the GWW transmission line project and other transmission and distribution lines to increase the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation and potential mitigation. As of the date of this report, Idaho Power is uncertain whether such increases will be significant.

Climate Change and the Regulation of Greenhouse Gas Emissions

Overview: Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing CO2 emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Stringent emissions standards could result in significant increases in capital expenditures and operating costs, which may accelerate the retirement of coal-fired units and create power system reliability issues. Some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a cessation of operation, as the cost of compliance makes the plants uneconomical to operate. As a result, Idaho Power ended its participation in coal-fired operations at the North Valmy plant unit 1 in 2019 and unit 2 in 2025. Idaho Power's 2025 IRP

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identified a preferred resource portfolio and action plan that anticipates (1) converting North Valmy plant units 1 and 2 to natural gas by mid-2026; and (2) converting units 3 and 4 at the Jim Bridger plant from coal to natural gas in 2030.

A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions. These include the specific GHG emissions limits imposed, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates. Accordingly, Idaho Power cannot predict the effect on its results of operations, financial condition, or cash flows of any GHG emissions or other climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. A more detailed discussion of legislative and regulatory developments related to climate change follows.

National GHG Initiatives; Clean Power Plan/Affordable Clean Energy Rule: The EPA has been active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions. As noted above, in August 2025, the EPA proposed a rule to reconsider the EPA's 2009 greenhouse gas endangerment finding. In February 2026, the EPA finalized a rule rescinding the 2009 endangerment finding. Idaho Power does not expect any near-term impact on its plans or operations as a result but will continue to monitor any potential effects.

In 2010, the EPA issued the “Tailoring Rule,” which set thresholds for GHG emissions that define when permits are required for new and existing industrial facilities. While the rule is complex, Idaho Power believes that its owned and co-owned fossil fuel-fired generation plants are, as of the date of this report, in compliance with the GHG Tailoring Rule.

In 2015, the EPA issued the Clean Power Plan (CPP) under Section 111(d) of the CAA, which required states to adopt plans to collectively reduce 2005 levels of power sector CO2 emissions by 32 percent by 2030. In 2019, the EPA repealed the CPP and replaced it with the Affordable Clean Energy (ACE) rule under Section 111(d) of the CAA for existing electric utility generating units. In subsequent litigation, the ACE rule was vacated without reinstating the CPP.

In April 2024, the EPA released a final rule under Section 111 of the CAA (New Section 111 Rule) that regulates CO2 emissions from coal- and natural gas-fired electric generating units. Under the final rule, applicable standards of emission reduction vary based upon the retirement date of coal units and the capacity factor of existing and new natural gas units. The EPA based some of its requirements on carbon capture and storage technology. Idaho Power, among many other parties, filed suit in May 2024 in the U.S. Court of Appeals, D.C. Circuit, to challenge the New Section 111 Rule. Idaho Power's suit was consolidated with other similar suits, and the proceedings were placed on hold in February 2025 at the request of the EPA and remain on hold pending finalization of EPA's new Section 111 rules. As noted above, in June 2025, the EPA proposed to repeal all GHG emissions standards for fossil fuel-fired power plants. If the EPA's repeal of GHG emissions standards becomes effective, this will eliminate the New Section 111 Rule and any impacts it may have had on Idaho Power's coal- and natural gas-fired plants.

State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative: In 2007, Oregon enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050. Oregon also established its Oregon Clean Electricity and Coal Transition Plan in 2016, which requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030. Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states. To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base.

Idaho has not passed legislation specifically regulating GHGs. Wyoming has enacted legislation to regulate GHG emissions of utilities serving over 10,000 electric customers in Wyoming, which does not apply to Idaho Power. Nevada has not enacted legislation to regulate GHG emissions and does not have a reporting requirement, but it does prepare a greenhouse gas emissions inventory for the state of Nevada. Idaho Power is engaged in voluntary GHG emissions intensity reduction efforts, which is discussed in Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs."

Other Clean Air Act Matters

In addition to the CAA developments related to GHG emissions described above, several other regulatory programs developed under the CAA apply to Idaho Power. These include the final MATS Rule and the Good Neighbor Plan.

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The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, and sulfur dioxide. States are then required to develop emissions reduction strategies through SIPs, based on attainment of these ambient air quality standards. Recent developments and pending actions related to certain of those items are relevant to Idaho Power.

Regional Haze / Good Neighbor Plan: In June 2023, the EPA published the final rule under the CAA called the Federal "Good Neighbor Plan" for the 2015 Ozone National Ambient Air Quality Standards (Good Neighbor Plan), which took effect in August 2023. The Good Neighbor Plan establishes nitrogen oxides (NOx) emissions budgets requiring fossil fuel-fired power plants to participate in an allowance-based ozone season trading program. The EPA's final rule temporarily excluded power plants located in Wyoming, while the EPA reevaluated the proposed disapproval of the Wyoming SIP. In December 2023, the EPA approved the Wyoming SIP, removing it from the Federal Implementation Plan (FIP).

In April 2024, the EPA proposed to approve revisions to the Wyoming Regional Haze SIP for the first planning period of 2008-2018. The proposed SIP replaces Wyoming’s previously approved source-specific NOx determination for Idaho Power’s jointly-owned Jim Bridger plant. Operations at the Jim Bridger plant have previously been modified to comply in advance with the proposed SIP. Accordingly, Idaho Power does not expect the proposed SIP, if approved, to require any additional changes to current operations at the Jim Bridger plant. As of the date of this report, the EPA's approval of the Wyoming SIP for the first planning period is pending.

In August 2024, the EPA proposed to approve in part and disapprove in part the proposed Wyoming Regional Haze SIP for the second planning period of 2018-2028. The public comment period for the EPA's proposed action ended in September 2024. Idaho Power submitted comments requesting that the EPA approve in full Wyoming's Regional Haze SIP for the second planning period. In December 2024, EPA published its final partial disapproval of Wyoming’s Regional Haze SIP for the second planning period based in part on Wyoming’s failure to consider the four statutory factors for the Jim Bridger plant. In January 2025, Idaho Power filed a petition with the EPA for reconsideration of its final partial disapproval and also filed suit in the 10th Circuit Court of Appeals to challenge the EPA's final partial disapproval, both of which remain pending. In May 2025, the EPA notified Idaho Power that the EPA would voluntarily reconsider its partial approval and disapproval of the Wyoming SIP for the second planning period.

On June 27, 2024, the U.S. Supreme Court issued an opinion in Ohio v. EPA that granted an application to stay the EPA’s FIP promulgated under the Good Neighbor Provision of the CAA. This action puts a hold on any related compliance obligations for the North Valmy plant, which is co-owned by Idaho Power and NV Energy and operated by NV Energy. The stay is expected to remain in place until the U.S. Court of Appeals, D.C. Circuit, reaches a decision on the applicants' challenge to the FIP.

In October 2025, the EPA issued a request for comment on how the EPA can revise the Regional Haze rules to streamline regulatory requirements. Further, in December 2025, the EPA finalized an extension of the due date for the third planning period of SIPs from 2028 to 2031.

In January 2026, the EPA proposed to approve the SIPs of eight states, including Nevada, and withdraw proposed SIP disapprovals of five other states under the 2015 Ozone National Ambient Air Quality Standards. The proposal is subject to a comment period and remains pending.

As of the date of this report, Idaho Power continues to evaluate the specific impacts the Good Neighbor Plan could have on its operations at the North Valmy plant. If the January 2026 proposal to approve the Nevada SIP is finalized, Idaho Power anticipates that the Nevada SIP would not affect the current operations of the North Valmy plant.

Mercury and Air Toxic Standards: The MATS Rule in Section 112 of the CAA for coal-fired power plants provides that sources must comply with certain emission limits. Idaho Power and the co-owner of the Jim Bridger coal-fired generating plant installed mercury continuous emission monitoring systems on all coal-fired units at the plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS Rule.

In April 2024, EPA finalized updated standards for coal-fired power plants under the MATS Rule. As applicable to Idaho Power, the MATS Rule amends the filterable particulate matter (fPM) surrogate emission standard for non-mercury metal hazardous air pollutants to existing coal-fired power plants and the fPM emission standard compliance demonstration requirements. For coal-fired units at the Jim Bridger plant, the MATS Rule would require additional monitoring equipment and possibly other equipment upgrades. However in June 2025, as noted above, the EPA proposed amendments to the MATS Rule which, if finalized, would revise the fPM emission standard, the revised fPM emission standard compliance demonstration

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requirements, and the revised mercury emission standard for lignite-fired electric utility steam generating units. Idaho Power will continue to monitor developments with respect to the MATS Rule for possible impact to Idaho Power's operations.

CAA Section 111 New Source Performance Standards: In January 2026, the EPA finalized its “New Source Performance Standards Review for Stationary Combustion Turbines and Stationary Gas Turbines” under CAA Section 111. This rule applies to affected sources constructed, modified, or reconstructed after December 13, 2024. The rule established NOx emissions standards for several subcategories of new, modified, and reconstructed stationary combustion turbines and stationary gas turbines based on the size, rate of utilization, design efficiency, and fuel type of these turbines equivalent to the application of selective catalytic reduction (SCR) for large, high-utilization natural gas-fired turbines, and establishes various levels of combustion controls as the “Best System of Emissions Reduction” for smaller and lower-utilization turbines. Idaho Power is analyzing the rule and how it may impact Idaho Power's proposed addition of natural gas-fueled generating capacity next to its Bennett Mountain power plant and any future gas-fired projects.

Clean Water Act Matters

CWA Permitting: Idaho Power's hydropower generation facilities are subject to compliance and permitting obligations under the CWA. Idaho Power has been engaged for several years with the EPA, and is now engaged with the Idaho Department of Environmental Quality (IDEQ), regarding Idaho Power's CWA permitting obligations and compliance status for those facilities. Idaho Power has in the past, and expects in the future, to incur costs associated with those permitting and compliance obligations, but as of the date of this report, Idaho Power is unable to estimate with any reasonable certainty those costs. Idaho Power also expects to incur additional costs associated with the relicensing of its hydropower facilities, as discussed elsewhere in this report. In January 2026, the EPA proposed a rule that could simplify certain requirements under Section 401 of the CWA for water quality certifications. If finalized, the proposed rule may streamline the process for Idaho Power to receive future Section 401 certifications.

In June 2022, Idaho Power and the IDEQ entered into a consent judgment in the Idaho state district courts to resolve a National Pollutant Discharge Elimination System permitting issue related to 15 of Idaho Power’s hydropower projects that required Idaho Power to pay a $1.1 million fine, implement interim measures for compliance, and ultimately submit applications for new permits at each of the dams subject to the consent judgment. Due to a misinterpretation of law, the EPA cancelled water discharge permits in the mid-1990’s, which Idaho Power subsequently determined were applicable for operation of the dams. Idaho Power believes the dams would have been in compliance had the earlier permits remained in place. As of the date of this report, Idaho Power has submitted new permit applications for all 15 dams.

Resource Conservation and Recovery Act Matters

Under the Resource Conservation and Recovery Act, EPA finalized changes to the coal combustion residual (CCR) regulations for inactive surface impoundments at inactive electric utilities. EPA is establishing groundwater monitoring, corrective action, closure and post closure care requirements for these areas and in July 2025, extended certain deadlines for these areas. In addition, in August 2025, the EPA announced a proposal to approve Wyoming's CCR permit program, which would operate in lieu of the federal CCR program. If finalized, the proposed approval will streamline the permitting and monitoring requirements for the Jim Bridger plant landfill and flue gas desulfurization ponds. Idaho Power continues to work with the co-owners of the Jim Bridger plant and the North Valmy plant to evaluate the potential impacts of these regulations, which could affect the amount of asset retirement obligations recorded in Idaho Power's consolidated balance sheets.

Invasive Species Management

Quagga mussels are an invasive species that were first detected in the Snake River system in 2023 in the mid-Snake River near Twin Falls, Idaho, in Idaho Power's service area. Quagga mussel infestations can clog and damage irrigation, hydropower, and water delivery facilities and increase the costs to maintain such facilities. The Idaho State Department of Agriculture (ISDA) treated the affected area in 2023 and 2024 with a copper-based, EPA-approved treatment. ISDA sampling in 2025 detected the continued presence of quagga mussels. As a result, the ISDA performed additional treatments in September and October 2025 in an effort to eradicate quagga mussels in the affected area. As of the date of this report, Idaho Power cannot predict the extent to which the additional treatments will be successful in eradicating quagga mussels from the Snake River or the potential increase in other O&M expenses related to quagga mussel mitigation efforts. If a quagga mussel infestation occurs, it may result in increased other O&M costs for mitigation efforts and other adverse impacts for Idaho Power's operation of its hydropower facilities in any infested areas.

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OTHER MATTERS

One Big Beautiful Bill Act

On July 4, 2025, the One Big Beautiful Bill Act (OBBB) was signed into law. Among its key provisions, the OBBB updates renewable energy tax incentives originally established under the Inflation Reduction Act of 2022, including the Clean Electricity Production Tax Credit and the Investment Tax Credit. Under the new law, solar and wind facilities that begin construction by July 4, 2026, will remain eligible for the credits, consistent with existing guidance on construction start dates. Projects that commence construction after this deadline must be placed in service by the end of 2027 to qualify. For certain other eligible technologies, a gradual phase-out of the credits will begin in 2034, with no credits available for projects that begin construction after 2035. The OBBB also introduces new restrictions for facilities that receive material support from a prohibited foreign entity as well as other corporate-related income tax law changes. IDACORP and Idaho Power do not anticipate material impacts from the OBBB to projects for which Idaho Power has already executed agreements to own generation resources.

Executive Orders of the Current Presidential Administration

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

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

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

Idaho's Wildfire Standard of Care Act

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

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

When preparing financial statements in accordance with GAAP, IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosures. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.

Accounting for Rate Regulation

Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items must be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service area must lack competitive pressures to reduce rates below the rates set by the regulator.

Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded approximately $1.6 billion of regulatory assets and $1.1 billion of regulatory liabilities at December 31, 2025. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.

Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for additional information relating to regulatory matters.

Income Taxes

IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. Refer to Note 1 - “Summary of Significant Accounting Policies” and Note 2 - “Income Taxes” to the consolidated financial statements included in this report for additional information relating to income taxes.

Pension and Other Postretirement Benefits

Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, and two unfunded nonqualified deferred compensation plans for certain senior management employees and directors called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II, and a postretirement benefit plan (consisting of health care and death benefits).

The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future capital markets performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates.

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2025, with maturities matching the projected cash outflows of

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the plans. Based on the results of this analysis, the discount rate used to calculate the 2026 defined benefit plan pension expense increased to 5.75 percent from the 5.70 percent rate used in 2025.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. The long-term rate of return used to calculate the 2026 pension expense will be 7.4 percent, the same assumption as used in 2025.

Total net periodic pension and other postretirement benefit cost for these plans totaled $28.2 million and $31.0 million for the years ended December 31, 2025 and 2024, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2026, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $26.5 million, which takes into account the change in the discount rate noted above.

Had different actuarial assumptions been used, net periodic pension costs and other postretirement benefit costs could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future net periodic pension costs and other postretirement benefit costs:

Discount rate

Rate of return

2026

2025

2026

2025

(millions of dollars)

Effect of 0.5% rate increase on total net periodic pension costs and other postretirement benefit costs

$

(2.9)

$

(2.7)

$

(5.1)

$

(4.9)

Effect of 0.5% rate decrease on total net periodic pension costs and other postretirement benefit costs

3.2 

3.4 

5.2 

4.7 

Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $73.4 million decrease in the combined benefit obligations of the plans as of December 31, 2025. A 0.5 percent decrease in the plans' discount rates would have resulted in an $82.1 million increase in the combined benefit obligations of the plans as of December 31, 2025.

The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2025, a total of $247 million of expense was deferred as a regulatory asset. Idaho Power expects net amortization of the regulatory asset of approximately $19 million in 2026. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $36 million in 2025 and $36 million in 2024.

Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

For discussion of new and recently adopted accounting pronouncements, see Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report.