What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-19 compared with 2025-02-20 · 447 added, 391 removed, 663 unchanged (56% of the section changed)

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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.

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 the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power.

Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part I - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report.

While reading this MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power.

IDACORP is a holding company whose principal operating subsidiary is Idaho Power.

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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.

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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 2024 and during 2025, through the date of this report, include the following:

• IDACORP achieved net income growth for a seventeenth consecutive year in 2024.

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 2024 and January 2025, the IPUC issued an order and an errata to the order, respectively, in Idaho Power's limited issue rate case filing, with new rates effective January 1, 2025, designed to increase annual Idaho-jurisdiction retail revenue by $50.1 million.

In addition, in September 2024, the OPUC approved three partial settlement stipulations related to Idaho Power's Oregon general rate case filing that it made in December 2023, with rates effective October 15, 2024, designed to increase annual Oregon-jurisdiction retail revenue by $6.7 million.

The Idaho limited issue rate case and Oregon general rate case filings are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and in "Regulatory Matters" in this MD&A.

• Idaho Power's customer count grew 2.6 percent in 2024 and Idaho Power's MWh sales to retail customers in 2024 were the highest in its history, surpassing the previous record set in 2022, reflecting considerable growth in its service area.

• Idaho Power reached new winter and summer peaks during 2024.

Idaho Power's new winter peak demand of 2,719 MW and summer peak demand of 3,793 MW were reached on January 16, 2024 and July 22, 2024, respectively.

The prior highest demand peaks were 2,604 MW and 3,751 MW, reached in December 2022 and June 2021, respectively.

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 third-party ratings for residential and business customer satisfaction remain strong – it was the third-ranked utility among peers in the segment for overall customer satisfaction, the highest in the segment for business customer satisfaction, and the third highest in the segment for residential customer satisfaction in 2024.

• In September 2024, IDACORP's board of directors approved an increase in the regular quarterly cash dividend on IDACORP’s common stock from $0.83 per share to $0.86 per share, as a part of a 187 percent increase in quarterly dividends approved over the last thirteen years.

• In connection with its resource planning process, Idaho Power has updated the estimate of load growth that it intends to use for its 2025 IRP.

While subject to adjustment, Idaho Power currently plans to use an 8.3 percent annual rate of growth in retail sales volumes over the 2025-2029 time period, representative of anticipated continued strong growth in Idaho Power's service area.

• 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:

◦ 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;

◦ 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;

◦ 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 increase is driven by Idaho Power's need to acquire additional power supply and transmission resources to meet growing demand.

Idaho Power has procured resources under several RFPs, and has RFPs for 2028 and 2029 resources outstanding.

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, 2024, 2023, and 2022 (in thousands, except earnings per share amounts):

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,

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$ 323,472 $ 289,174 $ 261,195

Average outstanding shares – diluted (000’s) 52,615 50,806 50,699

Weighted average outstanding shares – diluted 54,806 52,615 50,806

IDACORP, Inc.

earnings per diluted share $ 5.90 $ 5.50 $ 5.14

The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2024, from the year ended December 31, 2023 (items are in millions and are before tax unless otherwise noted):

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.

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Increase (decrease) in Idaho Power net income:

Retail revenues per MWh, net of power cost adjustment and FCA mechanisms 52.7

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 mechanisms 4.5

Transmission wheeling-related revenues, net of PCA mechanism impacts (3.0)

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 expense (28.1)

Depreciation and amortization expense (27.7)

Other changes in operating revenues and expenses, net (3.8)

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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 and FCA mechanisms, increased operating income by $52.7 million in 2024 compared with 2023.

This benefit was primarily due to an overall increase in Idaho base rates, effective January 1, 2024, per the terms of the 2023 Settlement Stipulation.

For more information on the 2023 Settlement Stipulation, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

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 increased operating income by $4.5 million in 2024 compared with 2023.

Overall, usage per

customer was relatively flat for most customer classes, with irrigation customers representing an increase, as higher temperatures during the summer led irrigation customers to run irrigation pumps more frequently.

Transmission wheeling-related revenues, net of PCA impacts, decreased $3.0 million during 2024 compared with 2023.

Effective January 1, 2024, financial settlement of transmission line losses were subject to the PCA mechanism, as approved in the 2023 Settlement Stipulation, resulting in a smaller contribution of those revenues to net income compared with 2023 when the financial settlement of transmission losses was not subject to the PCA mechanism.

Other O&M expenses in 2024 were $61.1 million higher than in 2023, primarily related to approximately $17.7 million of increased pension-related expenses and an approximate $29.5 million increase in wildfire mitigation program and related insurance expenses.

Both of these increases were partially offset by increases in retail revenues, as more of those costs are now recovered in base rates pursuant to the 2023 Settlement Stipulation.

Inflationary pressures on labor-related costs also contributed to the increase in other O&M expenses.

These increases were partially offset by an $8.5 million increase in deferral of other O&M expenses related to the conversion from coal to natural gas for two units at the Jim Bridger plant.

Depreciation expense increased $28.1 million in 2024 compared to 2023, due primarily to an increase in plant-in-service.

Other changes in operating revenues and expenses, net, increased operating income by $30.8 million in 2024 compared to 2023, due partially to a decrease in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms.

More moderate wholesale natural gas and power market prices in the western United States and increased wholesale energy sales decreased Idaho Power's net power supply expenses in 2024 compared with 2023.

In addition, property taxes contributed to the increase from 2023 to 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.

The change was also partially due to the timing of recording and adjusting regulatory accruals and deferrals.

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.

Interest expense on long-term debt increased in 2024 compared with 2023, due primarily to an increase in long-term debt balances.

In addition, Idaho Power's earnings from its investment in BCC decreased due to a decrease in the amount included and recovered in base rates pursuant to the 2023 Settlement Stipulation.

These increases were partially offset by an increase in AFUDC income in 2024 compared with 2023, as the average construction work in progress balance was higher.

Additionally, interest income increased due to higher average cash balances and interest rates compared with 2023.

Idaho Power recorded $29.8 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during 2024, but recorded no additional ADITC amortization during 2023.

The $18.6 million increase in income tax expense, excluding additional ADITC amortization, in 2024 compared with 2023 was primarily due to higher income before income taxes and variances in flow-through tax adjustments.

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.

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

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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, including those that are intended to help meet projected near-term capacity deficits, Idaho Power filed a limited-issue rate case in Idaho on May 31, 2024.

The IPUC approved, with modifications, the limited-issue rate case in December 2024, with rates effective January 1, 2025, designed to increase annual Idaho-jurisdiction retail revenue by $50.1 million.

In September 2024 the OPUC approved the 2024 Oregon Settlement Stipulations related to Idaho Power's Oregon general rate case filing, designed to increase annual Oregon-jurisdiction retail revenue by $6.7 million.

The IPUC order related to the limited-issue rate case and the 2024 Oregon

Settlement Stipulations are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Given the limited-scope nature of the filing Idaho Power made in 2024 and its ongoing infrastructure investment, Idaho Power believes it is likely that it will file a general rate case in Idaho during 2025, as early as May 2025.

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:

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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.

Idaho Power is preparing its 2025 IRP, its 20-year forecast of load and power supply resource options.

Included in the below table are the load forecast assumptions the company anticipates using in the 2025 IRP as of the date of this report, and for comparison purposes, the analogous average annual growth rates Idaho Power used in the prior two IRPs.

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

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(Peak Demand)

2025 IRP (preliminary) 8.3% 5.1% 2.7% 1.9%

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's prior all-time summer peak demand was 3,751 MW, set in June 2021.

Idaho Power believes that existing and sustained growth in customers, load, and peak demand for electricity, along with changes in the regional transmission markets that have constrained the availability of transmission outside Idaho Power’s service area to import energy during peak load periods, require Idaho Power to increase its investment in capacity resources, transmission, and distribution infrastructure.

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:

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When favorable hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales.

Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms, which lessen the potential earnings benefit or detriment of volatile hydrological conditions and their impact on overall power supply costs.

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.

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The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse earnings impacts to Idaho Power of fluctuations in power supply costs.

However, collection from customers or return to customers of most of the difference between actual power supply costs compared with those included in retail rates is deferred to a subsequent period, which can affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from or returned to customers.

• Regulatory and Environmental Compliance Costs;

Coal Plant Retirements:

Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council.

Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs.

Moreover, environmental laws and regulations may increase the cost of constructing new facilities, may increase the cost of operating generation plants, may require that Idaho Power install additional pollution control devices at existing generating plants, may result in penalties for non-compliance, even where inadvertent, or may require that Idaho Power curtail or cease operating certain generation plants.

Idaho Power expects to spend significant amounts on environmental compliance and controls for the foreseeable future.

Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its North Valmy plant, ceasing participation in coal-fired operations at one unit in 2019 and planning to cease its participation in coal-fired operations at the remaining unit by year-end 2025.

Idaho Power's jointly-owned coal plant in Boardman, Oregon, ceased operations as planned in October 2020.

In 2022, the IPUC approved Idaho Power's request to allow the coal-related assets at the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030.

Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that included the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030.

Units 1 and 2 at the Jim Bridger plant were successfully converted to natural gas in the second quarter of 2024.

In July 2024, Idaho Power executed an agreement with its co-owner to facilitate the planned conversion of the two units at the North Valmy plant from coal to natural gas by mid-2026.

• Water Management and Relicensing of Hydropower Projects:

Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its

water rights, seeking to preserve the long-term availability of its rights for its hydropower projects.

Also, Idaho Power is involved in renewing its long-term federal licenses for the HCC, its largest hydropower generation source, and for American Falls, its second largest hydropower generation source.

Given the number of parties involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial.

As of the date of this report, Idaho Power cannot determine the ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls hydroelectric facilities.

However, collection from customers or return to customers of most of the difference between actual power supply costs compared with those included in retail rates

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

• Wildfire Mitigation Efforts:

In recent years, the western United States has experienced an increasing number of wildfires of unprecedented severity.

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.

Idaho Power has adopted a WMP that outlines actions Idaho Power is taking or is working to implement in the future to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires.

Idaho Power's approach to achieve these objectives includes identifying areas subject to elevated risk;

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;

PSPS protocols;

and evaluating the performance and effectiveness of the strategies identified in the WMP through metrics and monitoring.

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 earnings.

In this analysis, the results for 2024 are compared with 2023.

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.

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Hydropower generation 7,021 7,203

Steam generation (1)

Jointly-owned thermal generation (1)

Natural gas-fired and other generation 3,685 3,843

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Total energy supply 19,074 18,789

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

(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.

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

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For more information on the changes in sales volume, see the "Operating Revenues" section below in this MD&A.

Total system generation increased 13 percent in 2024 compared with 2023, due primarily to higher natural gas generation and hydropower generation.

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.

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Retail Revenues :

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

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.

Retail revenues:

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

(2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service.

Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.

(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.

MWh Sales Retail Customers

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The primary factors affecting retail revenues during the period were the following:

Customer rates, excluding revenues related to power cost adjustment mechanisms and net of FCA mechanism revenues, increased retail revenues by $52.7 million in 2024 compared with 2023, due primarily to the January 1, 2024, rate increase for Idaho Power’s Idaho retail customers under the 2023 Settlement Stipulation.

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.

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

Increased usage (on a per customer basis) in most customer classes increased retail revenues by $11.2 million during 2024 compared with 2023.

Warmer and drier summer weather during 2024 led to an increase in energy usage per residential customer for cooling purposes and an increase in energy usage per irrigation customer, which was partially offset by a decrease in usage per residential customer due to milder temperatures during January to May and September to December 2024, compared with temperatures during 2023.

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, except for revenue per MWh amounts).

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).

Wholesale energy revenues $ 55,989 $ 73,908

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Wholesale energy revenues per MWh $ 40.54 $ 52.34

In 2024, wholesale energy revenue increased by $10.5 million, or 17 percent, compared with 2023, as higher wholesale energy sales volumes were partially offset by lower wholesale market prices.

Wholesale energy prices were lower during 2024 compared with 2023 as more moderate winter and spring weather resulted in lower natural gas fuel costs in the wholesale markets in the region.

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

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

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:

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Purchased Power :

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

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).

Purchased power expense $ 392,462 $ 425,082

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Purchased power expense decreased $32.6 million, or 8 percent, in 2025 compared with 2024.

The decrease in purchased power expense in 2024 is primarily due to lower wholesale energy market prices as milder winter and spring weather resulted in lower demand and lower fuel costs (natural gas and coal) in the wholesale markets in the region.

Increased system generation led to a decrease in total MWh purchased of 7 percent compared with 2023.

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, except for per MWh amounts).

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

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Total/Weighted average, all $ 253,236 $ 259,204 6,591 6,317 $ 38.42 $ 41.03

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

(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 coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned investment of IERCo.

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.

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Fuel expense decreased $6.0 million, or 2 percent, in 2025 compared with 2024.

In 2024, steam and natural gas generation increased to serve load and provide power for wholesale energy sales compared with 2023.

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.

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To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs.

In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers.

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.

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).

Idaho power supply cost deferral $ (5,606) $ (66,728)

Oregon power supply cost accrual 1,954 1,169

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).

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

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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 both 2024 and 2023, 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.

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 $61.1 million in 2024 compared with 2023, primarily related to approximately $17.7 million of increased pension-related expenses and an approximate $29.5 million increase in wildfire mitigation program and related insurance expenses.

Both of these increases were partially offset by increases in retail revenues, as more costs are now recovered in base rates pursuant to the 2023 Settlement Stipulation.

Inflationary pressures on labor-related costs also contributed to the increase in other O&M expenses.

These increases were partially offset by an $8.5 million increase in deferral of other O&M expenses related to the conversion from coal to natural gas for two units at the Jim Bridger plant.

IDACORP's and Idaho Power's 2024 income tax expense decreased $12.2 million and $11.2 million, respectively, when compared with 2023.

The decreases were primarily due to increased ADITC amortization described in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report, offset partially by an increase in income taxes due to higher income before income taxes.

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.

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.

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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 $981 million in 2024 and $591 million in 2023.

Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $6.1 billion over the period from 2025 through 2029.

Cash capital expenditures, excluding AFUDC and net costs of removing assets from service, were $1.1 billion in 2025 and $981 million in 2024.

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 14, 2025, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

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;

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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 May 16, 2022, which may be used for the issuance of debt securities and common stock, including a remaining aggregate gross sales price of up to $208 million in shares of IDACORP common stock available for issuance through its at-the-market (ATM) offering program;

• 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;

• Idaho Power's shelf registration statement filed with the SEC on May 16, 2022, which may be used for the issuance of first mortgage bonds and debt securities;

• 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;

• 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.

In January 2024, IDACORP began using original issuances of shares for the IDACORP, Inc.

Dividend Reinvestment and Stock Purchase Plan and also intends to use original issuances for share purchases within the Idaho Power Company Employee Savings Plan beginning in the first half of 2025.

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 November and December 2024, IDACORP executed FSAs under its ATM offering program with various counterparties, at an aggregate gross sales price of $92 million.

IDACORP may settle the FSAs at any time up to the maturity date of approximately one year following execution.

Depending on settlement timing, if IDACORP elects to physically settle by delivering shares of common stock, cash proceeds are expected to be approximately $92 million.

As described in the "Financing Cash Flows" section below, during 2024, IDACORP physically settled FSAs with shares of common stock in exchange for cash proceeds and contributed a portion of the net proceeds to Idaho Power.

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 2024, Idaho Power issued first mortgage bonds and repaid pollution control revenue bonds.

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.

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Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions.

As of December 31, 2024, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:

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:

IDACORP Idaho Power

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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 2024 were $594 million and $561 million, respectively, an increase in cash flows from operations of $327 million for IDACORP and $354 million for Idaho Power, when compared with the same period in 2023.

With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from operating cash flows from Idaho Power.

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, increased IDACORP and Idaho Power operating cash inflows by $120 million;

• changes in deferred taxes and taxes accrued and receivable combined to decrease operating cash flows for IDACORP and Idaho Power by $34 million and $41 million, respectively;

• changes in pension and postretirement benefits plan contributions and expenses combined to increase IDACORP and Idaho Power cash flows by $49 million, which was primarily due to the timing and amount of funding decisions and an increase in the amount of pension-related expenses approved for recovery in base rates pursuant to the 2023 Settlement Stipulation;

• 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;

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

◦ the timing of collections of accounts receivable and unbilled revenues increased operating cash flows by $49 million for IDACORP and $51 million for Idaho Power;

◦ the changes in materials, supplies, and fuel stock decreased operating cash flows by $31 million for IDACORP and Idaho Power, which was primarily due to an increase in material and supply inventory offset by the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants;

◦ the changes in accounts and wages payable increased operating cash flows by $98 million for IDACORP and $137 million for Idaho Power, which was primarily due to a decrease in power supply costs and associated timing of payments, and includes a $40 million difference between IDACORP and Idaho Power related to intercompany estimated tax payments;

◦ the changes in other assets and liabilities increased operating cash flows by $21 million for IDACORP and Idaho Power, which was primarily related to a PPA security deposit and performance assurance collateral activity for margin agreements relating to wholesale commodity contracts.

◦ 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;

◦ 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 2024 were $918 million and $915 million, respectively, decreasing cash $328 million for IDACORP and $333 million for Idaho Power, when compared with the same period in 2023.

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:

• $1.0 billion and $611 million, respectively, of additions to property, plant, and equipment;

• $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;

• $11 million in purchases of equity securities and $2 million in purchases of held-to-maturity securities in 2024 and 2023, and $11 million and $9 million in sales of equity securities in 2024 and 2023, respectively, held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's SMSP.

• 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 2024 were $365 million and $271 million, respectively, a decrease of $108 million for IDACORP and $267 million for Idaho Power, when compared with the same period in 2023.

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.

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

• in 2024, Idaho Power repaid $50 million in principal amount of pollution control revenue bonds;

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

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

• in 2023, Idaho Power repaid the entire $150 million in principal amount of a March 2022 term loan agreement, and $75 million in principal amount of first mortgage bonds;

• IDACORP and Idaho Power paid respective dividends of $177 million and $176 million in 2024, and $164 million and $102 million in 2023.

• 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;

• 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:

IDACORP fully settled its 2023 FSAs with 3.2 million shares of its common stock in exchange for cash of $292 million in 2024.

In November and December 2024, IDACORP executed FSAs under its ATM offering program with various counterparties, at an aggregate gross sales price of $92 million.

IDACORP has a remaining aggregate gross sales price of up to $208 million in shares of its common stock available for issuance through the ATM offering program.

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 of approximately one year following execution.

See Note 6 - "Common Stock" to the consolidated financial statements included in this report.

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.

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The IDACORP and Idaho Power Credit Facilities have similar terms and conditi ons.

The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or Adjusted Term Secured Overnight Financing Rate (SOFR) plus 1.0 percent, or 1.0 percent, or (2) the Adjusted Term SOFR, plus, in each case an applicable margin, provided that the Adjusted Term SOFR will not be less than 0.0 percent.

If during any period the SOFR rate is unavailable or unascertainable, an alternate benchmark rate selected by the administrative agent and the borrower would apply.

The 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.

While the credit facilities provide for an original maturity date of December 8, 2028, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions.

On December 9, 2024, IDACORP and Idaho Power executed extension agreements, extending the maturity date under both credit agreements to December 7, 2029.

No other terms of the credit facilities, including the amount of permitted borrowing under the credit agreements, were affected by the extensions.

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.

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“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, 2024, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively.

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.

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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.

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

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:

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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.

Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity

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

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

December 31, 2025 December 31, 2024

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Net balance available $ 100,000 $ 400,000 $ 100,000 $ 380,115

(1) American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.

(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, except percentages).

The table below presents additional information about short-term commercial paper borrowing during the year ended December 31 (in thousands of dollars, except percentages).

Idaho Power IDACORP (1)

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Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings.

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:

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Capital Requirements

Idaho Power's cash capital expenditures, excluding AFUDC, were $981 million during the year ended December 31, 2024.

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.

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The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings.

Given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table.

The timing and amount of actual constructed projects and capital expenditures could be affected by Idaho Power’s ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, regulatory determinations, inflationary pressures, macroeconomic conditions, or other issues, including those described below.

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

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Other Major Infrastructure Projects:

Idaho Power has recently completed or is engaged in the development of a number of significant projects and has entered into arrangements with third parties for joint development of infrastructure projects.

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 acquire significant generation, transmission, and storage resources to meet energy and capacity needs over the next several years.

To help meet peak needs in 2025 through 2027, Idaho Power entered into:

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

• a contract to purchase and own a 300 MW wind facility;

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

• 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;

• a PPA for 300 MW output of a planned third-party wind facility;

• four PPAs for the combined 745 MW output of planned third-party solar facilities.

Idaho Power plans to sell the output of three of these solar PPAs totaling 645 MW exclusively to a large industrial customer pursuant to an agreement under Idaho Power’s Clean Energy Your Way program.

The capital requirements table above includes capital expenditures of approximately $1.1 billion from 2025 through 2027 for resource additions to address projected energy and capacity deficits in those years.

To help address the additional capacity deficits projected for 2027 and beyond, Idaho Power continues to evaluate its RFP for additional resources.

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, actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures.

Idaho Power's existing and sustained growth in customers, load, and peak demand for electricity, along with transmission constraints, has created the need for Idaho Power to

acquire significant generation, transmission, and storage resources to meet energy and capacity needs 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;

• 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 planned 300-mile high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, is expected to provide transmission service to meet future resource needs.

Material procurement is in process and long-lead-time materials are arriving in Oregon.

Idaho Power expects construction will begin in the summer of 2025 and expects the in-service date for the transmission line will be no earlier than 2027.

Under the permitting phase of the project, Idaho Power had a joint funding agreement with PacifiCorp and BPA, with Idaho Power having an approximate 21 percent interest, BPA having an approximate 24 percent interest, and PacifiCorp having an approximate 55 percent interest in the permitting phase of the project.

In March 2023, BPA, PacifiCorp, and Idaho Power signed various agreements to facilitate certain asset transfers and other coordination efforts among the parties as the transmission line moves toward construction.

In particular, an agreement between Idaho Power and BPA transferred BPA’s total interest in the project to Idaho Power, increasing Idaho Power's interest to approximately 45 percent, and provided that Idaho Power will deliver long-term transmission service to BPA's customers across southern Idaho.

The agreement also required BPA to make a $10 million security payment to Idaho Power.

On Idaho Power's consolidated balance sheet, the agreement increased construction work in progress by $31 million for the acquired permitting interest, cash and cash equivalents by $10 million for the additional security payment, and other non-current liabilities by $41 million for Idaho Power's obligation to pay for the permitting interest and to return the security deposit to BPA.

Payments to BPA for the permitting interest are expected to be made over a 15-year period beginning 10 years after energization of the transmission line project, while the security deposit is due to be returned to BPA upon energization.

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 the joint funding arrangements, Idaho Power has received $208 million in reimbursement as of December 31, 2024, from project co-participants for their share of costs (including $31 million related to BPA's share, which was transferred to Idaho Power in March 2023 as part of the agreement described above) and continues to receive reimbursement as costs are incurred.

PacifiCorp is obligated to reimburse Idaho Power for its share of any future project permitting expenditures or agreed upon early construction expenditures incurred by Idaho Power under the terms of the joint funding agreement.

In June 2023, Idaho Power and PacifiCorp executed a construction funding agreement and filed it with the FERC.

The agreement became fully effective in September 2023.

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, the state's Energy Facility Siting Council (EFSC) approved Idaho Power's site certificate in September 2022.

The Oregon Department of Energy subsequently issued a final order and site certificate.

Idaho Power is pursuing two amendments to the site certificate to accommodate route changes, many of which are for the benefit of landowners along the route, and to enhance constructability.

In September 2023, EFSC approved Idaho Power's first amendment request.

One party contested the EFSC's approval of the first amendment in Union County Circuit Court.

On October 28, 2024, the Union County Circuit Court issued an order to dismiss the proceeding.

Separately, in August 2024, EFSC approved Idaho Power's second amendment request.

The approval of the second amendment is being contested, and a decision of the Oregon Supreme Court in the case is pending.

During the second quarter of 2023, the IPUC, OPUC, and WPSC granted Idaho Power and PacifiCorp their respective CPCNs related to the construction of the B2H project.

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 $500 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining permitting phase, design, material procurement, and construction phases of the project.

Actual construction costs could differ from Idaho Power's estimates based upon Idaho Power’s or its contractors ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, macroeconomic conditions, or other issues.

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 :

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In 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project.

Idaho Power has expended approximately $67 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2024.

As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $900 million and $1.1 billion, including Idaho Power's AFUDC.

The estimated cost range is based on assumptions about Idaho Power participation levels in the construction of certain project

segments and any changes in those assumptions or in Idaho Power's actual participation could affect future estimates and actual project costs.

The capital requirements table above includes approximately $615 million of Idaho Power's share of estimated costs (excluding AFUDC) for the permitting phase of the project and early construction costs, based on Idaho Power's current estimate that it may commence construction of applicable segments during that time period.

Actual construction costs could differ from Idaho Power's estimates based upon the ability of Idaho Power, PacificCorp, or their respective contractors to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, macroeconomic conditions, or other issues.

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.

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In 2020 and 2024, PacifiCorp completed construction and commissioned segments of its portion of the project in Wyoming.

In March 2023, PacifiCorp initiated the pre-construction phase of 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho.

Current permitting and pre-construction activities are focused on the section of line between the Hemingway substation and the Midpoint substation, near Jerome, Idaho.

Idaho Power expects the in-service date for this section of line or a portion of this section will be 2028 or later.

Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs, including potentially modifying the ownership structure of a few segments of the project.

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.

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.

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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 as early as 2025 and take approximately two years to complete.

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.

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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 :

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As of December 31, 2025, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $281 million.

As of the date of this report, Idaho Power believes issuance of a new HCC license by the FERC will be as early as 2026.

Idaho Power is unable to predict the exact timing that the FERC will issue a new license or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with a new license.

Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $35 million to $45 million until issuance of t he license.

Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with complian ce with the terms and conditions of the long-term license could also be substantial.

In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding.

In April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date.

As discussed in Note 3 – “Regulatory Matters – Notable Idaho Base Rate Adjustments – Recovery of Incremental AFUDC Associated with HCC" to the consolidated financial statements included in this report, in March 2025, Idaho Power filed an application with the IPUC to increase the annual cash collection of AFUDC associated with relicensing of the HCC project from $8.8 million to $38.5 million.

In September 2025, the IPUC approved Idaho Power's proposed increase in annual cash collection to recover AFUDC associated with relicensing of the HCC project, effective October 1, 2025.

As of the date of this report, Idaho Power anticipates that the FERC could issue a new HCC license in 2027 or thereafter.

However, the exact timing, as well as the total capital investment and ongoing operating and maintenance costs required to comply with the new license remain uncertain.

Idaho Power estimates that annual costs to obtain a new long-term license, including AFUDC but excluding post-issuance compliance cost, will range from $35 million to $45 million until t he license is

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 Project, which consists of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying 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 approximately 300 MW of generation.

The capital requirements table above includes Idaho Power's share of the costs to develop and construct the project but does not include any of the expected costs of the PPA.

As of the date of this report, the Jackalope Project is expected to begin operations in 2027.

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:

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Defined Benefit Pension Plan Contributions and Recovery

Idaho Power contributed $20 million in 2024 and $48 million in 2023 to its defined benefit pension plan.

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 could contribute up to $20 million to the pension plan during 2025.

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.

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Idaho Power only records a carrying charge on the unrecovered balance of cash contributions.

In December 2023, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs in 2024 from $17 million to $35 million annually.

Idaho Power has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011.

The 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.

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Contractual Obligations

IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2024, include long-term debt, interest payments, purchase obligations, pension and post-retirement benefit plans, and other long-term liabilities specific to IDACORP, most of which are discussed throughout this MD&A.

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.

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors.

IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant.

IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of

IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant.

The ability of IDACORP to pay dividends on its common stock is generally dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power.

IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 60 percent and 70 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of directors' dividend decisions.

Notwithstanding the dividend policy adopted by IDACORP's board of directors, the dividends

IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the factors above, among others.

In September 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.

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REGULATORY MATTERS

Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, the OPUC, and the FERC.

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, the OPUC, and the WPSC as to the issuance of debt and equity securities.

As a public utility under the FPA, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT.

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.

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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 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.

Idaho Power filed the 2024 Idaho Limited-Issue Rate Case in May 2024, focused on revenue requirements for 2024 incremental plant additions and incremental ongoing labor costs.

On December 31, 2024, the IPUC issued its order (Order) in the 2024 Idaho Limited-Issued Rate Case, providing that Idaho Power implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $50.6 million, or 3.7 percent, effective January 1, 2025.

The Order was subsequently modified by an errata issued on January 21, 2025, which reduced the revenue increase called for under the Order to $50.1 million.

Given the limited-scope nature of the 2024 Idaho Limited-Issued Rate Case and its ongoing infrastructure investment, Idaho Power believes it is likely that it will file a general rate case in Idaho during 2025, as early as May 2025.

Between general rate cases, Idaho Power relies upon customer growth, an FCA mechanism, 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.

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

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

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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 (millions) (1)

2024 Idaho limited-issue rate case 1/1/2025 $ 50.1

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

2023 Idaho general rate case 1/1/2024 54.7

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.

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Idaho and Oregon Rate Cases

As noted above, on December 31, 2024, the IPUC issued the Order in connection with Idaho Power's 2024 Idaho Limited-Issue Rate Case.

The Order provided for Idaho Power to implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $50.6 million, or 3.7 percent, effective January 1, 2025.

The Order was subsequently modified by an errata issued on January 21, 2025, which reduced the revenue increase called for under the Order to $50.1 million.

The 2023 Settlement Stipulation 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.

The 2023 Settlement Stipulation also provided for a 9.6 percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $3.8 billion.

For more information on the 2023 Idaho general rate case and related 2023 Settlement Stipulation, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

At December 31, 2024, Idaho Power estimates that it had $77 million of deferred credits available for future use under the ADITC and Revenue Sharing mechanism.

Under the modified ADITC and Revenue Sharing mechanism, Idaho Power may seek approval from the IPUC to replenish the total amount of additional ADITC it is permitted to amortize, and if there are no remaining amounts of additional ADITC authorized to be amortized, the remainder of the revenue sharing provisions would not be applicable until additional ADITC is replenished.

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 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.

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, which are settlement stipulations among Idaho Power and intervening parties settling the general rate case.

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.

The stipulations were premised on a 9.5 percent Oregon-jurisdiction return on year-end equity, and a 7.302 percent Oregon-jurisdiction authorized rate of return based on a 5.104 percent cost of debt and capital structure of 50 percent debt and 50 percent equity, applied to an Oregon-jurisdictional rate base of approximately $188.9 million.

For more information on the Oregon general rate case and the 2024 Oregon Settlement Stipulations, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

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 September 2023 and expects to file its next IRP during 2025, as described in Part 1, Item 1 - "Business - Resource

Planning" in this report.

The 2023 IRP, which was acknowledged by the IPUC in June 2024 and by the OPUC in August 2024, identified the need for resources to meet projected capacity deficits in the near-term.

In March and April 2024, Idaho Power filed applications with the IPUC for two of the bids from its 2023 RFP to procure resources for its anticipated energy and capacity needs in 2026 and 2027.

In the March 2024 application, Idaho Power requested that the IPUC approve a market purchase agreement with an energy marketer to purchase 200 MW of firm capacity for specified periods of time.

The IPUC approved this application in August 2024.

In the April 2024 application, Idaho Power applied for a CPCN to acquire and own 150 MW of battery storage with an expected useful life of 20 years.

The IPUC approved this application in November 2024.

In August 2024, following review by an independent evaluator appointed by the OPUC, OPUC staff, and other intervenors, the OPUC issued an order approving Idaho Power's final RFP to procure resources for its anticipated energy and capacity needs in 2028 and beyond.

Idaho Power issued the RFP in August 2024 soliciting resources with a commercial operation date (COD) no later than April 1, 2028 (2028 bids), as well as bids with a COD after April 1, 2028 (beyond 2028 bids), and filed a request with the OPUC on January 10, 2025, for acknowledgment of its final shortlist of 2028 bids in the RFP.

As of the date of this report, the OPUC's acknowledgment of the final shortlist of 2028 bids is pending.

Idaho Power has received and is currently evaluating beyond 2028 bids.

In December 2024, Idaho Power filed an application with the IPUC for the Jackalope Project, one of the bids from an RFP to procure resources for its anticipated energy and capacity needs in 2027.

The Jackalope Project consists of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying approximately 300 MW of generation to Idaho Power's system, and (ii) a wind turbine generator power plant to be owned by Idaho Power, providing approximately 300 MW of generation.

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.

As of the date of this report, the IPUC's decision is pending.

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.

As of the date of this report, the IPUC's decision is pending.

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

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.

As of the date of this report, the IPUC's decision is pending.

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

Brisbie, LLC (Brisbie) Data Center and Clean Energy Your Way - Construction Arrangements :

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 April 2023, Idaho Power received IPUC approval of a contract with a 200 MW solar project that is scheduled to begin operating as early as March 2025.

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 May 2024, Idaho Power received IPUC approval of a contract with a 125 MW solar project to be online as early as December 2026 for energy to be purchased by Brisbie.

In November 2024, Idaho Power filed for IPUC approval of an additional contract for Brisbie with a 320 MW solar project to be online as early as December 2027.

As of the date of this report, the IPUC's decision regarding the additional contract is pending.

In May 2024, Idaho Power also filed an application with the IPUC for approval of the second amendment to the Brisbie Special Contract providing for changes in certain pricing elements under the Brisbie Special Contract.

The IPUC approved the application in November 2024.

Micron Clean Energy Your Way - Construction Arrangements and Micron Fab Special Contract :

In August 2022, the IPUC issued an order approving, with modifications, Idaho Power's application for a revised special contract for electric service

between Idaho Power and Micron Technology, Inc.

The application was modeled after the Clean Energy Your Way program and included an arrangement under which Micron would purchase from Idaho Power energy generated by a to-be-constructed 40 MW solar facility pursuant to a 20-year PPA between Idaho Power and a third party.

The solar facility began operating in May 2023.

In May 2024, Idaho Power filed an application for approval of the third amendment to the special contract between Micron and Idaho Power, which provides for changes in certain pricing elements under the special contract.

The IPUC approved the application in November 2024.

Idaho regulations require any utility customer with an average load exceeding 20 MW to enter into a special contract with Idaho Power.

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 IPUC's decision is pending.

In April 2025, the IPUC approved the PPA.

Deferred Net Power Supply Costs

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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, income tax reform, and revenue sharing under Idaho regulatory settlement stipulations.

From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms.

The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" in this MD&A are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.

The following table summarizes the change in deferred (accrued) net power supply costs over last year (in millions):

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

Idaho Oregon Total

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$ 18.5 $ (3.9) $ 14.6

Current period net power supply costs deferred (accrued) 5.6 (1.9) 3.7

Prior amounts collected through rates (93.3) (0.1) (93.4)

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)

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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 Idaho Power files with the FERC.

In August 2024, Idaho Power filed its 2024 final transmission rate with the FERC, reflecting a transmission rate of $31.55 per kilowatt-year (kW-year), to be effective for the period from October 1, 2024, to September 30, 2025.

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.

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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 states' 401 certifications 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.

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The FERC also reinstated informal consultation with the USFWS and the NMFS under section 7 of the ESA.

In May 2024, the FERC issued an updated schedule for the supplemental EIS, indicating that the draft and final supplemental EIS would be issued no later than July 2024 and February 2025, respectively.

As of the date of this report, the FERC has not issued the draft supplemental EIS.

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.

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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.

Idaho Power owns the generation facility but not the structural dam or reservoir, which are owned by the U.S.

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Idaho Power filed the final relicensing application with the FERC in February 2023.

In September 2023, Idaho Power filed an application for CWA Section 401 water quality certification with the IDEQ.

In September 2024, IDEQ issued a final CWA Section 401 water quality certification.

In October 2024, FERC issued a revised notice of intent to prepare an environmental assessment, signaling that FERC staff did not anticipate that licensing the project would constitute a major federal action that would significantly affect the quality of the human environment.

FERC released its environmental assessment on January 16, 2025, which initiated a 30-day comment period.

Idaho Power is reviewing the environmental assessment, including the mitigation measures that FERC recommended in it.

Idaho Power's current license at American Falls expires on February 28, 2025.

As of the date of this report, Idaho Power anticipates the FERC will issue a new license for this facility in late 2025.

If the current license expires before the new license is issued, Idaho Power expects to continue to operate its American Falls facility on annual licenses issued by the FERC with the same conditions as the current license.

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

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In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions.

Idaho Power's co-owned coal-fired power plant, its co-owned coal- and gas-fired power plant, and its three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations.

Idaho Power's 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.

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In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation or conversion to natural gas, as the cost of compliance makes coal plants uneconomical to operate.

The decision to cease operation of the Boardman power plant in 2020 was based in part on the significant cost of compliance with environmental laws and regulations.

The decision to end participation in coal-fired operations of one unit at the North Valmy plant was also based in part on the economics of continuing coal-fired generation at the plant.

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.

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Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level.

Therefore, as of the date of this report, and except as specifically described below in this MD&A, Idaho Power is uncertain whether and to what extent the orders, any future executive orders, and the implementation of these and any future executive orders could affect its business, results of operations, and financial condition.

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";

• 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

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

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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 and B2H transmission projects and other infrastructure projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay construction.

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 North Dakota, and allege that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates.

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 in an effort to support the exemptions provided for in the BLM's plans.

If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction.

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

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 issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands.

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.

As of the date of this report, the BLM has not signed the record of decision for the land use plan amendments in Idaho.

Reinstatement of "Blanket Rule" for Threatened Species:

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 endanger ed species under Section 4(d) of the ESA.

Based on ESA listings as of the date of this report, Idaho Power anticipates that the rule will have limited or no impact on its projects.

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 February 2025 according to the FERC's updated schedule for issuance of the supplemental EIS.

As of the date of this report, the FERC has not issued the supplemental EIS in draft or final form.

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 :

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As of the date of this report, Idaho Power is uncertain whether such increases will be significant.

National Environmental Policy Act Matters

NEPA is a federal law that requires federal agencies to consider the environmental impacts of their actions and decisions.

NEPA applies to Idaho Power’s transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions.

In April 2022, the previous Presidential Administration’s Council on Environmental Quality (CEQ) published a final rule that restored a prior NEPA requirement, eliminated under the preceding Administration, that federal agencies consider all indirect and cumulative environmental impacts of infrastructure projects in their decision-making, among other things, which could delay and increase the cost of Idaho Power’s infrastructure projects.

In May 2024 the CEQ finalized a second phase of NEPA reform to revise regulations for implementing NEPA.

Key changes in the Phase 2 rule relate to the definition of “reasonably foreseeable effects,” how the agency interprets a reasonable range of alternatives, what constitutes a major federal action, and the incorporation of environmental justice into the NEPA analysis.

In November 2024, the U.S.

Court of Appeals for the D.C.

Circuit ruled in the Marin Audubon Society v.

Federal Aviation Administration case that the CEQ has no authority to issue regulations implementing NEPA and, therefore, NEPA regulations issued by CEQ are invalid.

This was followed by Executive Order 14154 that revoked CEQ’s authority to issue NEPA regulations and directed CEQ to rescind all NEPA regulations.

In February 2025, the U.S.

District Court for the District of North Dakota ruled in Iowa v.

CEQ , that CEQ has no rulemaking authority, invalidated CEQ’s 2024 NEPA rule, and restored the 2020 CEQ NEPA rule, as amended by the 2022 NEPA rule.

On February 16, 2025, CEQ issued a notice that it intends to rescind all CEQ NEPA implementing regulations.

These actions have raised significant questions regarding how CEQ’s NEPA regulations and agency-specific NEPA procedures will be interpreted and enforced going forward.

Idaho Power is unable to predict what impact these actions will have on Idaho Power and its operations.

Climate Change and the Regulation of Greenhouse Gas Emissions

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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 Boardman power plant in October 2020 and the North Valmy plant unit 1 in December 2019 .

Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that anticipates (1) converting North Valmy plant units 1 and 2 to natural gas by summer 2026;

(2) converting units 1 and 2 at the Jim Bridger plant from coal to natural gas in 2024;

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

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.

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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.

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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.

As of the date of this report, Idaho Power continues to evaluate the specific impacts the New Section 111 Rule could have on its operations at its three natural gas facilities, as well as the North Valmy and Jim Bridger plants.

Idaho Power anticipates that the GHG emissions reductions may under certain circumstances only be achievable by reducing unit runtimes.

Climate-Related Disclosures:

In March 2024, the SEC issued a final rule on the enhancement and standardization of climate-related disclosures for investors.

In April 2024, the SEC voluntarily stayed the effectiveness of the rule, pending the resolution of litigation challenging the rule in the U.S.

Court of Appeals for the Eighth Circuit.

If the rule becomes effective, it could require IDACORP and Idaho Power to make various additional climate-related disclosures, including regarding its Scope 1 and Scope 2 GHG emissions, if material.

The position that the new Presidential Administration will take toward this rule is not yet known, though it is possible that it could seek to modify, delay, or rescind this rule.

As of the date of this report, IDACORP and Idaho Power are evaluating the potential impacts of the final 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:

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These include the final MATS Rule and the Good Neighbor Plan.

The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health

and the environment.

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.

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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 on August 4, 2023.

The Good Neighbor Plan establishes nitrogen oxides (NO x ) emissions budgets requiring fossil fuel-fired power plants to participate in an allowance-based ozone season trading program.

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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 nitrogen oxide determination for Idaho Power’s jointly-owned Jim Bridger plant.

The proposed SIP replaces Wyoming’s previously approved source-specific NO x determination for Idaho Power’s jointly-owned Jim Bridger plant.

Operations at the Jim Bridger plant have previously been modified to comply in advance with the proposed SIP.

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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.

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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 Good Neighbor Plan is implemented in Nevada, Idaho Power anticipates that, under certain conditions, it could reduce the ability to use the full available output, or require additional controls for NO x and/or the purchase of allowances in order to utilize the full available output, at the North Valmy plant during the EPA defined ozone season (May through September).

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 Mercury and Air Toxic Standards in Section 112 of the CAA for coal-fired power plants (MATS Rule) provide that sources must comply with certain emission limits.

Idaho Power and the co-owners of Jim Bridger and North Valmy coal-fired generating plants 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.

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 the units at the Jim Bridger plant that are still operating on coal, the MATS Rule will require additional monitoring equipment and possibly other equipment upgrades, but as of the date of this report, this remains under evaluation.

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

requirements, and the revised mercury emission standard for lignite-fired electric utility steam generating units.

Idaho Power will continue to monitor developments with respect to the MATS Rule for possible impact to Idaho Power's operations.

CAA Section 111 New Source Performance Standards:

In January 2026, the EPA finalized its “New Source Performance Standards Review for Stationary Combustion Turbines and Stationary Gas Turbines” under CAA Section 111.

This rule applies to affected sources constructed, modified, or reconstructed after December 13, 2024.

The rule established NO x emissions standards for several subcategories of new, modified, and reconstructed stationary combustion turbines and stationary gas turbines based on the size, rate of utilization, design efficiency, and fuel type of these turbines equivalent to the application of selective catalytic reduction (SCR) for large, high-utilization natural gas-fired turbines, and establishes various levels of combustion controls as the “Best System of Emissions Reduction” for smaller and lower-utilization turbines.

Idaho Power is analyzing the rule and how it may impact Idaho Power's proposed addition of natural gas-fueled generating capacity next to its Bennett Mountain power plant and any future gas-fired projects.

Clean Water Act Matters

Section 401 Water Quality Certification:

As described more fully under “Relicensing of Hydropower Projects” in the "Regulatory Matters" section of this MD&A, Idaho Power filed water quality certification applications, required under Section 401 of the CWA, with Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards.

The states issued final certifications in May 2019.

In September 2023, Idaho Power filed an application for CWA Section 401 water quality certification with the IDEQ for the American Falls facility.

In September 2024, IDEQ issued a final CWA Section 401 water quality certification for the American Falls facility.

CWA Permitting:

Idaho Power's hydropower generation facilities are subject to compliance and permitting obligations under the CWA.

Idaho Power has been engaged for several years with the EPA, and is now engaged with the IDEQ, regarding Idaho Power's CWA permitting obligations and compliance status for those facilities.

Idaho Power has 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 that the dams would have been in compliance with the earlier permits had they remained in place.

As of the date of this report, Idaho Power has submitted new permit applications for all 15 of the dams.

Effluent Limitations:

In April 2024, EPA finalized effluent limitation guidelines and standards that set new water treatment standards for coal plants.

Idaho Power's co-owned coal-fired plants, the Jim Bridger plant and the North Valmy plant, are non-discharge facilities and are not impacted by this rule.

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 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.

Idaho Power continues to work with the co-owners of its coal-fired generation plants 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.

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 in Idaho Power's service area.

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 with a copper-based, EPA-approved treatment.

ISDA sampling in September 2024 detected the continued presence of quagga mussels.

As a result, the ISDA performed additional treatments in 2024 to eradicate quagga mussels in the affected area.

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.

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.

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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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Idaho Power must satisfy three conditions to apply regulatory accounting:

independent regulator must set rates;

(1) an independent regulator must set rates;

(2) the regulator must set the rates to cover specific costs of delivering service;

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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, 2024, with maturities matching the projected cash outflows of the plans.

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

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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis