IDACORP INC (IDA) FY 2024 MD&A

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

AND RESULTS OF OPERATIONS

In MD&A in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 2023 compared with 2022 can be found in their Annual Report on Form 10-K for the year ended December 31, 2023. 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.

INTRODUCTION

IDACORP is a holding company whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the IPUC, OPUC, and FERC. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity.

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

EXECUTIVE OVERVIEW

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

•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 2024, Idaho Power’s reliability metrics continued to be among the best in company history, as Idaho Power provided uninterrupted service to its retail customers 99.96 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.

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•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 estimate of capital expenditures from 2025 to 2029 is in the range of $5.4 billion to $6.1 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.

Summary of 2024 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 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):

IDACORP's net income increased $28 million for 2024 compared with 2023, 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.

Idaho Power's customer growth of 2.6 percent added $19.0 million to Idaho Power's operating income in 2024 compared with 2023. Usage per retail customer increased operating income by $4.5 million in 2024 compared with 2023. Overall, usage per

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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.

Non-operating expense, net, increased $2.2 million in 2024 compared with 2023. 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.

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

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

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

To address the regulatory lag in recovery of costs primarily associated with Idaho Power’s current and anticipated significant infrastructure investments, 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

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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.

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

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

•Economic Conditions and Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. In recent years, Idaho Power has seen significant growth in the number of customers in its service area. In 2024, Idaho Power's customer count grew by 2.6 percent. While recessionary or volatile economic conditions could slow the rate of customer growth, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase for the foreseeable future.

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.

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. 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.

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

Further, as Idaho Power's hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydropower generation decreases, Idaho Power must rely on more expensive generation resources and purchased power. When favorable hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms, which lessen the potential earnings benefit or detriment of volatile hydrological conditions and their impact on overall power supply costs. For 2025, Idaho Power expects generation from its hydropower resources to be in the range of 6.5 million to 8.5 million MWh, compared with 7.2 million MWh in 2024 and average total annual hydropower generation of approximately 7.7 million MWh over the last 30 years.

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

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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.

•Wildfire Mitigation Efforts: In recent years, the western United States has experienced an increasing number of wildfires of unprecedented severity. A variety of factors have contributed to this trend including increased wildland-urban interfaces, historical land management practices, climate change, and overall wildland and forest health. Idaho Power is taking a proactive approach to wildfire risk in its service area and transmission corridors. Idaho Power has 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; 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. 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.

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.

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

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

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

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

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

Sales Volume and Generation: In 2024, retail sales volumes increased 3 percent compared with the prior year, primarily due to growth in the number of Idaho Power customers. The number of Idaho Power customers grew by 2.6 percent in 2024. 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. For more information on the changes in sales volume, see the "Operating Expenses" section below in this MD&A.

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

Operating Revenues

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

(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.

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

Retail Revenues: Retail revenues increased $80.1 million in 2024 compared with 2023. The primary factors affecting retail revenues during the period were the following:

•Rates: 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 also include the collection from customers of amounts related to the power cost adjustment mechanisms, which decreased revenues by $14.2 million in 2024 compared with 2023. The adjustments related to the Idaho-jurisdiction PCA in rates do not have a significant effect on operating income as a corresponding amount is recorded in expense in the same period it is collected through rates.

•Customers: Customer growth of 2.6 percent increased retail revenues by $30.5 million in 2024 compared with 2023.

•Usage: 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.

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).

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.

Energy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency riders fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. The cumulative variances between expenditures and amounts collected through the riders are recorded as regulatory assets or liabilities. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2024, Idaho Power's energy efficiency rider balances were a $7.6 million regulatory liability in the Idaho jurisdiction and a $1.7 million regulatory liability in the Oregon jurisdiction.

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Operating Expenses

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

Purchased power expense decreased $76.4 million, or 15 percent, in 2024 compared with 2023. 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. 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).

(1) "Steam" 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 price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies the majority of the coal used by the Jim Bridger plant and BCC does not have significant sales to third parties. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods.

Fuel expense decreased $16.2 million, or 6 percent, in 2024 compared with 2023. In 2024, steam and natural gas generation increased to serve load and provide power for wholesale energy sales compared with 2023. The impact of this generation increase on fuel expense was more than offset during 2024 by lower natural gas market prices compared with 2023.

Included in fuel expense are losses and gains on settled financial gas hedges entered into in accordance with Idaho Power's energy risk management policy. In 2024 and 2023, losses on financial gas hedges of $63.3 million and $16.2 million, respectively, increased natural gas fuel expense. Most of these realized hedging losses and gains are passed on to customers through the power cost adjustment mechanisms described below.

Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases 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

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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).

The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. During 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. 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.

Income Taxes

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. For additional information relating to IDACORP's and Idaho Power's income taxes, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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:

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

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

•IDACORP's shelf registration statement filed with the SEC on 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 executed FSAs under its ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of February 14, 2025, would have been approximately $91 million; and

•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; $900 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 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. 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. For more detailed information about Idaho Power's long-term debt transactions, see Note 5 - "Long-Term Debt" to the consolidated financial statements included in this report.

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

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

IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent equity. Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2024, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:

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

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Operating Cash Flows

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

IDACORP’s and Idaho Power’s operating cash inflows in 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. Significant items that affected the companies' operating cash flows in 2024 when compared with the same period in 2023 were as follows:

•a $28 million and $24 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; and

•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; and

◦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.

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. Investing cash outflows for 2024 and 2023 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 2024 and 2023 included:

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

•$84 million and $27 million, respectively, from B2H project joint permitting participants relating to a portion of the permitting expenditures;

•$4 million and $3 million, respectively, of tax credit investments in affordable housing and other real estate, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits at IDACORP; and

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•$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.

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. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, dividends, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, payment of dividends, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. Significant items and transactions that affected financing cash flows in 2024 and 2023 were as follows:

•in 2024 and 2023, Idaho Power issued $300 million and $872 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; and

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

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. Depending on market conditions, its financial and regulatory strategy, and other factors, IDACORP could determine to issue additional equity securities in 2025.

Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and WPSC. In February and March 2024, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. At December 31, 2024, $900 million remained available for debt issuance under the regulatory orders. For more detailed information about Idaho Power First Mortgage Bonds, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.

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

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The IDACORP and Idaho Power Credit Facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or 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 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.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2024, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively. IDACORP's and Idaho Power's ability to utilize their respective Credit Facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the Credit Facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2024, IDACORP and Idaho Power believe they were in compliance with all of their respective Credit Facility covenants and, as of the date of this report, do not believe they will be in violation or breach of such covenants during 2025.

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

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

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.

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

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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):

At February 14, 2025, 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).

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. 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:

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

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

Capital Requirements

Idaho Power's cash capital expenditures, excluding AFUDC, were $981 million during the year ended December 31, 2024. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2025 through 2029 (in billions of dollars). The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings. Given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table. The timing and amount of actual constructed projects and capital expenditures could be affected by Idaho Power’s ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, regulatory determinations, inflationary pressures, macroeconomic conditions, or other issues, including those described below.

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of relatively small projects as Idaho Power continues to add to its system to accommodate growth and maintain reliability and operational effectiveness. These projects involve significant capital expenditures in the aggregate. Examples of anticipated system enhancements planned for 2025 through 2029 and estimated costs include the following:

•$90-$225 million per year for construction and replacement of transmission lines and stations other than the B2H, GWW, and SWIP-N projects discussed below;

•$215-$260 million per year for construction and replacement of distribution lines and stations;

•$10-$70 million per year for ongoing improvements and replacements at thermal plants;

•$105-$165 million per year for hydropower plant improvement programs, including relicensing costs; and

•$75-$105 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.

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. 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; and

•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,

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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.

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.

Idaho Power has spent approximately $380 million, including Idaho Power's AFUDC, on the B2H project through December 31, 2024. 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.

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.

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.

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

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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.

The permitting phase of the GWW project was subject to review and approval of the BLM. The BLM has published its records of decision for all segments of the transmission line. In 2020 and 2024, PacifiCorp completed construction and commissioned segments of its portion of the project in Wyoming. In March 2023, PacifiCorp initiated the pre-construction phase of 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.

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

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

Relicensing costs of $497 million (including AFUDC) for the HCC were included in construction work in progress at December 31, 2024. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million of AFUDC annually relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of December 31, 2024, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $251 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 the license. Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial. In December 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.

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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.

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

Defined Benefit Pension Plan Contributions and Recovery

Idaho Power contributed $20 million in 2024 and $48 million in 2023 to its defined benefit pension plan. Idaho Power estimates that it has no minimum required contribution to be made during 2025. Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $20 million to the pension plan during 2025. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position. Beyond 2025, Idaho Power expects continuing contributions under the pension plan could be significant. Refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.

Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. At December 31, 2024 and 2023, Idaho Power's deferral balance associated with the Idaho jurisdiction was $252 million and $255 million, respectively. Deferred pension costs are amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. 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 primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Contractual Obligations

IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 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. Refer to Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to purchase obligations and other long-term liabilities.

Dividends

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

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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 2024 and 2023, IDACORP's board of directors voted to increase the quarterly dividend to $0.86 per share and $0.83 per share of IDACORP common stock, respectively. IDACORP's dividends during 2024 were 60.9 percent of actual 2024 earnings.

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

Contingencies and Proceedings

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

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

Off-Balance Sheet Arrangements

IDACORP’s and Idaho Power’s off-balance sheet arrangements as of December 31, 2024, include guarantees of Idaho Power's portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. See Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to off-balance sheet arrangements.

REGULATORY MATTERS

Introduction

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

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

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Notable Retail Rate Changes in Idaho and Oregon

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

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.

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. 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.

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

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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. 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.

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.

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.

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: 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. 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

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between Idaho Power and Micron Technology, Inc. (Micron). 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.

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, for electric service for Micron's new memory manufacturing fabrication complex (fab) located in Boise. 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.

Deferred Net Power Supply Costs

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

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

Factors that have influenced power cost adjustment rate changes in recent years include year-to-year volatility in hydropower generation conditions, market energy prices and the volume of wholesale energy sales, power purchase costs from renewable energy projects, 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):

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. Idaho Power's final rate was based on a net annual transmission revenue requirement of $137.9 million. The OATT rate in effect from October 1, 2023, to September 30, 2024, was $30.74 per kW-year based on a net annual transmission revenue requirement of $135.7 million. A kW-year is a unit of electrical capacity equivalent to 1 kW of power used for 8,760 hours.

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Relicensing of Hydropower Projects

Overview: Idaho Power, like other utilities that operate non-federal hydropower projects on qualified waterways, obtains licenses for its hydropower projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. See Note 12 - "Property, Plant and Equipment and Jointly-Owned Projects" to the consolidated financial statements included in this report for information regarding relicensing costs for the HCC. In addition to the discussion below, refer to “Hells Canyon Complex Relicensing” in “Liquidity and Capital Resources” in this MD&A for a discussion of the costs and expected timing of an HCC license and "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydropower generating plants.

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

In connection with its relicensing efforts, Idaho Power filed annual water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards. Challenges regarding how to meet water temperature standards below the HCC for spawning fall Chinook salmon, and a conflict in laws between Oregon and Idaho regarding the reintroduction and passage of fish above the HCC, delayed the issuance of the 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 increase the number of Chinook salmon it releases each year through expanded hatchery production. In 2019, Oregon and Idaho issued final CWA Section 401 certifications which have been submitted to the FERC as part of the relicensing process. Also in 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the settlement among Idaho, Oregon, and Idaho Power. The FERC's decision relating to the Offer of Settlement is pending as of the date of this report.

In 2020, Idaho Power submitted to the FERC its supplement to the final license application, incorporating the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications. The supplement included feedback on proposed modifications of the 2007 final EIS for the HCC, as well as an updated cost analysis of the HCC and a request that the FERC issue a 50-year license and initiate a supplemental NEPA process at the FERC. In 2022, the FERC issued a notice of intent to prepare a supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the USFWS and the NMFS under section 7 of the ESA. In 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 February 2025, Idaho Power submitted to the FERC, to be included in the final HCC license, agreed-upon language between Idaho Power and the U.S. Army Corps of Engineers regarding flood control requirements applicable to the HCC.

American Falls Relicensing: In 2020, Idaho Power filed with the FERC a notice of intent to file an application to relicense the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a nameplate generating capacity of 92.3 MW. Idaho Power owns the generation facility but not the structural dam or reservoir, which are owned by the U.S. Bureau of Reclamation. Idaho Power filed the final relicensing application with the FERC in February 2023. In September 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.

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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.

ENVIRONMENTAL MATTERS

Overview

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

Compliance with current and future environmental laws and regulations may:

•increase the operating costs of generating plants;

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

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

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

•reduce the output from current generating facilities; or

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

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

Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2025 to 2027. Given the uncertainty of future environmental regulations and technological advances, there is uncertainty around near-term estimates, and Idaho Power is also unable to predict its environmental-related expenditures beyond 2027, though they could be substantial. Changes in Presidential Administrations and Congressional elections since 2017 have resulted, and in the future could result, in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. Executive orders that could be issued by the current Presidential Administration and the outcome of U.S. federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict.

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

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

Endangered Species Act Matters

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

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

There are a number of threatened or endangered species within Idaho Power's service area located in waterways in which Idaho Power has hydropower facilities, and within or near proposed transmission line routes. To date, efforts to protect these species have not significantly affected generation levels or operating costs at any of Idaho Power's hydropower facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases. These ESA regulations could impact the timing and feasibility of the HCC relicensing project and the GWW and B2H transmission projects and other infrastructure projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay construction.

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. 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. 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. 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: The listing of a species, or changes to the critical habitat designations, of fish, wildlife, or plants as threatened or endangered under the ESA and the associated mitigation policies may have an adverse impact on Idaho Power's ability to construct power supply, transmission, or distribution facilities or relicense or operate its hydropower facilities. In March 2024, the USFWS published a final rule which, among other items, reinstated the “blanket rule” that allows the USFWS to treat threatened species the same (or similar) as endangered species under Section 4(d) of the ESA. 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.

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

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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. 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.

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

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

Overview: Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing CO2 emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Stringent emissions standards could result in significant increases in capital expenditures and operating costs, which may accelerate the retirement of coal-fired units and create power system reliability issues. Some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a cessation of operation, as the cost of compliance makes the plants uneconomical to operate. As a result, Idaho Power ended its participation in coal-fired operations at the 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; and (3) 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

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for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates. Accordingly, Idaho Power cannot predict the effect on its results of operations, financial condition, or cash flows of any GHG emissions or other climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. A more detailed discussion of legislative and regulatory developments related to climate change follows.

National GHG Initiatives; Clean Power Plan/Affordable Clean Energy Rule: The EPA has been active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.

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

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

In April 2024, the EPA released a final rule under Section 111 of the CAA (New Section 111 Rule) that regulates CO2 emissions from coal- and natural gas-fired electric generating units. Under the final rule, applicable standards of emission reduction vary based upon the retirement date of coal units and the capacity factor of existing and new natural gas units. The EPA based some of its requirements on carbon capture and storage technology. Idaho Power, among many other parties, filed suit in May 2024 in the U.S. Court of Appeals, D.C. Circuit, to challenge the New Section 111 Rule. Idaho Power's suit was consolidated with other similar suits, and the proceedings were placed on hold in February 2025 at the request of the EPA.

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.

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

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

Other Clean Air Act Matters

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

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

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

Regional Haze / Good Neighbor Plan: In June 2023, the EPA published the final rule under the CAA called the Federal "Good Neighbor Plan" for the 2015 Ozone National Ambient Air Quality Standards (Good Neighbor Plan), which took effect on August 4, 2023. The Good Neighbor Plan establishes nitrogen oxides (NOx) emissions budgets requiring fossil fuel-fired power plants to participate in an allowance-based ozone season trading program. The EPA's final rule temporarily excluded power plants located in Wyoming, while the EPA reevaluated the proposed disapproval of the Wyoming SIP. In December 2023, the EPA approved the Wyoming SIP, removing it from the Federal Implementation Plan (FIP).

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

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

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

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 NOx 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).

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.

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.

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.

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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 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 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.

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.

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 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. 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Accounting for Rate Regulation

Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items must be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an

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independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service area must lack competitive pressures to reduce rates below the rates set by the regulator.

Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded approximately $1.5 billion of regulatory assets and $1.0 billion of regulatory liabilities at December 31, 2024. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.

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

Income Taxes

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

Pension and Other Postretirement Benefits

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

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

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2024, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 2025 defined benefit plan pension expense increased to 5.70 percent from the 5.10 percent rate used in 2024.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. The long-term rate of return used to calculate the 2025 pension expense will be 7.4 percent, the same assumption as used in 2024.

Total net periodic pension and other postretirement benefit cost for these plans totaled $31.0 million and $28.5 million for the years ended December 31, 2024 and 2023, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2025, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $27.2 million, which takes into account the change in the discount rate noted above.

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

Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $71.2 million decrease in the combined benefit obligations of the plans as of December 31, 2024. A 0.5 percent decrease in the plans' discount rates would have resulted in an $79.3 million increase in the combined benefit obligations of the plans as of December 31, 2024.

The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2024, a total of $252 million of expense was deferred as a regulatory asset. Idaho Power expects net amortization of the regulatory asset of approximately $18 million in 2025. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $36 million in 2024 and $18 million in 2023.

Refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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