What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-02-20 compared with 2024-02-15 · 445 added, 444 removed, 609 unchanged (59% of the section changed)

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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 IDACORP Financial Services, Inc., an investor in affordable housing and other real estate tax credit investments;

and Ida-West Energy Company, an operator of small hydropower generation projects that satisfy the requirements of the PURPA.

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

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This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report.

Examples of IDACORP's and Idaho Power's achievements, notable events, milestones, and recognitions during 2023 include:

• IDACORP achieved net income growth for a sixteenth consecutive year.

Idaho Power achieved a 9.4 percent return on year-end equity in the Idaho jurisdiction without the need to amortize additional ADITCs available under its Idaho regulatory mechanism, described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in 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 2023, the IPUC approved a settlement stipulation publicly filed by Idaho Power, the Staff of the IPUC, and intervening parties (2023 Settlement Stipulation) related to the Idaho general rate case that Idaho Power had filed in June 2023.

Also, in December 2023 Idaho Power filed a general rate case with the OPUC.

The general rate case filings and 2023 Settlement Stipulation 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 2.4 percent in 2023 and Idaho Power's MWh sales to retail customers in 2023 were the second highest in its history, only behind 2022.

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.

• In September 2023, Idaho Power filed its 2023 IRP with the IPUC and OPUC.

The 2023 IRP preferred resource portfolio plans for a significant increase in energy and capacity resources over the next 20 years to meet growing demand, primarily solar, wind, and battery resource additions.

In addition, the preferred resource portfolio includes conversions of multiple jointly-owned coal-fired generation units to natural gas-fired generation units.

To support the resource additions, the preferred portfolio also includes the Boardman-to-Hemingway transmission line with an in-service date in 2026 and three Gateway West transmission line segments phased in with in-service dates from 2028 through 2040.

• In September 2023, IDACORP's board of directors approved a 5.1 percent increase in the regular quarterly cash dividend on IDACORP’s common stock from $0.79 per share to $0.83 per share, as a part of a 177 percent increase in quarterly dividends approved over the last twelve years.

• In March 2023, Idaho Power executed an agreement with the BPA to transfer BPA's 24 percent interest in the Boardman-to-Hemingway transmission line project to Idaho Power, bringing Idaho Power's interest in the project to

In June 2023, both the IPUC and OPUC granted certificates of public convenience and necessity (CPCNs) related to the construction of the Boardman-to-Hemingway transmission line, and Idaho Power plans to begin construction in 2024.

• In April 2023, Idaho Power entered into a 20-year agreement to utilize the storage capacity from a 150-MW battery storage facility scheduled to be online in June 2025.

Idaho Power intends for this capacity to supplement 304 MW of company-owned storage that it expects to be online by the end of 2025.

In 2023, 131 MW of company-owned battery storage were installed.

• Idaho Power issued a formal RFP in April 2023, soliciting bids for new energy and capacity resources as well as energy that can be delivered via transmission, beginning in 2026.

At the time of the RFP issuance, Idaho Power’s long-range planning process had identified a potential need in 2026 and 2027 of approximately 350 MW of peak capacity, which could be met by approximately 1,100 MW of variable energy resources.

RFP procurement decisions will be based on the most up-to-date energy and capacity need information.

The RFP provides that a portion of these resources may be transmitted via the Boardman-to-Hemingway transmission line project, which Idaho Power plans to have in-service as early as late 2026.

Idaho Power anticipates completing the RFP process in the first half of 2024.

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

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

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

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

• Idaho Power's 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

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Increase (decrease) in Idaho Power net income:

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

Customer growth, net of associated power supply costs and power cost adjustment mechanisms 19.0

Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms 4.5

Idaho FCA revenues 15.1

Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms 11.0

Transmission wheeling-related revenues (0.2)

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

Other O&M expenses (61.1)

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Other changes in operating revenues and expenses, net 30.8

Decrease in Idaho Power operating income (13.8)

Increase in Idaho Power operating income 14.8

Non-operating expense, net (2.2)

Income tax expense 11.0

Additional ADITC amortization 29.8

Income tax expense, excluding additional ADITC amortization (18.6)

Total increase in Idaho Power net income 23.8

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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.

Lower sales volumes on a per-customer basis among all customer classes, but more significantly among residential and

irrigation customers, decreased operating income by $31.3 million in 2023 compared with 2022.

More moderate temperatures and greater precipitation in Idaho Power's service area during 2023, compared with 2022, led residential customers to use less energy per customer for cooling and heating and agricultural irrigation customers to use less energy per customer to operate irrigation pumps.

The negative revenue impact of the decrease in sales volumes per residential and small commercial customer was partially offset by the FCA mechanism, which increased revenues in 2023 by $15.1 million compared with 2022.

The net increase in retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $11.0 million in 2023 compared with 2022.

The net increase in retail revenues per MWh was primarily due to the June 1, 2022, rate increase for Idaho Power’s Idaho retail customers related to an order from the IPUC that authorized Idaho Power to accelerate the depreciation on and recover through 2030 the net book value of coal-related assets at Idaho Power's jointly-owned Jim Bridger plant, as of December 31, 2020, plus forecasted plant investments (Bridger Order).

Other O&M expenses were relatively flat in 2023 compared with 2022, as inflationary pressures on labor-related costs were mostly offset by lower expenses from scheduled cyclical plant maintenance projects, as well as the timing of regulatory deferrals and payment credits received related to a jointly-funded infrastructure project.

Depreciation expense increased $25.3 million due partially to an increase in plant-in-service.

In addition, the increase was partially due to the impacts of the Bridger Order.

The Bridger Order resulted in Idaho Power recording the deferral of certain depreciation expense in the second quarter of 2022, reducing depreciation expense in that year.

Non-operating expense, net, decreased $4.7 million in 2023 compared with 2022.

AFUDC increased as the average construction work in progress balance was higher throughout 2023 compared with 2022.

Also, interest and investment income increased due to higher interest rates and higher average cash and cash equivalents balances.

These increases were partially offset by higher interest expense on long-term debt and other liabilities in 2023 compared with 2022.

The $11.0 million decrease in Idaho Power income tax expense in 2023 compared with 2022 was primarily due to plant-related tax adjustments at Idaho Power.

2024 Initiatives and Strategy

IDACORP’s strategy is focused on four areas:

keeping employees safe and engaged, growing financial strength, improving Idaho Power's core business, and enhancing Idaho Power’s brand.

IDACORP's directors have reviewed and affirmed IDACORP’s long-term strategy.

In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders.

Idaho Power is committed to working for strong, sustainable financial results by continuing to safely provide reliable, affordable, clean energy to its customers from diversified generation resources, including an increasingly clean portfolio of generation as Idaho Power works toward its “Clean Today.

Cleaner Tomorrow.®” goal of 100% clean energy by 2045.

More specific information on IDACORP’s strategy is included in Item 1 – “Business,” in this report.

Usage per retail customer increased operating income by $4.5 million in 2024 compared with 2023.

Overall, usage per

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

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

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

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

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

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

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

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

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

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

In addition, property taxes contributed to the increase from 2023 to 2024, due primarily to the successful conclusion of multi-year litigation efforts challenging Idaho and Oregon property tax valuations, which resulted in refunds of prior year taxes being finalized in 2024.

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

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

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To provide context for the discussion elsewhere in this report, some of the more notable factors include the following:

• Regulation of Rates and Cost Recovery;

General Rate Case Filings:

• 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 focuses on the prudent management of expenses and investments and on the timely recovery of its costs through filings with its regulators.

In December 2023, the IPUC approved the 2023 Settlement Stipulation between Idaho Power, the Staff of the IPUC, and intervening parties related to the Idaho general rate case filed by Idaho Power in June 2023.

New tariff schedules resulting from the 2023 Settlement Stipulation are designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, and became effective January 1, 2024.

The $54.7 million of additional annual revenue is net of a 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 included 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, excluding coal-related assets at the Jim Bridger plant and North Valmy plant which are recovered under separate regulatory mechanisms.

Idaho Power also made a general rate case filing in Oregon in December 2023 and expects the full processing of that general rate case will take approximately ten months.

The general rate case filings and the 2023 Settlement Stipulation 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.

Several factors impacted Idaho Power’s need to file its general rate cases including the increase in depreciation expense from plant in service, the significant amounts of capital expenditures Idaho Power made since its last general rate case filed in 2011, the financing costs for capital expenditures in a higher interest-rate environment, and, to a lesser extent, inflationary pressures on other O&M expenses.

Due to the continuing impact of many of these same factors and the effect of regulatory lag, on February 14, 2024, Idaho Power provided notice to the IPUC of its intent to file a general rate case or limited issue rate proceeding in Idaho on or after June 1, 2024.

Idaho Power is focused on timely recovery of its costs through filings with its regulators and prudent management of expenses and investments.

To address the regulatory lag in recovery of costs primarily associated with Idaho Power’s current and anticipated significant infrastructure investments, including those that are intended to help meet projected near-term capacity deficits, Idaho Power filed a limited-issue rate case in Idaho on May 31, 2024.

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

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

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

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

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

• Rate Base Growth and Infrastructure Investment:

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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 Boardman-to-Hemingway and Gateway West 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.

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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 in the near-term, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase in the foreseeable future.

Idaho Power filed its most recent IRP with the IPUC and OPUC in September 2023.

The 2023 IRP assumes a forecasted annual growth in retail MWh sales of 5.5 percent and a forecasted annual growth in peak-hour demand of 3.7 percent over the upcoming 5-year period.

For more information on the 2023 IRP, refer to "Resource Planning" in Item 1 – "Business." 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.

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 that Idaho Power increase its investment in capacity resources, transmission, and distribution infrastructure.

This includes the Boardman-to-Hemingway and Gateway West transmission projects, along with other capacity, energy, and transmission resources.

This includes those contemplated by the resource procurements described in the "Liquidity and Capital Resources" in this MD&A.

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.

5-Year Forecasted Annual Growth Rate 20-Year Forecasted Annual Growth Rate

(Billed MWh) Annual Peak

(Peak Demand) Retail Sales

(Billed MWh) Annual Peak

(Peak Demand)

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

2023 IRP 5.5% 3.7% 2.1% 1.8%

2021 IRP 2.6% 2.1% 1.4% 1.4%

Customer growth has contributed to increases in peak loads experienced in recent years.

For example, Idaho Power's highest all-time winter peak demand of 2,719 MW occurred on January 16, 2024, and on July 22, 2024, Idaho Power reached a new all-time summer peak demand of 3,793 MW.

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

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

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.

• Weather Conditions:

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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.

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• 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 power purchase agreements (including PURPA agreements), and power purchases in the wholesale markets.

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.

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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 jointly-owned coal-fired generating plant in North Valmy, Nevada (North Valmy plant), ceasing 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.

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 includes 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.

For more information on the 2023 IRP, refer to "Resource Planning" in Item 1 – "Business" of this report.

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

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

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

• Water Management and Relicensing of Hydropower Projects:

Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects.

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

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

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

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

Idaho Power cannot currently determine the

ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls hydroelectric facilities.

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 trend in the degree of annual destruction from wildfires.

A variety of factors have contributed to this trend including climate change, increased wildland-urban interfaces, historical land management practices, and overall wildland and forest health.

While Idaho Power has not experienced to date the extent of catastrophic wildfires within its service area that have occurred in California and elsewhere in the western United States, Idaho Power is taking a proactive approach to wildfire threat in its service area and transmission corridors.

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.

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

Idaho Power has a regulatory mechanism which allows the company to defer, for future amortization, the Idaho jurisdictional share of actual incremental O&M expenses necessary to implement the WMP.

The WMP regulatory deferral is described in more detail in the "Regulatory Matters" section of this MD&A.

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

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Hydropower generation 7,203 6,548

Coal-fired generation 2,473 3,657

Steam generation (1)

Natural gas-fired and other generation 3,843 2,917

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Total energy supply 18,789 17,610

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

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

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Sales Volume and Generation:

In 2023, retail sales volumes decreased 2 percent compared with the prior year, primarily due to weather variations that caused lower usage per customer.

Greater precipitation and more moderate temperatures in Idaho Power's service area during 2023 led agricultural irrigation customers to use less energy per customer to operate irrigation pumps and residential and commercial customers to use less energy per customer for cooling and heating purposes compared with 2022.

The decrease in usage per customer was partially offset by customer growth, as the number of Idaho Power customers grew by 2.4 percent in 2023.

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 5 percent in 2023 compared with 2022, due primarily to higher natural gas generation and hydropower generation, partially offset by decreased coal-fired generation.

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.

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Total retail revenues $ 1,552,780 $ 1,472,666

(1) The FCA mechanism is an alternative revenue program 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 electric plant in service.

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

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

Customer rates, excluding collections of amounts related to the power cost adjustment mechanisms, increased retail revenues by $11.0 million in 2023 compared with 2022, due primarily to the June 1, 2022 rate increase for Idaho Power’s Idaho retail customers related to the Bridger Order.

Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which increased revenues by $98.5 million in 2023 compared with 2022.

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.

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

Decreased usage (on a per customer basis) in all customer classes decreased retail revenues by $51.4 million during 2023 compared with 2022.

Milder temperatures during 2023, compared with temperatures during 2022, led retail customers to use less energy per customer for cooling and heating.

More precipitation during the spring and late summer of 2023, compared with the same period of 2022, led agricultural irrigation customers to use 7 percent less energy per customer to operate irrigation pumps during 2023.

Heating degree-days in Boise, Idaho, were 13 percent lower during 2023 compared with 2022, and 5 percent lower than normal.

Also, cooling degree-days in Boise, Idaho, were 4 percent lower during 2023 compared with 2022 and 28 percent above normal.

• Idaho FCA Revenues:

The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year.

Lower usage (on a per customer basis) by residential and small commercial customers during 2023 increased the amount of FCA revenue accrued by $15.1 million, compared with 2022.

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 :

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Wholesale energy revenues per MWh $ 52.34 $ 75.50

In 2023, wholesale energy revenue decreased by $3.1 million, or 5 percent, compared with 2022, as higher wholesale energy sales volumes were more than offset by lower wholesale market prices.

The increase in wholesale energy volumes sold during 2023, was partially due to energy originally purchased under derivative forward contracts to be bundled with RECs, but the energy was ultimately sold in the wholesale markets.

Those sales increased wholesale energy revenues by $16.7 million in 2023, and a corresponding amount was recorded in purchased power on the consolidated statements of income.

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.

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

The decrease in purchased power expense in 2023 is primarily due to lower wholesale energy market prices as milder summer and winter weather resulted in lower demand and lower fuel costs (natural gas and coal) in the wholesale markets in the region.

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."

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2024 2023 2024 2023 2024 2023

Coal $ 95,499 $ 105,552 2,473 3,657 $ 38.62 $ 28.86

$ 97,427 $ 95,499 2,474 2,473 $ 39.38 $ 38.62

Natural gas (2)

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Total/Weighted average, all $ 259,204 $ 275,405 6,317 5,390 $ 41.03 $ 51.10

(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.

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Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods.

Fuel expense increased $45.2 million, or 20 percent, in 2023 compared with 2022, despite lower total thermal generation.

The increase in fuel expense was primarily due to higher coal purchase prices and higher natural gas market prices in 2023, which resulted in an increase in the average cost per MWh of coal and natural gas generation.

The mix of Idaho Power's thermal generation between natural gas and coal in 2023 compared with 2022 was affected by fluctuations in natural gas prices and coal supply constraints.

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 2023, losses on financial gas hedges of $16.2 million increased natural gas fuel expense.

In 2022, gains on financial gas hedges of $68.5 million reduced natural gas fuel expense.

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.

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The Idaho deferral period, or PCA year, runs from April 1 through March 31.

Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period.

However, the IPUC directed Idaho Power to spread recovery of the March 31, 2023, PCA deferral

balance over a two-year period from June 1, 2023, to May 31, 2025.

Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1

through May 31 period.

However, the IPUC directed Idaho Power to spread recovery of the March 31, 2023 PCA deferral balance over a two-year period from June 1, 2023, to May 31, 2025.

Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.

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

Oregon power supply cost accrual (deferral) 1,169 (1,079)

Oregon power supply cost accrual 1,954 1,169

Amortization of prior year authorized balances 93,409 72,444

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When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability.

During 2023, higher fuel costs partially offset by lower purchased power expense led to higher actual power supply costs compared with the forecasted amount, which resulted in the deferral of power supply costs.

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 $0.5 million in 2023 compared with 2022, as inflationary pressures on labor-related costs were mostly offset by lower expenses from scheduled cyclical plant maintenance projects as well as the timing of regulatory deferrals and payment credits received related to a jointly funded infrastructure project.

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

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

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

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

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

The decreases were primarily due to plant-related tax adjustments at Idaho Power.

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.

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

• 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;

• 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;

• 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.

• IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available credit capacity under their respective credit facilities;

• IDACORP's forward sale agreements (FSA), which may be physically settled with common stock in exchange for net proceeds, which as of February 9, 2024, would be approximately $291 million.

In March 2023, Idaho Power issued the following long-term debt with the proceeds being used for general corporate purposes, including repaying outstanding commercial paper and long-term debt and funding Idaho Power's capital projects:

• $60 million of 5.06% first mortgage bonds, secured medium-term notes, Series N, maturing in March 2043;

• $62 million of 5.20% first mortgage bonds, secured medium-term notes, Series N, maturing in March 2053;

• $400 million of 5.50% first mortgage bonds, secured medium-term notes, Series M, maturing in March 2053.

During March through May 2023, a portion of the proceeds from the March 2023 issuances was used to repay outstanding commercial paper, $150 million in principal amount from a March 2022 term loan agreement, and $75 million in principal amount of maturing 2.50% first mortgage bonds, Series I.

In September 2023, Idaho Power issued $350 million of 5.80% first mortgage bonds, secured medium-term notes, Series M, maturing in April 2054 with the proceeds used for general corporate purposes, including funding its capital projects.

In November 2023, IDACORP entered into FSAs in connection with a completed $299 million public offering of approximately 3.2 million shares of its common stock.

IDACORP may settle the agreements at any time up to the maturity date of November 7, 2024.

Depending on settlement timing, if IDACORP elects to physically settle by delivering shares of common stock, cash proceeds are expected to be approximately $290 million to $295 million.

The proceeds are expected to be used for general corporate purposes, including funding Idaho Power's capital projects.

For more detailed information about IDACORP's FSAs, see Note 6 - "Common Stock" to the consolidated financial statements included in this report.

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 debt securities or first mortgage bonds, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent.

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.

In January 2024, IDACORP began using original issuances of shares for its dividend reinvestment and stock purchase plan and also intends to use original issuances of IDACORP shares for share purchases within Idaho Power's employee savings plan going forward.

IDACORP may discontinue using original issuances of shares for its dividend reinvestment and stock purchase plan and/or the employee savings plan at any time.

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.

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However, if actual costs rise above the level currently allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.

IDACORP’s and Idaho Power’s operating cash inflows in 2023 were $267 million and $207 million, respectively, a decrease of $84 million and $174 million for IDACORP and Idaho Power, respectively, when compared with 2022.

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 2023 when compared with 2022 were as follows:

• a $2 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 Idaho PCA, FCA, and wildfire mitigation, increased operating cash inflows by $75 million;

• changes in deferred taxes and taxes accrued and receivable combined to increase operating cash flows for IDACORP and Idaho Power by $32 million and $38 million, respectively;

• contributions to pension and postretirement benefits plans decreased IDACORP and Idaho Power cash flows by $11 million;

• changes in distributions from equity-method investments, primarily related to IERCo, a wholly-owned subsidiary of Idaho Power, decreased IDACORP and Idaho Power cash flows by $9 million and $10 million, respectively;

• changes in working capital balances due primarily to timing, including fluctuations in accounts receivable and unbilled revenues, materials, supplies, and fuel stock, accounts and wages payable, and other assets and liabilities, as follows:

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;

• 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 decreased operating cash flows by $194 million for IDACORP and $288 million for Idaho Power, which was primarily due to an increase in power supply costs and associated timing of payments, and includes a $94 million difference between IDACORP and Idaho Power related to intercompany estimated tax payments;

◦ the changes in other assets and liabilities, which includes accrued paid time off and leave, customer deposits, accrued interest, and other miscellaneous liabilities, decreased operating cash flows by $12 million for IDACORP and Idaho Power.

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

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

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 2023 were $590 million and $582 million, respectively.

Investing cash outflows for 2023 and 2022 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth, aging plant and equipment, and environmental and regulatory compliance requirements.

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:

• $611 million and $433 million, respectively, of additions to property, plant and equipment, including $112 million spent on battery storage projects, and at December 31, 2023, $31 million was accrued in accounts payable on their consolidated balance sheets related to battery payments;

• $27 million and $18 million, respectively, from Boardman-to-Hemingway project joint permitting participants relating to a portion of the permitting expenditures;

• $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;

• $8 million in 2022 related to return of investment from IERCo, a wholly-owned subsidiary of Idaho Power;

• $11 million and $44 million in purchases of equity securities, respectively, $2 million and $31 million in purchases of held-to-maturity securities, respectively, and $9 million and $64 million in sales of equity securities, respectively, held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's SMSP;

• $25 million in 2022 of both purchases and sales of short-term investments at IDACORP.

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

Financing Cash Flows

Financing activities 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 2023 were $473 million and $538 million, respectively.

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 2023 were as follows:

• in 2023, Idaho Power issued $872 million in aggregate principal amount of first mortgage bonds, secured medium-term notes, as described above in this "Liquidity and Capital Resources" section;

• 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, secured medium-term notes at maturity, each as described above in this "Liquidity and Capital Resources" section;

• IDACORP and Idaho Power paid dividends of $164 million and $102 million in 2023, respectively.

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;

• 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 issued no equity securities in 2023 other than under its equity compensation plans.

As described elsewhere in this MD&A, IDACORP has significant planned capital expenditures in the near-term, and the company plans to issue approximately 3.2 million shares of common stock during 2024 under the FSAs.

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.

Term Loan Credit Agreement:

In March 2022, Idaho Power entered into a term loan credit agreement (Term Loan Facility).

The Term Loan Facility was a two-year senior unsecured term loan facility in the aggregate principal amount of $150 million.

On March 31, 2023, Idaho Power repaid $100 million and on May 17, 2023, repaid $50 million principal amount to fully repay the Term Loan Facility.

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 May and June 2022, 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, 2023, $280 million remains available for debt issuance under the regulatory orders.

In January 2024, Idaho Power submitted applications to the IPUC, OPUC, and WPSC requesting authorization to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, which if approved will replace the $280 million remaining on the 2022 orders.

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.

In December 2022, Idaho Power entered into a Bond Purch ase Agreement with certain institutional purchasers, relating to t he sale by the Idaho Power of $170 million in aggregate principal amount of first mortgage bonds, secured medium-term notes, Series N (Series N Notes).

Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated December 20, 2022, to the Indenture (Fifty-second Supplemental Indenture).

The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series N Notes pursuant to the Indenture.

The Series N Notes consist of four tranches of bonds, due in 2032, 2042, 2043, and 2053, respectively.

The first two tranches were issued on December 22, 2022, and the third and fourth tranches were issued on March 8, 2023, each under the Indenture .

Idaho Power used the proceeds of the sale of the Series N Notes for general corporate purposes, primarily related to the construction of a battery storage project.

At December 31, 2023, $170 million in principal amount of Series N Notes had been issued and was outstanding.

For more detailed information about the Series N Notes, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.

IDACORP and Idaho Power Credit Facilities (Credit Facilities) :

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 existing credit agreements, dated November 18, 2022, as amended.

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.

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

The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or Adjusted Term 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.

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.

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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.

Both the IDACORP and Idaho Power Credit Facilities mature on December 8, 2028, and each contains the rights to request up to two one-year extensions, subject to certain conditions.

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.

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The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue.

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

Individual instruments carry a fixed rate during

their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity

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(2) Holding company only.

At February 9, 2024, IDACORP and Idaho Power had no loans outstanding under their respective revolving Credit Facilities and no commercial paper outstanding.

The table below presents additional information about short-term commercial paper borrowing during the year ended December 31 (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).

Idaho Power IDACORP (1)

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IDACORP Idaho Power IDACORP Idaho Power

Rating Outlook Stable Stable Stable Stable

Rating Outlook Negative Negative Stable Stable

Issuer Rating/Corporate Baa2 Baa1 BBB BBB

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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 2024 through 2028 (in millions of dollars).

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.

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2025 2026 2027-2029

Expected capital expenditures (excluding AFUDC) $ 925-975 $ 850-950 $ 2,000-2,500

Expected capital expenditures (excluding AFUDC), in billions of dollars $ 1.00 - 1.10 $ 1.25 - 1.35 $ 3.10 - 3.60

Infrastructure Projects:

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Examples of anticipated system enhancements planned for 2025 through 2029 and estimated costs include the following:

• $140-$250 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;

• $130-$175 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;

• $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;

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Resource Additions to Address Projected Energy and Capacity Deficits :

As noted previously, 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 from 2023 through 2025, Idaho Power entered into contracts to purchase, own, and operate 304 MW of battery storage assets with expected useful lives of approximately 20 years, entered into a 20-year agreement to purchase the storage capacity from a 150-MW battery storage facility, and also entered into three power purchase agreements for the combined 340 MW output of planned third-party solar facilities with 20- and 25-year terms.

As described in “Regulatory Matters” of this MD&A, Idaho Power plans to sell the output of two of these solar power purchase agreements totaling 240 MW exclusively to two large industrial customers under agreements modeled after Idaho Power’s Clean Energy Your Way program.

The capital requirements table above includes capital expenditures of more than $220 million in the years 2024 through 2025 for resource additions to address projected energy and capacity deficits in those years.

To help address the additional capacity deficits projected for 2026 through 2027, Idaho Power has issued an RFP for additional resources.

The table above does not currently include any amounts for possible company-owned resources from the RFP to address projected deficits in 2026 or 2027.

Depending on factors such as RFP results, the timing of project in-service dates, estimated load and resource balances and customer growth, the nature and quantity of resources owned versus acquired under power purchase agreements or similar agreements, and the outcome of regulatory proceedings, actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures.

Boardman-to-Hemingway Transmission Line :

The Boardman-to-Hemingway 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 and construction subcontract bid events are in progress.

As a result of delays in issuing Notices to Proceed from state and federal agencies and obtaining right-of-way grants, Idaho Power expects construction will begin in 2024.

Given the status of ongoing activities and the construction period, Idaho Power expects the in-service date for the transmission line will be no earlier than late 2026.

Until recently, Idaho Power had a joint funding agreement with PacifiCorp and BPA to pursue permitting of the project, 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.

Idaho Power's existing and sustained growth in customers, load, and peak demand for electricity, along with transmission constraints, has created the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs over the next several years.

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

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

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

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

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

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

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

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

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

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

Depending on factors such as RFP results, the timing of project in-service dates, estimated load and resource balances and customer growth,

the nature and quantity of resources owned versus acquired under PPAs or similar agreements, and the outcome of regulatory proceedings, actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures.

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.

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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 $215 million, including Idaho Power's AFUDC, on the Boardman-to-Hemingway project through December 31, 2023.

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.

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The agreement became fully effective in September 2023.

The permitting phase of the Boardman-to-Hemingway project was subject to federal review and approval by various federal agencies.

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.

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

Idaho Power is pursuing multiple amendments to the site certificate to accommodate route changes and enhance constructability.

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 filed in Union County Circuit Court contesting the EFSC’s approval of the first amendment, which Idaho Power is seeking to remove to the appropriate venue to expedite review.

Idaho Power submitted its preliminary request for a second amendment in June 2023,

which remains 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 Boardman-to-Hemingway project.

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.

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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.

Gateway West Transmission Line :

Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a high-voltage transmission lines project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho.

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.

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

The estimated cost range is based on assumptions about Idaho Power participation levels in the construction of certain project segments and any changes in those assumptions or in Idaho Power's actual participation could affect future estimates and actual project costs.

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

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

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

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

The permitting phase of the Gateway West project was subject to review and approval of the BLM.

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 late 2020, PacifiCorp completed construction and commissioned a 140-mile segment of its portion of the project in Wyoming.

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

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

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

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

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

In 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 :

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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 $460 million (including AFUDC) for the HCC, Idaho Power's largest hydropower complex and a major relicensing effort, were included in construction work in progress at December 31, 2023.

As of the date of this report, the IPUC has authorized Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million annually of AFUDC relating to the HCC relicensing project.

Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates.

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 in 2025 or thereafter.

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

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

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

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

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

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

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

In April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor

recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date.

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.

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:

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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.

Long-Term Resource Planning:

The IPUC and OPUC require that Idaho Power prepare biennially an IRP.

The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term, mid-term, and long-term actions.

Idaho Power filed its most recent IRP with the IPUC and OPUC in 2023.

Information on Idaho Power's 2023 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.

Defined Benefit Pension Plan Contributions and Recovery

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

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

directors' dividend decisions.

Notwithstanding the dividend policy adopted by IDACORP's board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the factors above, among others.

In September of 2023 and 2022, IDACORP's board of directors voted to increase the quarterly dividend to $0.83 per share and $0.79 per share of IDACORP common stock, respectively.

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

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

In September 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.

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These factors include in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates, as well as other factors.

In recognition of 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 general rate case in Idaho in June 2023.

The 2023 Settlement Stipulation was filed for that rate case in October 2023, and the IPUC approved the 2023 Settlement Stipulation on December 28, 2023, with rates effective January 1, 2024.

Idaho Power filed a general rate case in Oregon on December 15, 2023.

With the large amount of ongoing investments and the associated regulatory lag in cost recovery, on February 14, 2024, Idaho Power provided notice to the IPUC of its intent to file a general rate case or limited issue rate proceeding in Idaho on or after June 1, 2024.

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

Idaho Power filed 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.

Notable Retail Rate Changes in Idaho and Oregon

The table below presents notable rate changes during 2023 and 2022 that affected Idaho Power's results for the periods or that will likely affect future periods.

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.

The table does not include the changes to rates effective January 1, 2024, resulting from the 2023 Settlement Stipulation.

Description Effective Date Estimated Annualized Rate Impact (millions) (1)

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

2024 Idaho PCA 6/1/2024 (35.7)

2024 Idaho FCA 6/1/2024 11.7

2023 Oregon general rate case 10/15/2024 6.7

2023 Idaho general rate case 1/1/2024 54.7

2023 Idaho PCA 6/1/2023 105.1

2023 Idaho FCA 6/1/2023 (10.1)

Idaho Bridger rate base adjustment and recovery 6/1/2022 19

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

The rate changes for the Idaho PCA and FCA are applicable only for one-year periods and represent the net change to the deferral balance from the prior year's filing, as well as a forecast component for the PCA.

Idaho and Oregon General Rate Cases

As noted above, on December 28, 2023, the IPUC approved the 2023 Settlement Stipulation in connection with Idaho Power's general rate case.

The 2023 Settlement Stipulation provides 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 provides 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.

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, 2023, Idaho Power estimates that it had $86 million of deferred credits for future use under the ADITC and Revenue Sharing mechanism.

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.

Previously, effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the OPUC approving a settlement stipulation in its general rate case proceedings that provided for a $1.8 million base rate revenue increase, a rate of return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction.

Oregon base rates were subsequently adjusted again in 2012 and 2020.

Idaho Power is unable to predict the outcome of the Oregon general rate case, but anticipates that new rates, if approved by the OPUC, would become effective in October 2024 or later.

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

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

May 2018 Idaho Tax Reform Settlement Stipulation:

In May 2018, the IPUC issued an order approving a settlement stipulation (2018 Settlement Stipulation) related to income tax reform.

In 2023, Idaho Power recorded no amounts for sharing with customers under this stipulation.

For the years 2011 through 2022, Idaho Power recorded $58.7 million as a refund to customers and $68.1 million as a pre-tax charge to pension expense cumulatively under the 2018 Settlement Stipulation and its predecessors.

For more information on the provisions of the 2018 Settlement Stipulations, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

North Valmy Base Rate Adjustment Settlement Stipulations:

Idaho Power has settlement stipulations in place in Idaho and Oregon related to the planned early retirement of both units of its jointly-owned North Valmy coal-fired power plant.

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

Jim Bridger Power Plant Rate Base Adjustment and Recovery:

In June 2022, the IPUC issued an order (Bridger Order) approving, with modifications, Idaho Power’s amended application related to adjustment and recovery of the Jim Bridger Power Plant rate base.

The Bridger Order and associated accounting are described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.

Regulatory orders from the IPUC and OPUC provide for Idaho Power to cease coal-fired operations at the Jim Bridger plant by the end of 2028.

However, as noted previously, Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024 and the remaining two units at the Jim Bridger plant in 2030.

Idaho Power expects to seek approval from the IPUC and OPUC for any necessary adjustments to plant retirement dates to align with its current resource plan.

Wildfire Mitigation Cost Deferral:

Beginning in 2021, the IPUC has authorized Idaho Power to defer for future amortization certain expenses necessary to implement the company's WMP.

The wildfire mitigation cost deferral is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Fixed Cost Adjustment:

The FCA mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kWh charge and linking it instead to a set amount per customer.

The FCA mechanism is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Integrated Resource Plan and Resource Procurement Filings:

Idaho Power filed its most recent IRP with the IPUC and OPUC in September 2023, as described in Part 1, Item 1 - "Business - Resource Planning" in this report.

The State of Oregon has competitive bidding rules regarding a public utility's procurement of resources.

However, as allowed by the rules in certain cases, Idaho Power is pursuing exceptions for its identified 2024 and 2025 resource needs.

In July 2023, following review by an independent evaluator appointed by the OPUC, OPUC staff, and other intervening parties, the OPUC issued an order approving issuance of Idaho Power's final RFP to procure resources for its anticipated energy and capacity needs in 2026 and 2027.

Customer-Owned Generation Filing:

Customer-owned generation enables customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid.

If a customer requires more energy than its system generates, it uses energy supplied by Idaho Power’s grid and infrastructure.

If a customer's system generates more energy than the customer uses, the energy is transferred to the grid and Idaho Power applies a corresponding kWh credit to the customer’s bill.

The IPUC issued an order in February 2020 directing Idaho Power to continue to allow residential and small commercial customers with on-site generation installed prior to December 20, 2019, to be subject to the compensation and billing structure in place on that date until December 20, 2045.

In December 2020, the IPUC issued an order establishing a 25-year grandfathering term for large commercial, industrial, and irrigation customers, similar to the terms approved for the residential and small commercial customer classes.

In June 2022, as directed by the IPUC, Idaho Power filed a comprehensive study on the costs and benefits of on-site generation based on the IPUC’s study framework findings and conclusions, and in December 2022, the IPUC issued an order that directed Idaho Power to file a new case requesting to implement changes to the structure and design of its on-site generation program.

In May 2023, Idaho Power filed a new case as directed by the IPUC, requesting to implement changes for non-grandfathered customers starting January 1, 2024, including:

(1) a change from net monthly to real-time net billing, which would better measure customers’ actual reliance on the grid;

(2) a change in the excess exported energy credit from a kWh credit ranging in value of 5 to 12 cents, depending on the customer class, to a time-differentiated financial bill credit ranging from approximately 5 to 20 cents per kWh that would be updated annually;

and (3) a modification to the eligibility cap for large commercial, industrial, and irrigation customers.

On December 29, 2023, the IPUC approved Idaho Power's filing, with certain modifications, including an adjustment to the financial bill credit rates to a range from 5 to 17 cents as well as other administrative modifications.

Idaho Power filed its most recent IRP with the IPUC and OPUC in September 2023 and expects to file its next IRP during 2025, as described in Part 1, Item 1 - "Business - Resource

Planning" in this report.

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

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

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

The IPUC approved this application in August 2024.

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

The IPUC approved this application in November 2024.

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

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

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

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

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

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

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

Clean Energy Your Way Program :

In August 2023, the IPUC approved Idaho Power's application to expand optional customer clean energy offerings through its new Clean Energy Your Way Program.

Specifically, Idaho Power received authority to:

(1) rename its existing green power program;

(2) maintain and expand procurement options for the RECs;

(3) establish a regulatory framework for a future voluntary subscription green power service program;

(4) offer a tailored renewable option for Idaho Power's largest customers;

and (5) procure the associated additional resources outside of the IPUC's current competitive procurement requirements.

Brisbie, LLC (Brisbie) Data Center :

In April 2023, the IPUC approved an arrangement, modeled after the Clean Energy Your Way program under which a new large load customer, Brisbie, LLC (Brisbie), a wholly-owned subsidiary of Meta Platforms, Inc., would purchase from Idaho Power energy for a new 960,000 square-foot enterprise data center.

The energy to be purchased by Brisbie is anticipated to be generated by a to-be-constructed 200-MW solar facility pursuant to a long-term power purchase agreement between Idaho Power and a third party, as well as additional renewable resource projects to be developed.

The 200-MW solar facility is scheduled to begin operating as early as March 2025.

In January 2024, Idaho Power filed for IPUC approval of an additional contract with a 125-MW solar project to be online in December 2026.

In May 2023, the IPUC issued an order approving, with modifications, a special contract for electric service for Brisbie for the new data center.

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

Brisbie, in addition to its large load service requirements in excess of 20 MW, has a sustainability objective to support 100 percent of its operations with new renewable resources.

Under the special contract, Idaho Power expects to procure enough renewable resources to support 100 percent of Brisbie's operations on an annual basis with new renewable resources.

The modified special contract and related rate schedule were approved by the IPUC in October 2023.

Micron Dedicated Renewable Resource :

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

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 power purchase agreement between Idaho Power and a third party.

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

between Idaho Power and Micron Technology, Inc.

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

The solar facility began operating in May 2023.

In April 2023, the IPUC issued an order approving Idaho Power's compliance filing of revised electric service rates for Micron that include new energy rates that incorporate the solar generation and compensation for capacity value and excess renewable energy generation.

Lamb Weston, Inc.

Special Contract :

In September 2023, the IPUC issued an order approving Idaho Power's special contract for electric service for an existing large load customer, Lamb Weston, Inc.

(Lamb Weston).

Idaho Power anticipates Lamb Weston's large load service requirements to exceed 20 MW in the near future.

Speculative High-Density Load :

In June 2022, the IPUC approved Idaho Power's application to create a new customer class that would be applicable to commercial and industrial cryptocurrency mining operations, or any other speculative high-density load customers of less than 20 MW.

Idaho Power believes new system resources may be necessary to serve this speculative customer load, which could create a financial risk for Idaho Power and its customers if the underlying economics of cryptocurrency mining change.

Idaho Power believes that the financial and system risks of speculative high-density load could be mitigated through use of a rate design for this customer class that prices energy at a marginal rate, and through a requirement that speculative high-density load customers be interruptible at Idaho Power's discretion from June 15 through September 15, Idaho Power's summer peak season.

As subsequently required by the IPUC, in December 2022, Idaho Power filed an application proposing the interruption compensation for Schedule 20 customers.

In August 2023, the IPUC approved interim interruption compensation rates until a rate can be designed using sufficient data from actual Schedule 20 customers.

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

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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.

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.

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Open Access Transmission Tariff Rate

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC.

In October 2023, Idaho Power filed its 2023 final transmission rate with the FERC, reflecting a transmission rate of $30.74 per "kW-year," to be effective for the period from October 1, 2023, to September 30, 2024.

A "kW-year" is a unit of electrical capacity equivalent to 1 kW of power used for 8,760 hours.

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, 2022 to September 30, 2023, was $31.42 per kW-year based on a net annual transmission revenue requirement of $132.7 mi llion.

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.

Relicensing of Hydropower Projects

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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 a 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.

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 July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license.

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 December 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 August 2007.

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 dam 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 November 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 January 2017.

In February 2018, Idaho Power appealed the FERC's January 2017 order with the United States Court of Appeals for the District of Columbia Circuit, which is pending.

In April 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 May 2019, Oregon and Idaho issued final CWA Section 401 certifications which have been submitted to the FERC as part of the relicensing process.

In December 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.

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 July 2020, Idaho Power submitted to the FERC its supplement to the final license application, incorporating the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications.

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 June 2022, the FERC issued a notice of intent to prepare a supplemental EIS in accordance with NEPA.

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 October 2023, the FERC issued a notice revising the schedule for completing the supplemental EIS.

Under the revised schedule, the draft supplemental EIS is targeted to be published in February 2024 and the final supplemental EIS in November 2024.

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 April 2020, the FERC formally initiated the relicensing of the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a generating capacity of 92.3 MW.

Idaho Power owns the generation facility but not the structural dam itself, which is owned by the U.S.

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.

In February 2023, following the filing of a draft license application and public comment period, Idaho Power filed a final license application with the FERC.

In July 2023, the FERC accepted Idaho Power’s final license application for filing and solicited motions to intervene and protest.

In September 2023, the FERC issued a request for comments to determine the resource issues that should be addressed in the environmental analysis and identify reasonable alternatives to the proposed action that the FERC should evaluate under the NEPA framework.

In January 2024, the FERC indicated that it planned to issue a Notice of Ready for Environmental Analysis, the next major milestone in the relicensing process, in February 2024.

The relicensing has begun the process of informal ESA Section 7 consultation with the USFWS and Section 106 of the National Historic Preservation Act consultation with the Idaho State Historic Preservation Office.

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.

The IDEQ informed Idaho Power that it anticipates preparing a draft certification and will seek public comment once the draft is complete.

American Falls' current license expires in 2025, and as of the date of this report, Idaho Power expects the FERC to issue a new license for this facility concurrent with or prior to the existing license's expiration.

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

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

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

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

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

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

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

ENVIRONMENTAL MATTERS

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

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

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.

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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, as the cost of compliance makes the plants uneconomical to operate.

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

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

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

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.

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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.

Furthermore, several executive orders issued since 2017 concerning environmental regulations, including executive orders issued by the current Presidential Administration to establish new federal environmental mandates, revoke several existing executive orders, and require agencies to review environmental regulations issued by the previous Presidential Administration, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters.

The outcome of federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict.

Additionally, 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 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.

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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.

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

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The uncertainty in the regulatory landscape makes it difficult to predict the scope, timing and complexity of project-related ESA matters to be addressed.

In May 2023, the USFWS published a revised Mitigation Policy and a revised ESA Compensatory Mitigation Policy (Revised Policies) which together establish fundamental mitigation principles and compensatory mitigation standards and application guidance through implementation of the ESA.

The Revised Policies scale back the mitigation goal from the previous policies by including a nexus and proportionality principle to reinforce that government-required mitigation measures must have a clear connection with the anticipated effects of the proposed land use.

As of the date of this report, Idaho Power is uncertain to what extent the Revised Policies may impact its obligations in permitting infrastructure, including relicensing its hydropower facilities, and transmission lines.

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.

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However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.

These ESA regulations could impact the timing and feasibility of the HCC relicensing project and the Gateway West and Boardman-to-Hemingway transmission projects and other infrastructure projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay construction.

These ESA regulations could impact the timing and feasibility of the HCC relicensing project and the GWW 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:

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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 Boardman-to-Hemingway and Gateway West transmission line projects.

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.

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, soliciting public comments on the planning initiative.

It is unclear when the BLM will issue the applicable draft land use plan amendments and associated EISs.

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.

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

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

ESA Issues Related to Specific Projects:

Hells Canyon Relicensing Project :

In December 2004, Idaho Power and eleven other parties, including the NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project.

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.

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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 November 2024 according to the FERC's revised notice of intent.

Gateway West and Boardman-to-Hemingway Transmission Projects and Other Infrastructure - Slickspot Peppergrass Designation :

In August 2016, the USFWS re-instated the threatened species status of slickspot peppergrass under the ESA.

In July 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 Gateway West 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 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.

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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 current Presidential Administration’s Council on Environmental Quality (CEQ) published a final rule that restores a prior NEPA requirement, eliminated under the previous 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 July 2023 the CEQ proposed a

second round of NEPA reform to revise regulations for implementing NEPA.

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.

The CEQ is now working on finalizing the rule.

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

Ongoing climate change could significantly affect Idaho Power's business in a variety of ways, including:

• changes in temperature and precipitation could affect customer demand for electric power;

• extreme weather events, wildfires, drought, and other natural phenomena and natural disasters could increase service interruptions, outages, maintenance costs, system damage, personal property damage, personal injuries and loss of life, legal liability, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of those and other commodities;

• changes in the amount and timing of snowpack and other precipitation and stream flows could affect hydropower generation;

• legislative and/or regulatory developments related to climate change could affect power/generation plants and operations, including restrictions on the construction or addition of new power supply resources, the expansion of existing resources, or the operation of power supply resources;

• consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.

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 CO 2 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 near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate, particularly in light of continued low natural gas prices that decrease the cost to operate natural gas-fired power plants.

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 identifies a preferred resource portfolio and action plan that anticipates (1) converting North Valmy plant units 1 and 2 to natural gas by summer 2026;

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;

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A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions.

These include the specific GHG emissions limits imposed, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates.

for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates.

Accordingly, Idaho Power cannot predict the effect on its results of operations, financial condition, or cash flows of any GHG emissions or other climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial.

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The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.

In May 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.

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 August 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 CO 2 emissions by 32 percent by the year 2030.

In June 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 and the case is pending further legal proceedings.

In May 2023, the EPA released a proposed rule under Section 111 of the CAA to regulate GHG emissions from fossil fuel-fired power plants.

The proposed rule would impose significant GHG emissions reductions on new and existing natural gas-fired generating units and coal plants expected to be operational in 2040 and beyond.

The proposed rule would require states to submit plans to the EPA to implement standards for existing sources within 24 months of the effective date of the emission guidelines.

In August 2023, Idaho Power submitted comments to the EPA requesting it to maintain certain jurisdictional limits published in the rule and create flexibility for state plans to account for system reliability.

In November 2023, the EPA finalized a portion of the Section 111 rule related to existing fossil fuel-fired power plants, but deferred action on new sources, pending additional comments and information related to reliability.

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

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 CO 2 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 CO 2 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:

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Idaho has not passed legislation specifically regulating GHGs.

Wyoming and Nevada similarly have not enacted legislation to regulate GHG emissions and do not have a reporting requirement, but they are members of the Climate Registry.

The Climate Registry is a voluntary collaboration aimed at developing and managing a common GHG emissions reporting system across states, provinces, and tribes to track GHG emissions nationally.

All states for which Idaho Power has traditional fuel generating plants (i.e.

Idaho, Wyoming, and Nevada) are members of the Climate Registry.

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 ."

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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, NAAQS, New Source Review / Prevention of Significant Deterioration Rules, and the Regional Haze Rule.

The MATS rule under the CAA provides that sources must comply with emission limits by April 2015.

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

Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule.

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

These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, and SO 2 .

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

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

and the environment.

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.

However, as of the date of this report, Idaho Power does not expect the recent changes in the NAAQS to significantly impact its operations or materially increase Idaho Power’s capital and operating costs.

In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas.

This includes all units at the Jim Bridger plant, which are subject to regulation by both EPA and WDEQ.

In June 2023, the EPA published the final rule under the CAA called the Federal "Good Neighbor Plan" for the 2015 Ozone NAAQS (Good Neighbor Plan), which took effect on August 4, 2023.

The Good Neighbor Plan establishes 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

In August 2023, the EPA published a proposed approval of the Wyoming SIP, finding that the EPA’s updated modeling demonstrated that Wyoming’s determination that no additional controls are required to address interstate transport for the 2015 zone NAAQSs was reasonable.

In December 2023, the EPA finalized the approval of the Wyoming SIP, removing it from the federal implementation plan.

The Wyoming SIP does not have additional requirements for the Jim Bridger facility under the Good Neighbor Plan.

In July 2023, the Ninth Circuit Court of Appeals issued a stay halting application of the Good Neighbor Plan in Nevada pending a hearing on the merits of an appeal challenging the EPA's disapproval of Nevada's SIP.

In light of the court's ruling, in September 2023, the EPA issued an interim final rule indefinitely suspending the implementation of the Good Neighbor Plan in Nevada.

Regional Haze / Good Neighbor Plan:

In June 2023, the EPA published the final rule under the CAA called the Federal "Good Neighbor Plan" for the 2015 Ozone National Ambient Air Quality Standards (Good Neighbor Plan), which took effect on August 4, 2023.

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

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 the purchase of allowances in order to utilize the full available output, at the North Valmy plant during the EPA defined ozone season (May through September).

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

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

Definition of “Waters of the United States” Under the CWA :

The definition of "waters of the United States" is fundamental to the application of the CWA because only those bodies of water designated as WOTUS are protected from unlawful discharge of pollutants under the CWA.

In May 2023, the U.S.

Supreme Court issued a decision defining WOTUS under the CWA and providing nationwide clarity of the federal government’s jurisdiction over WOTUS.

The decision restricts the federal government's ability to regulate wetlands that do not have a continuous surface connection with a navigable water.

While not addressed in the opinion, ephemeral streams and other water bodies that are not relatively permanent would also not be jurisdictional under the May 2023 decision.

The new definition of WOTUS from the Supreme Court should not alter how the CWA applies to most of Idaho Power's facilities, including its hydropower plants.

As a result, Idaho Power does not expect the new definition to materially impact Idaho Power's operations or financial condition.

Section 401 Water Quality Certification:

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The states issued final certifications in May 2019.

In September 2023, Idaho Power filed a water quality certification application with Idaho for the American Falls facility, that is pending with the IDEQ.

In July 2020, the EPA published a rule amending regulations intended to implement the CWA Section 401 water quality certification process.

The rule has been subject to various legal challenges.

In September 2023, the EPA finalized a new Section 401 Water Quality Certification Rule and repealed the 2020 rule.

The EPA’s new rule expands state and tribal authority over water quality certifications;

however, such expanded authority will not likely impact the timing and cost of the HCC certification under the current approval process.

Idaho Power is still evaluating the impact the new rule will have on the American Falls application.

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

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

CWA Permitting:

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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 twelve of the dams and anticipates completing all submissions by June 2024.

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 which have not been present in the Snake River system historically.

Quagga mussel infestations can foul up irrigation, hydropower, and water delivery facilities and increase the costs to maintain such facilities.

In September 2023, a larval form of quagga mussels and one adult quagga mussel were detected in the mid-Snake River near Twin Falls in Idaho Power's service area by the Idaho State Department of Agriculture (ISDA).

As a result, in October 2023, ISDA treated approximately six miles of the Snake River, which includes Idaho Power's Twin Falls and Shoshone Falls hydropower facilities, using a copper-based, EPA-approved treatment called Natrix to eradicate quagga mussels.

Initial ISDA sample results indicated that the treatment impacted larvae and adult quagga mussel populations.

However, it is premature to conclude complete eradication at this stage.

The ISDA will resume sampling in spring 2024 once water temperatures warm.

The ISDA expects to implement ongoing surveying to determine the success of treatment.

If the treatment was unsuccessful, and a quagga mussel infestation occurs, it may result in increased other O&M expenses for mitigation efforts and other adverse impacts for Idaho Power's operation of its hydropower facilities in any infested areas.

As of the date of this report, Idaho Power cannot predict the extent to which the Natrix treatment will be successful in eradicating quagga mussels from the Snake River, the extent of the treatment’s impact to the river and its inhabitants, or the potential increase in other O&M expenses related to quagga mussel mitigation efforts.

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

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Idaho Power must satisfy three conditions to apply regulatory accounting:

(1) an independent regulator must set rates;

independent regulator must set rates;

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

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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 2024 defined benefit plan pension expense decreased to 5.10 percent from the 5.45 percent rate used in 2023.

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.

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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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

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.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis