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Item 7. Management’s Discussion and Analysis

2024-02-15 compared with 2023-02-16 · 478 added, 650 removed, 575 unchanged (66% of the section changed)

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AND RESULTS OF OPERATIONS

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed.

In MD&A in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed.

The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 2022 compared with 2021 can be found in their Annual Report on Form 10-K for the year ended December 31, 2022.

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IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA".

Idaho Power is an electric utility whose rates and other matters are regulated by the Idaho Public Utilities Commission (IPUC), Public Utility Commission of Oregon (OPUC), and Federal Energy Regulatory Commission (FERC).

Idaho Power is an electric utility whose rates and other matters are regulated by the IPUC, OPUC, and FERC.

Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity.

Idaho Power is the parent of Idaho Energy Resources Co.

(IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger power plant (Jim Bridger plant) owned in part by Idaho Power.

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 Public Utility Regulatory Policies Act of 1978 (PURPA).

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

EXECUTIVE OVERVIEW

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

• IDACORP achieved net income growth for a fifteenth consecutive year;

• IDACORP increased its quarterly common stock dividend to $0.79 per share from $0.75 per share, as a part of a 163 percent increase in quarterly dividends approved over the last eleven years;

• Idaho Power's customer count grew 2.4 percent in 2022;

• In 2022, Idaho Power sold 15,822 megawatt-hours (MWh) of power to retail customers, the highest in its history;

• Idaho Power set a new winter system peak demand of 2,574 megawatts (MW) on December 19, 2022, and agai n on December 22, 2022, with 2,604 MW of demand, exceeding the previous winter high of 2,527 MW set on January 6, 2017;

• Amid unprecedented retail customer usage and demand in 2022, Idaho Power’s reliability metrics were among the best in company history and Idaho Power provided uninterrupted service to its retail customers 99.97 percent of the time;

• In 2022, Idaho Power ranked 6th highest in customer satisfaction among 92 investor-owned utilities, as rated by an independent third party customer satisfaction study;

• As part of its “Clean Today.

Cleaner Tomorrow.®” goal and in alignment with its 2021 IRP, Idaho Power obtained regulatory approval to accelerate depreciation for its co-owned Jim Bridger plant, reflecting Idaho Power’s plan to exit all coal-fired generation by 2028;

• To reliably serve growing customer demand, Idaho Power has undertaken a substantial capital program for new capacity and energy resources, and in 2022 began constructing two sizeable utility-scale battery storage facilities while conducting requests for proposals (RFPs) for additional resources.

• 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.

• 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 2023, Idaho Power’s reliability metrics continued to be among the best in company history, as Idaho Power provided uninterrupted service to its retail customers 99.97 percent of the time.

• 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.

Summary of 2023 Financial Results

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Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms (31.3)

Idaho fixed cost adjustment (FCA) revenues (12.7)

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)

Other operations and maintenance (O&M) expenses (38.1)

Other O&M expenses (0.5)

Depreciation expense (25.3)

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IDACORP's net income increased $2.2 million for 2023 compared with 2022, due primarily to higher net income at Idaho Power.

Idaho Power's customer growth of 2.4 percent added $12.1 million to Idaho Power's operating income compared with 2021.

Higher sales volumes on a per-customer basis increased operating income by $8.8 million in 2022 compared with 2021, as higher sales volumes on a per customer basis for residential, commercial, and industrial customers were partially offset by lower sales volumes on a per customer basis for irrigation customers.

Warmer summer weather in Idaho Power's service area during the third quarter of 2022 and colder winter weather during the first and fourth quarters of 2022, compared with the same periods of 2021, led customers to use more energy per customer for cooling and heating.

Greater precipitation during the spring of 2022, compared with the spring of 2021, reduced usage per irrigation customer for irrigation pumping by 9 percent in 2022 compared with 2021.

The positive revenue impact of the increase in sales volumes per residential and small commercial customer was partially offset by the FCA mechanism, which decreased revenues in 2022 by $12.7 million compared with 2021.

Idaho Power's customer growth of 2.4 percent added $15.7 million to Idaho Power's operating income in 2023 compared with 2022.

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.

This was due partially to changes in Idaho Power's customer sales mix, which includes separate rate tariffs based on customer class.

To a greater extent, the net increase in retail revenues per MWh was 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).

Idaho Power plans to cease participation in all coal-related operations at the Jim Bridger plant by 2028.

Power expects the Bridger Order to increase operating revenues, net depreciation expense, and income tax expense in future periods and estimates the impacts of the Bridger Order will increase net income by approximately $10 million in 2023.

From 2023, Idaho Power expects the ongoing annual benefit to net income from the Bridger Order to decline each year through 2030, primarily due to the annual decline in Jim Bridger plant coal-related rate base, which Idaho Power expects to be fully depreciated by December 31, 2030.

For more information on the Bridger Order, see "Regulatory Matters" in this MD&A.

During 2022, transmission wheeling-related revenues increased $12.5 million compared with 2021.

Weather variations between the southwest United States and the Pacific Northwest and energy price volatility in the western United States led to price spreads between energy market hubs.

The price spreads in 2022 increased wheeling activity across Idaho Power's transmission system for wheeling customers to access these markets.

Also, Idaho Power's OATT rates increased 4 percent in October 2021 and 1 percent in October 2022, and Idaho Power saw a significant increase in transmission line-loss settlement rates and associated revenues in the fourth quarter of 2022 compared with the fourth quarter of 2021.

In addition, two new long-term wheeling agreements executed in April 2021 contributed to increased wheeling volumes during the first three months of 2022 compared with the same period in 2021.

Other O&M expenses increased $38.1 million in 2022 compared with 2021, due partially to inflationary pressures on labor-related costs, professional services, and supplies.

Also, maintenance activities at the Jim Bridger plant, Langley Gulch natural gas plant, Bennett Mountain natural gas plant, and American Falls hydropower project contributed to the increase in other O&M expenses in 2022 compared with 2021.

Most of those maintenance activities are performed as scheduled maintenance, but not annually.

Depreciation expense decreased $5.4 million, due primarily to the impact of the Bridger Order, which resulted in Idaho Power recording the deferral of certain depreciation expense in the second quarter of 2022.

This decrease was partially offset by higher utility plant in service in 2022, compared with 2021.

Other changes in operating revenues and expenses, net, decreased operating income by $14.8 million in 2022 compared with 2021, due primarily to the increase in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms.

Higher wholesale natural gas and power market prices in the western United States and higher energy usage by Idaho Power customers, combined with below-average generation from Idaho Power's hydroelectric facilities, increased Idaho Power's net power supply expenses in 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.

Allowance for funds used during construction (AFUDC) increased as the average construction work in progress balance was higher throughout 2022 compared with 2021.

Also, interest income increased due to higher market interest rates, and investment income increased related to life insurance claims in the rabbi trust for Idaho Power's nonqualified defined benefit pension plans, in 2022 compared with 2021.

In addition, costs recorded in 2021 related to an Idaho Power postretirement medical plan did not recur in 2022, as expected.

These items were partially offset by higher interest expense on long-term debt in 2022 compared with 2021.

The $1.7 million increase in Idaho Power income tax expense in 2022 compared with 2021 was primarily due to greater 2022 pre-tax income.

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:

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

IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy.

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.

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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:

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.

• Rate Base Growth and Infrastructure Investment:

The rates established by the IPUC, OPUC, and FERC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred income taxes and other items.

Over time, rate base is increased by additions to utility plant in service and reduced by depreciation of utility plant and write-offs as authorized by the IPUC and OPUC.

Idaho Power is pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and provide service to new customers, including major ongoing transmission projects such as the 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.

Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding, but the company incurs the cash requirements of constructing and the costs of financing those resources before they are in rates and customer revenues.

Idaho Power expects its capital expenditures on infrastructure investments in the next five years or more will be considerable as it works to address projected energy and capacity deficits.

For more information about forecasted capital expenditures and expected rate base growth, see the "Liquidity and Capital Resources" section of this MD&A.

• Economic Conditions and Loads:

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In 2023, Idaho Power's customer count grew by 2.4 percent.

Reflective of that recent customer growth, Idaho Power sold 15,822 MWh of power to retail customers in 2022, the highest in its history, and Idaho Power reached a new winter system peak power demand of 2,604 MW on December 22, 2022.

While current inflationary and volatile economic conditions could slow the rate of residential 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.

In 2022, Idaho Power began preparing its 2023 IRP, its 20-year forecast of power demand and supply options.

As of the date of this report, the preliminary load forecast assumptions Idaho Power expects to use in the 2023 IRP are included in the table below.

The 2023 preliminary IRP assumptions include significant large commercial and industrial additions in the 5-year forecasted annual growth rate, including potential load from new facilities recently announced by Meta Platforms, Inc.

and Micron Technology, Inc.

For comparison purposes, the analogous average annual growth rates used in the prior two IRPs are included.

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)

2023 IRP (preliminary) 5.5% 3.7% 2.2% 1.8%

2021 IRP 2.6% 2.1% 1.4% 1.4%

2019 IRP 1.3% 1.4% 1.0% 1.2%

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 and energy resources contemplated by the resource procurements described in the "Rate Base Growth and Infrastructure Investment" section below in this MD&A.

In order to meet growth in its service area, Idaho Power relies on numerous vendors to provide goods and services.

Economic conditions in 2021 and 2022 have resulted in supply chain constraints and inflationary cost increases.

Those inflationary pressures have impacted not only external costs, but also Idaho Power's internal labor costs.

Inflationary pressures on both external costs and internal labor costs were notable components of the increases in other O&M expenses in 2022 compared with 2021.

Idaho Power also experienced significant increases in fuel costs during 2022, reflective of the economic environment.

Idaho Power has taken measures to help ensure the availability of supply chain-constrained items that are needed to serve new and existing customers, such as ordering distribution transformers and other electrical apparatus in advance and from new suppliers.

Idaho Power has also taken measures to help mitigate where possible cost increases through supplier diversity and contract negotiation, as it works to meet the demands of continued customer and load growth amid an uncertain national and global economic environment.

Idaho Power also has an energy risk management and hedging process designed to mitigate some, but not all, of the price risk associated with volatile and elevated power supply and fuel costs.

• Rate Base Growth and Infrastructure Investment:

Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, retirement, and write-off of utility plant.

Idaho Power is pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity and capacity, and provide service to new customers.

These infrastructure projects include major ongoing new transmission projects such as the Boardman-to-Hemingway and Gateway West projects, as well as utility-scale battery storage projects and other resource procurements.

Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydropower generation resource.

Idaho Power intends to pursue timely

inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding.

As noted previously, Idaho Power believes that 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 and storage resources to meet energy and capacity needs over the next several years.

While demand varies and is based on numerous factors, based on Idaho Power's analysis of its load and current resource balance, Idaho Power believes it will have resource capacity deficits for peak needs in each of the years from 2023 through 2027.

Idaho Power spent $52 million in 2022 on new resource procurements, and expects to spend more than $600 million from 2023 through 2027 on resource additions to address projected energy and capacity deficits.

For more information about forecasted capital expenditures and expected rate base growth, see the "Liquidity and Capital Resources" section of this MD&A.

• Regulation of Rates and Cost Recovery;

General Rate Case Filing:

The prices that Idaho Power is authorized to charge for its electric and transmission service is 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 timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and prudent management of expenses and investments.

Idaho Power has a regulatory settlement stipulation in Idaho that includes provisions for the accelerated amortization of accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.4 percent Idaho-jurisdiction return on year-end equity (Idaho ROE).

The settlement stipulation also provides for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE, which would adjust to the authorized return on equity determined in the next general rate case.

The settlement stipulation has no expiration date but the minimum Idaho ROE would revert back to 95 percent of the authorized return on equity determined in the next Idaho general rate case.

The specific terms of the settlement stipulation are described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

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 believes it is likely that it will file a general rate case in Idaho during 2023, as early as June 2023, with a general rate case filing in Oregon likely to follow in 2024.

However, several factors impact Idaho Power’s timing and need to file general rate cases.

As it looks to a potential 2023 general rate case, Idaho Power is assessing the expected increase in depreciation expense from rate-base eligible assets as they are placed into service (including its battery storage projects that it expects to be in-service in 2023), the significant amounts of capital expenditures Idaho Power has made since its last general rate case filed in 2011, the expected financing costs for capital expenditures in a higher interest-rate environment, and, to a lesser extent, the inflationary pressures on other O&M expenses described above.

In Idaho, Idaho Power is required to file a notice of its intent to file a general rate case with the IPUC at least 60 days before filing an application for a general rate case, and Idaho Power expects the processing of a general rate case in Idaho would span at least seven months before new rates would be in effect.

In Oregon, Idaho Power expects that processing of a general rate case would take approximately ten months.

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.

• 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.

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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Further, as Idaho Power's hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources.

When hydropower generation decreases, Idaho Power must rely on more expensive generation sources and purchased power.

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

wholesale energy sales.

When hydropower generation decreases, Idaho Power must rely on more expensive generation resources and purchased power.

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

For 2023, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 7.5 million MWh, compared with average total annual hydropower generation of approximately 7.7 million MWh over the last 30 years.

For 2024, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 7.5 million MWh, compared with 6.5 million MWh in 2023 and average total annual hydropower generation of approximately 7.6 million MWh over the last 30 years.

• Mitigation of Impact of Fuel and Purchased Power Expense:

In addition to hydropower generation, Idaho Power relies significantly on natural gas and coal to fuel its generation facilities and on 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 power purchase agreements (including PURPA agreements), and power purchases in the wholesale markets.

Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs.

Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, generation resource maintenance outages, and wholesale energy market prices.

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

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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 Valmy, Nevada (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 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.

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

In June 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.

The IPUC's Bridger Order related to Idaho Power's plan to cease participation in coal-related operations at the Jim Bridger plant by 2028 is described more fully in the "Regulatory Matters" section of this MD&A.

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.

• Water Management and Relicensing of Hydropower Projects:

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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.

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.

• Wildfire Mitigation Efforts:

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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.

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

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

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

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incorporating current and forecasted weather and field conditions into operational practices;

public safety power shutoff protocols adopted in 2022;

PSPS protocols;

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

In June 2021,

the IPUC authorized Idaho Power to defer, for future amortization, the Idaho jurisdictional share of actual incremental O&M expenses and depreciation expense of certain capital investments necessary to implement the WMP.

The WMP cases with the IPUC are described in more detail in the "Regulatory Matters" section of this MD&A.

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.

RESULTS OF OPERATIONS

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In this analysis, the results for 2023 are compared with 2022.

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

Year Ended December 31,

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

Retail energy sales 15,515 15,822

Wholesale energy sales 840 427

Energy sales bundled with renewable energy credits 892 739

Energy sales bundled with RECs 1,255 892

Total energy sales 17,610 17,141

Hydropower generation 6,548 5,347

Coal generation 3,657 2,981

Natural gas and other generation 2,319 2,765

Coal-fired generation 2,473 3,657

Natural gas-fired and other generation 2,917 2,319

Total system generation 11,938 11,323

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Total energy supply 17,610 17,141

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

Year Ended December 31,

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

2023 2022 Normal (2)

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Sales Volume and Generation:

In 2022, retail sales volumes increased 3 percent compared with the prior year, primarily due to

growth in the number of Idaho Power customers and increased usage per customer in all customer classes, except for irrigation customers.

Warmer summer weather in Idaho Power's service area during the third quarter of 2022 and colder winter weather during the first and fourth quarters of 2022, compared with the same periods in 2021, caused customers to use more energy for cooling and heating.

Greater precipitation in Idaho Power's service area during the spring of 2022, compared with the spring of 2021, reduced usage per irrigation customer for irrigation pumping by 9 percent in 2022 compared with 2021.

The number of Idaho Power customers grew by 2.4 percent in 2022.

Wholesale energy sales volumes decreased 29 percent during 2022 compared with 2021, as higher retail sales volumes and lower than average available hydroelectric generation from Idaho Power resources led to less energy being available for opportunistic market sales.

Total system generation increased 2 percent in 2022 compared with 2021, due primarily to higher coal-fired generation, partially offset by decreased natural gas generation.

Natural gas generation decreased 16 percent due primarily to higher natural gas market prices.

This decrease in natural gas generation during 2022 led to a significant increase in coal generation to help reliably meet customer demand.

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.

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.

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

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

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Retail Revenues :

The table below presents Idaho Power’s retail revenues (in thousands), MWh sales (in thousands), and number of customers for the last two years.

Year Ended December 31,

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

Retail revenues:

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Irrigation 173,929 170,964

Provision for sharing — (569)

Deferred revenue related to HCC relicensing AFUDC (2)

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Total retail revenues $ 1,472,666 $ 1,372,758

Volume of Sales (MWh)

Residential 6,056 5,645

Commercial 4,306 4,164

Industrial 3,510 3,471

Irrigation 1,950 2,126

Total retail MWh sales 15,822 15,406

Number of retail customers at year-end

(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.

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.

MWh Sales Retail Customers

2023 2022 2023 2022

Residential 5,903 6,056 531,885 518,490

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Irrigation 1,805 1,950 22,333 22,071

Total customers 617,995 603,753

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

Total 15,515 15,822 632,936 617,995

Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period.

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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.

Also, changes in Idaho Power's customer sales mix, which includes separate rate tariffs based on customer class, contributed to the increase in retail revenues.

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.

The adjustments related to the Idaho-jurisdiction power cost adjustment mechanism (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.

The adjustments related to the Idaho-jurisdiction PCA in rates do not have a significant effect on operating income as a corresponding amount is recorded in expense in the same period it is collected through rates.

• Customers :

Customer growth of 2.4 percent increased retail revenues by $26.7 million in 2023 compared with 2022.

Higher usage (on a per customer basis) in all customer classes except irrigation customers, increased retail revenues by $18.3 million during 2022 compared with 2021.

Warmer summer weather in Idaho Power's service area during the third quarter of 2022 and colder winter weather during the first and fourth quarters of 2022, compared with the same periods of 2021, led retail customers to use more energy per customer for cooling and heating.

Higher precipitation during the spring of 2022, compared with the spring of 2021, led agricultural irrigation customers to use 9 percent less energy per customer to operate irrigation pumps during 2022.

Heating degree-days in Boise, Idaho, were 19 percent higher during 2022 compared with 2021, and 9 percent higher than normal.

Also, cooling degree-days in Boise, Idaho, were 1 percent higher during 2022 compared with 2021 and 34 percent above normal.

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.

Higher usage (on a per customer basis) by residential and small commercial customers during 2022 decreased the amount of FCA revenue accrued by $12.7 million, compared with 2021.

Idaho Power did not record any provision for sharing in 2022.

In 2021, Idaho Power recorded a $0.6 million provision against current revenues to be refunded to customers through an approved rate reduction which was included in PCA rates in June 2022.

This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is described in "Regulatory Matters" in this MD&A and Note 3 -"Regulatory Matters" to the consolidated financial statements included in this report.

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.

Wholesale Energy Sales :

Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the energy imbalance market in the western United States, and do not include derivative transactions.

The table below presents Idaho Power’s wholesale energy sales for the last two years (in thousands, except for revenue per MWh amounts).

Year Ended December 31,

Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the western EIM, and do not include derivative transactions.

The table below presents Idaho Power’s wholesale energy sales for the last two years ended December 31 (in thousands, except for revenue per MWh amounts).

Wholesale energy revenues $ 63,421 $ 66,519

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Wholesale energy revenues per MWh $ 75.50 $ 155.78

In 2022, wholesale energy revenue increased by $25.7 million, or 63 percent, compared with 2021, as higher average wholesale energy prices more than offset a decrease in volumes sold.

Wholesale energy prices were higher compared with 2021 as extreme summer and winter weather resulted in higher demand and higher fuel costs (natural gas and coal) in the wholesale markets in the region.

Wholesale energy sales volumes decreased 29 percent in 2022 compared with 2021, as higher retail sales volumes led to less energy available for opportunistic market sales.

The earnings 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.

Transmission Wheeling-Related Revenues:

Revenue related to transmission wheeling increased $12.5 million, or 18 percent, in 2022 compared with 2021, as weather-related price spreads between electricity market hubs increased wheeling activity across Idaho Power's transmission system during 2022, compared with 2021.

Also, Idaho Power saw a significant increase in transmission line-loss settlement rates and associated revenues in the fourth quarter of 2022 compared with the fourth quarter of 2021.

In addition, two new long-term wheeling agreements executed in April 2021 contributed to increased wheeling volumes during the first three months of 2022 compared with the same period in 2021.

Idaho Power's OATT rates increased approximately 4 percent during the period from October 1, 2021 to September 30, 2022, as compared with the rates in effect from October 1, 2020 to September 30, 2021.

Also, Idaho Power's OATT rate increased 1 percent in October 2022.

Refer to "Regulatory Matters" in this MD&A for more information on Idaho Power's OATT rate.

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.

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

Energy Efficiency Program Revenues:

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A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected.

At December 31, 2022, Idaho Power's energy efficiency rider balances were a $3.8 million regulatory asset in the Idaho jurisdiction and a $0.2 million regulatory liability in the Oregon jurisdiction.

At December 31, 2023, Idaho Power's energy efficiency rider balances were a $0.7 million regulatory liability in the Idaho jurisdiction and a $0.8 million regulatory liability in the Oregon jurisdiction.

Operating Expenses

Purchased Power :

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

Year Ended December 31,

PURPA contracts $ 189,367 $ 199,517

Other purchased power (including wheeling) 354,978 194,174

Total purchased power expense $ 544,345 $ 393,691

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

Purchased power expense $ 501,531 $ 544,345

MWh purchased 7,027 7,178

PURPA contracts 2,756 3,040

Other purchased power 4,422 3,783

Total MWh purchased 7,178 6,823

Cost per MWh from PURPA contracts $ 68.71 $ 65.63

Cost per MWh from other sources $ 80.28 $ 51.33

Weighted average - all sources

$ 75.84 $ 57.70

Idaho Power is required by federal law to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices.

The intermittent, non-dispatchable nature of most PURPA generation increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydropower or its fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a significant loss.

Although it was not the case in 2022 or 2021, the other purchased power cost per MWh often exceeds the wholesale energy sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods than during light load periods, and conversely has less energy available for wholesale energy sales during heavy load periods than light load periods.

Market energy prices are typically higher during heavy load periods than during light load periods.

Also, in accordance with Idaho Power's energy risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery.

The regional energy market price is dynamic and additional energy transactions that Idaho Power makes at current market prices may be noticeably different than the advance transaction prices.

Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.

Purchased power expense increased $150.7 million, or 38 percent, in 2022 compared with 2021.

The increase in purchased power expense in 2022 is primarily due to higher wholesale energy market prices as extreme summer and winter weather resulted in higher demand and higher fuel costs (natural gas and coal) in the wholesale markets in the region.

Average cost per MWh $ 71.37 $ 75.84

Purchased power expense decreased $42.8 million, or 8 percent, in 2023 compared with 2022.

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.

For further information on purchased power activities, see Part I, Item 1 – Utility Operations – "Power Supply – Purchased Power."

Fuel Expense :

The table below presents Idaho Power’s fuel expenses and thermal generation for the last two years (in thousands, except per MWh amounts).

Year Ended December 31,

Coal $ 105,552 $ 95,324

Natural gas (1)

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

Fuel Expense MWh Generated Cost per MWh

2023 2022 2023 2022 2023 2022

Total fuel expense $ 230,210 $ 180,550

MWh generated

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

Natural gas (1)

Total MWh generated 5,976 5,746

Cost per MWh - Coal $ 28.86 $ 31.98

Cost per MWh - Natural gas $ 53.76 $ 30.82

Weighted average, all sources $ 38.52 $ 31.42

179,906 124,658 2,917 2,319 $ 61.68 $ 53.76

Total/Weighted average, all $ 275,405 $ 230,210 5,390 5,976 $ 51.10 $ 38.52

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

The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint venture of IERCo.

The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned investment of IERCo.

The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels.

BCC supplies up to two-thirds of the coal used by the Jim Bridger plant.

BCC supplies the majority of the coal used by the Jim Bridger plant and BCC does not have significant sales to third parties.

Natural gas is mainly purchased on the regional wholesale spot market at published index prices.

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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 $49.7 million, or 28 percent, in 2022 compared with 2021, primarily due to higher natural gas market prices in 2022, which resulted in a 74 percent increase in the average cost per MWh of natural gas generation.

Also, coal-fired generation increased to compensate for the significant decrease in natural gas generation resulting from higher natural gas market prices.

Idaho Power's increase in coal generation in 2022 has resulted in the company using a significant portion of its share of coal inventory at its jointly-owned coal plants.

Due to existing coal supply constraints, Idaho Power is currently optimizing dispatch of coal generation resources in an effort to help ensure adequate coal supply during its period of peak demand in 2023.

Given the coal supply constraints, Idaho Power may need to rely on more purchased power and natural gas-fired generation in those periods, depending in part on hydroelectric generating conditions in those 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.

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 2022 and 2021, gains on financial gas hedges of $68.5 million and $12.1 million, respectively, reduced natural gas fuel expense.

Most of these realized hedging gains are passed on to customers through the power cost adjustment mechanisms described below.

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.

Most of these realized hedging losses and gains are passed on to customers through the power cost adjustment mechanisms described below.

Power Cost Adjustment Mechanisms :

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

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

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

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

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

Year Ended December 31,

Power supply cost deferral $ (116,994) $ (22,036)

Oregon power supply cost deferral (1,079) —

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

Idaho power supply cost deferral $ (66,728) $ (116,994)

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

Amortization of prior year authorized balances 72,444 17,414

Total power cost adjustment expense $ (100,659) $ (49,844)

Total power cost adjustment (income statement) $ 6,885 $ (100,659)

The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms.

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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 2022, higher purchased power costs led to higher actual power supply costs compared with the forecasted amount, which resulted in a significant increase in the amount of power supply costs deferred by the mechanism.

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.

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 $38.1 million, or 11 percent, in 2022 compared with 2021, due partially to inflationary pressures on labor-related costs, professional services, and supplies.

Most of those maintenance activities are performed as scheduled maintenance, but not annually.

IDACORP's and Idaho Power's 2022 income tax expense increased $0.9 million and $1.7 million, respectively, when compared with 2021.

The increases were primarily due to higher pre-tax earnings at Idaho Power.

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.

IDACORP's and Idaho Power's 2023 income tax expense decreased $10.5 million and $11.0 million, respectively, when compared with 2022.

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

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.

On August 16, 2022, the Inflation Reduction Act of 2022 (the 2022 IRA) was signed into law.

The 2022 IRA provides for, among other things, numerous renewable energy tax credits, for example:

extension of the current investment (ITC) and production (PTC) tax credits, a new ITC for standalone energy storage, application of the PTC to solar, transition to a technology-neutral ITC and PTC after 2024, and created a transferability option that allows credits to be sold to an unrelated taxpayer.

The 2022 IRA modifies the calculation of most of the energy tax credits by introducing the concept of a “base credit” (e.g., 6 percent ITC) and a “bonus credit” (e.g., an additional 24 percent ITC) if certain wage and apprenticeship requirements are met in the construction and ongoing maintenance of the renewable energy facilities.

Additionally, the 2022 IRA also established a 15 percent alternative minimum tax for C-corporations with an average financial statement income of more than $1 billion for the previous three taxable years.

IDACORP and Idaho Power are not subject to the alternative minimum tax .

LIQUIDITY AND CAPITAL RESOURCES

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Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $4.4 billion over the period from 2024 through 2028.

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

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

As of February 9, 2024, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

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

• IDACORP's shelf registration statement filed with the U.S.

Securities and Exchange Commission (SEC) on May 16, 2022, which may be used for the issuance of debt securities and common stock;

• 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;

• 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;

$1.15 billion remains available for issuance pursuant to state regulatory authority;

$280 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 and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs.

• 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.

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.

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.

As described in the "Financing Cash Flows" section below, during 2022 Idaho Power issued first mortgage bonds, including a portion of the first mortgage bonds on a delayed-draw basis to be issued in March 2023, drew from a term loan facility, and redeemed pollution control revenue bonds.

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 with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing credit facilities, and access to commercial paper and short-term and long-term debt markets.

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.

IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent equity.

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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 2022 were $351 million and $380 million, respectively, a decrease of $12 million for IDACORP and an increase of $58 million for Idaho Power, when compared with 2021.

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.

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 $14 million and a $12 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 energy efficiency program cost mechanisms, decreased operating cash inflows by $46 million;

• changes in deferred taxes and taxes accrued and receivable combined to decrease operating cash flows for IDACORP by $11 million and increase operating cash flows for Idaho Power by $9 million;

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

◦ timing of collections of accounts receivable and unbilled revenues decreased operating cash flows by $72 million for IDACORP and $73 million for Idaho Power;

• 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:

◦ the timing of collections of accounts receivable and unbilled revenues increased operating cash flows by $64 million for IDACORP and $63 million for Idaho Power;

◦ the changes in materials, supplies, and fuel stock decreased operating cash flows by $42 million for IDACORP and Idaho Power, which was primarily due to an increase in material and supply inventory offset by the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants;

◦ the changes in accounts and wages payable increased operating cash flows by $95 million for IDACORP and $149 million for Idaho Power, which was primarily due to an in increase power supply costs and associated timing of payments, and includes a $54 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, increased operating cash flows by $27 million for IDACORP and Idaho Power.

◦ 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.

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction of, and improvements to, Idaho Power’s generation, transmission, and distribution facilities.

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 2022 and 2021 were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements.

Significant items and transactions that affected investing cash flows in 2022 and 2021 were as follows:

• IDACORP’s and Idaho Power’s investing cash outflows for 2022 and 2021 included $433 million and $300 million, respectively, of additions to utility plant;

• IDACORP's and Idaho Power's investing cash inflows for 2022 and 2021 included $18 million and $6 million, respectively, from Boardman-to-Hemingway project joint permitting participants relating to a portion of the permitting expenditures;

• IDACORP's investing cash outflows for 2022 and 2021 included $10 million and $15 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;

• IDACORP's investing cash outflows and inflows for 2022 and 2021 included $25 million in purchases of short-term investments and $25 million and $50 million, respectively, in sales of short-term investments;

• IDACORP's and Idaho Power's investing cash inflows for 2022 and 2021 included an $8 million and $14 million, respectively, return of investment from IERCo, a wholly-owned subsidiary of Idaho Power;

• IDACORP's and Idaho Power's investing cash outflows and inflows for 2022 included $44 million and $31 million in purchases of equity and held-to-maturity securities, respectively, and $64 million in sales of equity securities, held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's security plan for senior management employees.

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.

Significant items and transactions that affected investing cash flows in 2023 and 2022 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;

• $3 million and $10 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.

Financing Cash Flows

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IDACORP's and Idaho Power's net financing cash inflows for 2023 were $473 million and $538 million, respectively.

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, a term loan facility, 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 2022, Idaho Power drew $150 million from a term loan facility;

• in December 2022, Idaho Power issued $23 million in principal amount of its 4.99 percent first mortgage bonds, secured medium term notes, Series N, maturing in December 2032;

• in December 2022, Idaho Power issued $25 million in principal amount of its 5.06 percent first mortgage bonds, secured medium term notes, Series N, maturing in December 2042;

• in December 2022, Idaho Power redeemed, prior to maturity, $4.4 million in principal amount of variable rate pollution control revenue bonds, Series 2000, maturing in February 2027.

The bonds were redeemed prior to maturity due to demolition of the Boardman power plant in October 2022;

• 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.

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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 could determine to issue equity during 2023, depending on market conditions, its financial and regulatory strategy, and other factors.

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.

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 2024.

Term Loan Credit Agreement:

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

The Term Loan Facility is a two-year senior unsecured term loan facility in the aggregate principal amount of $150 million, used for general corporate purposes, including funding Idaho Power's capital projects.

The maturity date of the Term Loan Facility is March 4, 2024.

At December 31, 2022, $150 million in principal amount had been drawn and was outstanding on the Term Loan Facility.

For more information about the Term Loan Facility, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.

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 Wyoming Public Service Commission (WPSC).

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.

For more detailed information about Idaho Power First Mortgage Bonds, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.

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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 Idaho Power has a commitment to issue the third and fourth tranches on March 8, 2023, each under the Indenture .

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

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.

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IDACORP and Idaho Power Credit Facilities (Credit Facilities) :

The IDACORP Credit Facility, which may be used for general corporate purposes and commercial paper backup, 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 principle amount at any time outstanding not to exceed $50 million.

The Idaho Power Credit Facility, which may be used for general corporate purpose and commercial paper backup, consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principle amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million.

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.

The IDACORP Credit Facility, which may be used for general corporate purposes, consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million.

The Idaho Power Credit Facility, which may be used for general corporate purposes, consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $400 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $50 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million.

IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $600 million, respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power Credit Facilities have similar terms and 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 perc ent, or one-month SOFR rate plus 1.1 percent, or 0.0 percent, or (2) the Secured Overnight Financing Rate administered by the Federal Reserve Bank of New York (SOFR) Market Index rate, plus, in each case, an applicable margin, provided that

the federal funds rate and SOFR rate will not be less than zero.

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.

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

The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by rating agencies, as set forth on a schedule to the credit agreements.

Under their respective Credit Facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities.

On December 6, 2025, the extension of $15.6 million and $46.9 million on the IDACORP and Idaho Power Credit Facilities, respectively, terminates.

The extension of the remaining $84.4 million of the IDACORP Credit Facility and the remaining $253.1 million of the Idaho Power Credit Facility, respectively, terminates on December 7, 2026.

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.

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 occurrence of specified events or the incurring of specified liabilities relating to benefit plans;

and the incurring of certain environmental liabilities, subject, in certain instances, to cure periods.

and the occurrence of certain events related to the environment, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable.

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However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.

Without additional approval from the IPUC, the OPUC, and the WPSC, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.

Idaho Power has obtained approval of the state public utility commissions of Idaho, Oregon, and Wyoming for the issuance of short-term borrowings with maturities of three years and under through December 2026.

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

IDACORP and Idaho Power Commercial Paper:

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(2) Holding company only.

IDACORP and Idaho Power had no short term commercial paper outstanding during the years ended December 31, 2022 and 2021.

At February 10, 2023, IDACORP had no loans outstanding under the IDACORP Credit Facility and no commercial paper outstanding, and Idaho Power had no loans outstanding under the Idaho Power Credit Facility and had $60.0 million of commercial paper outstanding with a weighted average interest rate of 4.97 percent.

Idaho Power issued the commercial paper to provide additional liquidity for Idaho Power to meet obligations related to the purchase of natural gas and wholesale power and hedging activities.

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).

Idaho Power IDACORP (1)

Commercial Paper:

Amount outstanding $ — $ — $ — $ —

Weighted average interest rate — % — % — % — %

Daily average amount outstanding during the period $ — $ 9,201 $ — $ —

Weighted average interest rate during the period — % 4.94 % — % — %

Maximum month-end balance $ — $ 110,000 $ — $ —

(1) Holding company only.

Impact of Credit Ratings on Liquidity and Collateral Obligations

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

The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody’s Investors Service (Moody's) and Standard & Poor’s Ratings Services as of the date of this report:

IDACORP Idaho Power

Moody's Investors Service:

Rating Outlook Stable Stable

Long-Term Issuer Rating Baa2 Baa1

The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody's and Standard & Poor’s Ratings Services as of the date of this report:

Moody's Standard & Poor's

IDACORP Idaho Power IDACORP Idaho Power

Rating Outlook Stable Stable Stable Stable

Issuer Rating/Corporate Baa2 Baa1 BBB BBB

First Mortgage Bonds None A2

Senior Secured Debt None A2

Commercial Paper P-2 P-2

Standard & Poor's Rating Services:

Corporate Credit Rating BBB BBB

Rating Outlook Stable Stable

Short-Term Rating A-2 A-2

Senior Secured Debt None A-

Senior Secured Debt None A2 None A-

Commercial Paper/Short-Term P-2 P-2 A-2 A-2

These security ratings reflect the views of the ratings agencies.

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Such ratings are not a recommendation to buy, sell, or hold securities.

In July 2022, Moody's Long-Term Issuer rating for IDACORP was downgraded to Baa2 from Baa1, and Idaho Power's Long-Term Issuer rating was downgraded to Baa1 from A3.

In addition, Moody's ratings for Idaho Power's First Mortgage Bonds and Senior Secured Debt were downgraded to A2 from A1.

IDACORP and IPC's short-term ratings for commercial paper were affirmed at Prime-2 and the outlook for both companies were rated as stable.

Following the Moody's credit ratings changes, the companies’ credit ratings remain investment grade and the companies do not believe the ratings changes will have a material impact on their liquidity nor access to debt capital.

Moody’s credit ratings of Baa3 and above are considered to be investment grade, or prime, ratings.

Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties.

As of December 31, 2022, Idaho Power had no performance assurance collateral posted.

Should Idaho Power experience a reduction in its credit rating on its unsecured debt to

below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions.

Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2022, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $113.3 million.

To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

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

Capital Requirements

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

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

The capital expenditure table below assumes, among other projects, construction and ownership of a number of capacity resources identified in Idaho Power's RFPs, 2021 IRP, and preliminary 2023 IRP modeling in order to safely and reliably serve the company's customers.

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

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

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Resource Additions to Address Projected Energy and Capacity Deficits :

As noted previously, Idaho Power believes that existing and sustained growth in customers, load, and peak demand for electricity, along with transmission constraints, will create the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs over the next several years.

While demand varies and is affected by numerous factors, based on Idaho Power's analysis of its load and current resource balance, Idaho Power believes it will have resource capacity deficits for peak needs in each of the years from 2023 through at least 2027.

To help meet peak needs in 2023 and 2024, Idaho Power entered into contracts to purchase, own, and operate 180 MW of battery storage assets with expected useful lives of approximately 20 years, and also entered into two 20-year power purchase agreements for the combined 140 MW output of planned third-party solar facilities.

To help address the additional capacity deficits projected for 2025 through 2027, Idaho Power has initiated or issued RFPs for additional resources.

The capital requirements table above includes capital expenditures of more than $600 million from 2023 through 2027 for resource additions to address projected energy and capacity deficits in those years.

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

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

Idaho Power has a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to pursue permitting of the project.

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

In January 2022, the participants executed a non-binding term sheet regarding the ownership structure that would be addressed through amended or new funding agreements for the future phases of the project.

The term sheet contemplates that Idaho Power would acquire BPA's ownership interest, which would increase Idaho Power's interest to approximately 45 percent, and Idaho Power would provide transmission service to BPA's customers across Southern Idaho.

In January 2023, BPA issued a Letter to Region to announce that the participants have concluded negotiations on final agreements to transfer ownership interest and began its public process to provide regional stakeholders with more information about the contracts and an opportunity to comment prior to a final decision.

After the outreach period and BPA's final decision, BPA, PacifiCorp, and Idaho Power plan to finalize the agreements by mid-2023.

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.

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

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

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

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

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

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

Pursuant to the terms of the joint funding arrangements, Idaho Power has received $99 million in reimbursement as of December 31, 2022, from project co-participants for their share of costs.

As of the date of this report, no material co-participant reimbursements are outstanding.

Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures or agreed upon early construction expenditures incurred by Idaho Power under the terms of the joint funding agreement.

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

Pursuant to the terms of the joint funding arrangements, Idaho Power has received $124 million in reimbursement as of December 31, 2023, from project co-participants for their share of costs (including $31 million related to BPA's share, which was transferred to Idaho Power in March 2023 as part of the agreement described above) and continues to receive reimbursement as costs are incurred.

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

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

The agreement became fully effective in September 2023.

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

Federal agency records of decision have been received and all lawsuits challenging the federal rights-of-way have been resolved.

In the separate State of Oregon permitting process, the state's Energy Facility Siting Council (EFSC) approved Idaho Power's site certificate on September 27, 2022.

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

Three limited parties filed appeals to the Oregon Supreme Court asking that court to overturn EFSC's approval of the Boardman-to-Hemingway site certificate.

Idaho Power expects a decision from the Oregon Supreme Court in June 2023.

In the separate State of Oregon permitting process, the state's Energy Facility Siting Council (EFSC) approved Idaho Power's site certificate in September 2022.

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

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

Total cost estimates for the project are between $1.5 billion and $1.7 billion, including Idaho Power's AFUDC.

The capital requirements table above includes approximately $550 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining permitting phase, design, material procurement, and construction phases of the project.

The preliminary estimates of construction costs could change as the construction timeline nears and as the project participants obtain more detailed information on construction and material costs.

In July 2021, Idaho Power awarded contracts for detailed design, geotechnical investigation, land surveying, and right-of-way option acquisition;

and that work commenced in the third quarter of 2021.

In April 2022, Idaho Power awarded a contract for constructability consulting services.

Idaho Power's 2021 IRP, which has been acknowledged by the IPUC and OPUC, included the Boardman-to-Hemingway transmission line in its resource capacity plans for 2026.

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

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 :

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Idaho Power has expended approximately $60 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2023.

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 $300 million and $500 million, including AFUDC.

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

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

The capital requirements table above includes approximately $425 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.

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

Bureau of Land Management (BLM).

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 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 their portion of the project in Wyoming.

Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.

In late 2020, PacifiCorp completed construction and commissioned a 140-mile segment 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.

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.

Hells Canyon Complex Relicensing :

The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 36 percent of its total generating nameplate capacity.

Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC.

Idaho Power has been engaged in the process of obtaining a new long-term license for the HCC from the FERC.

The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant.

Costs for the relicensing of Idaho Power's hydropower projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service.

Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through the regulatory process.

Relicensing costs of $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.

As of December 31, 2023, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $229 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 is likely in 2024 or thereafter.

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.

Idaho Power intends to seek recovery of those relicensing and compliance costs in rates through the regulatory process.

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.

Environmental Regulation Costs:

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

Idaho Power's 2021 IRP identified a preferred resource portfolio and action plan, which included the addition of a 120-MW solar resource in late 2022, the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant unit 2 in 2025, the completion of the Boardman-to-Hemingway transmission line in 2026, and an end to Idaho Power's participation in the remaining two coal-fired units at the Jim Bridger plant by the end of 2028.

The 2021 IRP preferred resource portfolio and action plan also includes a need to acquire significant generation and storage resources to meet energy and capacity needs.

Including the resources noted above, over the next 20 years the 2021 IRP plans for the addition of 1,685 MW of storage capacity, 1,405 MW of solar capacity, 700 MW of wind capacity, 500 MW of transmission capacity, and 400 MW of capacity from demand response.

As noted in the 2021 IRP, there is uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of coal-fired plant conversions and retirements.

These uncertainties, as well as others, may result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions in the 2021 IRP.

In November 2022, and January 2023, respectively, the IPUC and OPUC issued orders acknowledging Idaho Power's 2021 IRP.

In preparing its 2023 IRP, Idaho Power intends to analyze the potential acceleration of the timing of construction of the Gateway West transmission project and the potential conversion of additional coal-fired generation units to natural gas.

Idaho Power expects to complete and file its 2023 IRP with the IPUC and OPUC in June 2023.

Additional information on Idaho Power's 2021 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.

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

Idaho Power contributed $40 million to its defined benefit pension plan in each of 2022 and 2021.

Idaho Power contributed $48 million in 2023 and $40 million in 2022 to its defined benefit pension plan.

Idaho Power estimates that it has no minimum required contribution to be made during 2024.

Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $30 million to the pension plan during 2024.

Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to

mitigate the cost of being in an underfunded position.

Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position.

Beyond 2024, Idaho Power expects continuing contributions under the pension plan could be significant.

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

The IPUC has authorized Idaho Power to recover and amortize $17 million of deferred pension costs annually, and has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011.

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

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

The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions.

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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.

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.

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Off-Balance Sheet Arrangements

Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest.

This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $48.2 million at December 31, 2022, representing IERCo's one-third share of BCC's total reclamation obligation of $144.7 million.

BCC has a reclamation trust fund set aside and specifically for the purpose of paying these reclamation costs.

At December 31, 2022, the value of the reclamation trust fund totaled $196.1 million.

During 2022, the reclamation trust fund made $3.9 million of distributions for reclamation activity costs associated with the BCC surface mine.

BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs.

To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant.

Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

IDACORP’s and Idaho Power’s off-balance sheet arrangements as of December 31, 2023, include guarantees of Idaho Power's portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest.

See Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to off-balance sheet arrangements.

REGULATORY MATTERS

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Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities.

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

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

Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability, among other items.

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

Idaho Power's most recent general rate cases in Idaho and Oregon were filed during 2011, and in 2012, large single-issue rate cases for the Langley Gulch power plant resulted in the resetting of base rates in both Idaho and Oregon.

Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014 but without a resulting net increase in rates.

The IPUC and OPUC have also approved base rate changes in single-issue cases subsequent to 2014.

Between general rate cases, Idaho Power relies upon customer growth, a FCA mechanism, power cost adjustment mechanisms, wildfire mitigation plan 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.

Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms.

With Idaho Power’s anticipated significant infrastructure investments, including those that are intended to help meet projected near-term capacity deficits, Idaho Power believes it is likely that it will file a general rate case in Idaho during 2023, as early as June 2023, with a general rate case filing in Oregon likely to follow in 2024.

Several factors impact Idaho Power’s timing and need to file general rate cases, including the expected increase in costs associated with rate-base eligible assets as they are placed into service in the future, increased costs associated with the capital expenditures Idaho Power has made since its last general rate case filed in 2011, the expected financing costs for capital expenditures in a higher interest-rate environment, and inflationary pressures on other O&M expenses described above.

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.

Notable Retail Rate Changes in Idaho and Oregon

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Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanisms and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A.

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)

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2023 Idaho FCA 6/1/2023 (10)

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

2022 Idaho PCA 6/1/2022 95

2022 Idaho FCA 6/1/2022 (3)

Idaho Boardman plant closure 1/1/2021 (4)

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.

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Idaho and Oregon General Rate Cases

Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from the regulatory settlement of a general rate case filing Idaho Power made in 2011.

In the general rate case, the IPUC approved a settlement stipulation that provided for an overall 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion.

The settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues.

Neither the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity.

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.

Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant.

In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the plant in rates.

The order also provided for a $335.9 million increase in Idaho rate base.

In September 2012, the OPUC issued an order approving a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates.

Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulch power plant revenue requirement variances, effective November 1, 2020, through October 31, 2024.

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.

For more information on the 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.

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.

Other Notable Regulatory Matters

May 2018 Idaho Tax Reform Settlement Stipulation:

In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations.

In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.

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

Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers.

The May 2018 Idaho Tax Reform Settlement Stipulation provides for the extension of a prior 2014 settlement stipulation beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism that became effective January 1, 2020, with no defined end date.

The May 2018 Idaho Tax Reform Settlement Stipulation does not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho

during its term and includes provisions for the accelerated amortization of ADITC to help achieve a minimum 9.4 percent (9.5 percent prior to 2020) Idaho ROE.

In addition, under the May 2018 Idaho Tax Reform Settlement Stipulation, minimum Idaho ROE would revert back to 95 percent of the authorized return on equity in the next general rate case.

IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the May 2018 Idaho Tax Reform Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect.

In 2022, Idaho Power recorded no provision against current revenue for sharing with customers, as its full-year Idaho ROE was between 9.4 percent and 10.0 percent.

Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers in 2021, as its full-year ROE exceeded 10.0 percent.

At December 31, 2022, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.

Idaho Power recorded the following amounts for sharing with customers under the May 2018 Idaho Tax Reform Settlement Stipulation and its predecessor stipulations (in millions):

Year Recorded as Refunds to Customers Recorded as a Pre-tax Charge to Pension Expense Total

2022 $ — $ — $ —

2021 0.6 — 0.6

2011 - 2019 58.1 68.1 126.2

Total $ 58.7 $ 68.1 $ 126.8

For more information on the provisions of the 2018 Idaho Tax Reform Settlement Stipulations and its impacts on results, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Valmy Base Rate Adjustment Settlement Stipulations:

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.

Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and plans to cease coal-fired operations at unit 2 in 2025.

Both commissions have approved this plan.

The IPUC-approved settlement stipulation provides for (1) accelerated depreciation for the North Valmy plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2028, (2) Idaho Power to use prudent and commercially reasonable efforts to end its participation in coal-fired operations at North Valmy as described above, (3) a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the North Valmy plant, and (4) increased customer rates related to the associated incremental annual levelized revenue requirement.

If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

In Oregon, the OPUC has also approved settlement stipulations that provide for the accelerated cost recovery of unit 1 through 2019 and unit 2 through 2025.

The net rate impact of the Oregon settlement stipulations is immaterial.

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 approving, with modifications, Idaho Power’s amended application requesting authorization to (1) accelerate depreciation for the Jim Bridger plant, to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (2) establish a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Order).The Bridger Order and associated accounting are described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.

As a result of the Bridger Order, Idaho Power recorded the deferral of certain depreciation expense in 2022.

Idaho Power plans to cease participation in all coal-related operations at the Jim Bridger plant by 2028.

Idaho Power expects the Bridger Order to increase operating revenues, net depreciation expense, and income tax expense in future periods, and estimates the impacts of the order will increase after-tax net income by approximately $10 million in 2023.

Idaho Power expects the ongoing annual benefit to net income from the Bridger Order to decline each year through 2030, primarily due to the annual decline in Jim Bridger plant coal-related rate base, which Idaho Power expects to be fully depreciated by December 31, 2030.

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:

In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental O&M and depreciation expense of certain capital investments necessary to implement the company's WMP.

The IPUC also authorized Idaho Power to record these deferred expenses as a regulatory asset until the company can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review actual costs and

determine the amount of prudently incurred costs that Idaho Power can recover through retail rates.

In its 2021 application with the IPUC, Idaho Power projected spending approximately $47 million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening incremental capital expenditures over a five year period.

The IPUC authorized a deferral period of five years, or until rates go into effect after Idaho Power's next general rate case, whichever is first.

As of December 31, 2022, Idaho Power’s deferral of Idaho-jurisdiction costs related to the WMP was $27.1 million.

During the 2021 and 2022 wildfire seasons, Idaho Power identified needs for expanded mitigation measures by gaining additional insights and knowledge on wildfires and wildfire mitigation activities.

In October 2022, Idaho Power filed an updated WMP with the IPUC along with an application requesting authorization to defer an estimated $16 million of newly identified incremental costs expected to be incurred between 2022 and 2025 associated with expanded wildfire mitigation efforts.

As of the date of this report, the application with the IPUC is pending.

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 kilowatt-hour (kWh) charge and linking it instead to a set amount per customer.

In May 2021, the IPUC ordered Idaho Power to work with interested parties and initiate a case to review the FCA mechanism and propose modifications it determines are appropriate.

In December 2021, the IPUC approved Idaho Power's proposed modifications to the FCA mechanism to institute separate, and reduced, fixed cost tracking for customers added to Idaho Power's system after December 31, 2021.

These modifications did not have a material impact on Idaho Power's operating revenues or consolidated financial statements.

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 December 2021 and expects to file its next IRP during 2023, as described in Part 1, Item 1 - "Resource Planning and Renewable Energy Projects" in this report.

The 2021 IRP, which was acknowledged by the IPUC in November 2022 and by the OPUC in January 2023, identified the need for resources to meet projected capacity deficits in the near-term.

In December 2021, Idaho Power filed an application with the OPUC requesting a waiver of Oregon's competitive bidding rules for Idaho Power's procurement of resources to fill near-term capacity deficits.

Specifically, Idaho Power requested that the OPUC issue an order waiving Idaho Power’s obligation to comply with the competitive bidding rules for its proposed resource procurement in favor of a modified competitive process and authorizing Idaho Power to move forward expeditiously with resource procurement to meet identified resource needs in 2023, 2024, and 2025.

In March 2022, the OPUC issued an order denying Idaho Power's request to waive t he competitive bidding rules.

However, as allowed by the OPUC in certain cases, Idaho Power is pursuing an exception for 2023 resource needs, and plans to pursue additional exceptions to the competitive bidding rules for certain projects to meet the identified resource needs in 2024 and 2025.

In September 2022, in accordance with the OPUC's competitive bidding rules, Idaho Power filed an application requesting the OPUC open a docket for approval of a solicitation process and appoint an independent evaluator to oversee the process for Idaho Power to procure resources to meet identified potential energy and capacity needs in 2026 and 2027.

In December 2022, the OPUC issued an order appointing an independent evaluator.

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:

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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.

In May 2018, the IPUC issued an order authorizing the creation of two new customer classes for residential and small commercial customers who install their own on-site generation, with no change to pricing or compensation.

Idaho Power has initiated several cases with the IPUC related to studying the costs and benefits of customer-owned generation on Idaho Power’s system, and exploring potential modifications to the customer-owned generation pricing structure.

The IPUC issued orders in December 2019 and February 2020 directing Idaho Power to (1) complete additional studies related to the costs and benefits of customer generation before changes to the compensation structure are implemented, and (2) 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.

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 2021, Idaho Power filed an application requesting that the IPUC initiate the multi-phase process for a comprehensive study of the costs and benefits of on-site generation as directed by previous IPUC orders.

In December 2021, the IPUC issued

an order requiring Idaho Power to complete the comprehensive study on the costs and benefits of on-site generation based on the IPUC’s study framework findings and conclusions.

In June 2022, Idaho Power filed the comprehensive study and in December 2022, the IPUC issued an order that acknowledged the company's study and directed Idaho Power to file a new case requesting to implement changes to the structure and design of its on-site generation program.

Filings for Certificates of Public Convenience and Necessity

In April 2022, Idaho Power filed an application with the IPUC requesting that the IPUC issue a Certificate of Public Convenience and Necessity (CPCN) authorizing Idaho Power to install, own, and operate two battery storage facilities.

The 120 MW combined capacity of the two projects is planned to help meet peak energy needs in the summer of 2023 and beyond.

The CPCN was intended to allow the IPUC to review the need for the project prior to Idaho Power incurring the bulk of the associated expenses.

In December 2022, the IPUC issued an order:

(1) granting Idaho Power's request for a CPCN;

(2) requiring that Idaho Power change the battery storage account depreciation rate to 5 percent and reflect all available investment tax credits for the battery storage projects;

and (3) absent additional evidence of the prudence of expenditures in a subsequent recovery case, limiting recovery of costs to approximately $50 million and $100 million, respectively, for the 40 MW and 80 MW battery storage projects.

In September 2022 and January 2023, respectively, Idaho Power filed petitions with the OPUC and the IPUC requesting that the OPUC and the IPUC issue CPCNs authorizing Idaho Power to construct the 300-mile Boardman-to-Hemingway high-voltage transmission line.

Oregon law requires utilities proposing to construct transmission lines to petition the OPUC for a CPCN if a transmission line will necessitate condemnation of land or an interest in land.

As of the date of this report, the OPUC and IPUC decisions in these matters are pending.

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.

Large Customer Rate Proceedings

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 has received approximately 2,000 MW of potential customer interest from this industry and 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.

In October 2022, after a third party requested reconsideration of the matter, the IPUC affirmed its June 2022 order establishing the new customer class and ordered Idaho Power to file an application by December 31, 2022, to determine the amount of compensation, if any, that is fair, just, and reasonable under the interruptability provision of the new speculative high-density load customer class.

In December 2022, Idaho Power filed an application to either establish the interruption compensation for Schedule 20 or defer implementation of any compensation structure for the mandatory interruption requirement of Schedule 20 until evaluation of cost assignment is completed at a general rate case.

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

Clean Energy Your Way Program :

In December 2021, Idaho Power filed an application with the IPUC requesting to expand optional customer clean energy offerings through its new Clean Energy Your Way Program.

Specifically, Idaho Power is seeking authority to:

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 renewable energy credits (REC);

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

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

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

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

Brisbie, LLC (Brisbie) Data Center :

In December 2021, Idaho Power filed an application with the IPUC for approval of a special contract for electric service for a new large load customer, Brisbie, LLC (Brisbie), for a new 960,000 square-foot enterprise data center.

Brisbie is a wholly-owned subsidiary of Meta Platforms, Inc.

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

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 proposed special contract, Idaho Power would procure enough renewable resources to provide Brisbie with 100 percent renewable energy on an annual basis for Brisbie’s facility.

In its application, Idaho Power requested authority to procure the necessary resources contemplated within its agreement with Brisbie without seeking IPUC approval for each such procurement and requested assurance from the IPUC that each such resource procurement would receive

the same ratemaking treatment outlined in the case, unless otherwise modified in a subsequent proceeding.

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

In November 2022, Idaho Power filed an application with the IPUC requesting approval for an arrangement under which Brisbie would purchase from Idaho Power energy 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.

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

The application is modeled after the Clean Energy Your Way program described above.

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

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 March 2022, Idaho Power filed an application with the IPUC requesting approval of a revised special contract for electric service between Idaho Power and an existing industrial customer, Micron Technology (Micron).

The application included an arrangement under which Micron would be the purchaser from Idaho Power of the 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.

The solar facility is scheduled to begin operating as early as June 2023.

Idaho Power also requested in the application 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.

The application is modeled after Clean Energy Your Way program described above.

In August 2022, the IPUC issued an order approving Idaho Power’s application, with modifications.

In December 2022, Idaho Power made a compliance filing requesting approval of Idaho Power's proposed payment structure for Micron's renewable capacity credit.

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

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.

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 :

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.

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.

Deferred Net Power Supply Costs

Deferred (accrued) power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs.

Deferred (accrued) power supply costs are recorded on the balance sheets for future recovery (refund) through customer rates.

Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions 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.

Deferred (accrued) power supply costs are recorded on the balance sheets for future recovery or refund through customer rates.

Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers.

The power cost adjustment mechanisms and

associated financial impacts are described in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Factors that have influenced power cost adjustment rate changes in recent years include year-to-year volatility in hydropower generation conditions, market energy prices and the volume of wholesale energy sales, power purchase costs from renewable energy projects, income tax reform, and revenue sharing under Idaho regulatory settlement stipulations.

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Balance at December 31, 2022

Current period net power supply costs deferred 117.0 1.0 118.0

Prior amounts refunded through rates (17.6) 0.2 (17.4)

SO 2 allowance and REC sales

$ 128.7 $ 0.6 $ 129.3

Current period net power supply costs deferred/(accrued) 66.7 (1.2) 65.5

Prior amounts collected through rates (72.2) (0.2) (72.4)

REC sales (13.2) (0.6) (13.8)

Interest and other 5.6 0.1 5.7

Balance at December 31, 2023

$ 115.6 $ (1.3) $ 114.3

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 August 2022, Idaho Power filed its 2022 final transmission rate with the FERC, reflecting a transmission rate of $31.42 per "kW-year," to be effective for the period from October 1, 2022, to September 30, 2023.

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

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's final rate was based on a net annual transmission revenue requirement of $135.7 million.

The OATT rate in effect from October 1, 2021 to September 30, 2022, was $31.19 per kW-year based on a

net annual transmission revenue requirement of $127.3 mi llion.

The increase in the OATT rate is largely attributable to increased transmission plant in service.

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.

Relicensing of Hydropower Projects

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The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report.

Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through the regulatory process.

In April 2018, the IPUC approved a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third-party intervenor and determined that $216.5 million in expenditures incurred for relicensing through December 31, 2015, were reasonably and prudently incurred, and therefore should be eligible for inclusion in customer rates at a later date.

Relicensing costs o f $423.1 million (i ncluding 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, 2022.

As of the date of this report, the IPUC authorizes 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.

As of December 31, 2022, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $207.5 million.

In addition to the discussion below, refer to "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydropower generating plants.

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.

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.

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 National Marine Fisheries Service (NMFS) and U.S.

Fish and Wildlife Service (USFWS), entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA)-listed species pending the relicensing of the project.

The FERC staff issued a final environmental impact statement (EIS) in August 2007 which should aid the FERC in determining whether, and under what conditions, to issue a new license for the project.

The final EIS informs the FERC, federal and state agencies, Native American tribes, and the public about the environmental effects of Idaho Power's operation of the HCC.

Certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act (CWA) and formal consultations under the ESA.

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 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.

In January 2017, the FERC issued an order denying Idaho Power’s petition, stating that the petition for a declaratory order was premature, cannot realistically be considered separately from the issue of the states’ certification authority under the CWA Section 401, and raises issues that are beyond the FERC’s authority to decide.

In February 2017, Idaho Power sought rehearing before the FERC on the January 2017 order, which the FERC denied.

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

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.

The CWA Section 401 certifications were challenged by three third parties in Oregon state court, and the Oregon Department of Environmental Quality subsequently resolved all challenges.

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.

During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement, and its 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 that incorporated the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications and provided feedback on proposed modification of the 2007 final EIS for the HCC.

The July 2020 filing also contained an updated cost analysis of the HCC and a request for the FERC to issue a 50-year license and initiate a supplemental National Environmental Policy Act (NEPA) process at the FERC.

Idaho Power prepared draft biological assessments in consultation with the USFWS and the NMFS and filed those with the FERC in October 2020.

The draft biological assessments provide information to the USFWS and the NMFS that is necessary to issue their biological opinion as required under the ESA.

Since December 2020, Idaho Power has responded to sixteen additional information requests issued by the FERC staff to aid in the FERC analysis.

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.

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.

The FERC indicated that the supplemental EIS would address the new and revised measures proposed by the CWA 401 certification settlement, the conditions contained in the Oregon and Idaho water quality certificates, and the information provided in the draft biological assessments.

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

In the notice of intent, the FERC predicted that the draft supplemental EIS would be published in June 2023 and the final supplemental EIS in December 2023.

As of the date of this report, Idaho Power believes issuance of a new HCC license by the FERC will be in 2024 or thereafter.

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, are likely to range from $30 million to $40 million until issuance of the license.

Subsequent to the issuance of a new license, Idaho Power expects to incur increased annual operating and maintenance costs to comply with the requirements of any new license and would seek to recover those increased costs through regulatory proceedings.

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.

American Falls Relicensing:

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Bureau of Reclamation.

The FERC recognized Idaho Power’s pre-application document, including a proposed process plan and schedule, and recognized Idaho Power’s intent to file an application for a license.

In August 2022, Idaho Power filed a draft license application with the FERC and, following a public comment period, Idaho Power plans to file a final license application with the FERC in February 2023.

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.

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.

Renewable Energy Standards and Contracts

Renewable Portfolio Standards:

Many states have enacted legislation that would require electric utilities to obtain a specified percentage of their electricity from renewable sources.

These requirements are commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no State of Idaho RPS is in effect.

Idaho Power will be required to comply with either a five- or ten-percent RPS in Oregon beginning in 2025 (depending on loads at that time), and Idaho Power expects to meet either RPS requirement with RECs obtained from the purchase of energy from the Elkhorn Valley wind project.

Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared 95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA.

For the years ended December 31, 2022 and 2021, Idaho Power's REC sales totaled $7.8 million and $4.7 million, respectively.

Were Idaho Power to be subject to additional RPS legislation, it may cease in full or in part the sale of RECs it receives, seek to obtain RECs from additional projects, generate RECs from any REC-generating facilities it owns or may be required to construct in light of an RPS, or purchase RECs in the market.

Historically, Idaho Power has generally not received the RECs associated with PURPA projects.

However, an order issued by the IPUC in 2012 provides that Idaho Power will own a portion of the RECs generated by some PURPA projects.

The required purchase of additional RECs to meet RPS requirements would increase Idaho Power's costs, which Idaho Power expects would be wholly or largely passed on to customers through rates and the power cost adjustment mechanisms.

Renewable and Other Energy Contracts:

Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small hydropower, and geothermal.

The majority of these contracts are entered into as mandatory purchases under

As of December 31, 2022, Idaho Power had contracts to purchase energy from 129 on-line PURPA projects.

An additional four contracts are with on-line non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity and the Jackpot solar project with a 120-MW nameplate capacity.

Idaho Power also has contracts with PURPA and non-PURPA projects under development.

On January 20, 2023, Idaho Power executed an additional non-PURPA power purchase agreement with an additional solar facility with a planned nameplate capacity of 100 MW, expected to be online in 2024.

The following table sets forth, as of the date of this report, the resource type and nameplate capacity of Idaho Power's signed agreements for power purchases from PURPA and non-PURPA generating facilities.

These agreements have original contract terms ranging from one to 35 years.

Resource Type On-line megawatts (MW) Under Contract but not yet On-line (MW) Total Projects under Contract (MW)

Wind 627 — 627

Solar 316 74 390

Hydropower 150 1 151

Other 44 — 44

Total PURPA 1,137 75 1,212

Wind 101 — 101

Geothermal 35 — 35

Solar 120 340 460

Total non-PURPA 256 340 596

The projects not yet on-line include one PURPA-qualifying hydropower project that is currently scheduled to be on-line in 2023, two PURPA-qualifying solar projects scheduled to be on-line in 2023, and one PURPA-qualifying solar project scheduled to be on-line in 2024.

The three non-PURPA-qualifying projects not yet on-line are solar projects that are scheduled to be on-line, one per year, in 2023, 2024, and 2025.

In 2020, the FERC issued Order No.

872, which could affect how states determine PURPA project avoided cost rates for purchases of power generated from qualifying facilities (QF), which facilities are eligible for QF status, whether and when certain QFs can enter into purchase agreements with utilities, and how parties can contest the eligibility of a generation facility seeking QF status.

As of the date of this report, Idaho Power is unable to determine the impact of these potential changes on the company's future obligations for new PURPA power purchase contracts.

Further action by the state public utility commissions is required to implement many of the changes.

Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.

ENVIRONMENTAL MATTERS

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act (CAA), the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws.

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the CAA, the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws.

These laws are administered by a number of federal, state, and local agencies.

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• reduce the output from current generating facilities;

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

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

Current and future environmental laws and regulations could significantly increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices.

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

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

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

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

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

Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.

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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 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 plans to 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.

Endangered Species Act Matters

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Subsequent federal court decisions have in some cases undermined the effectiveness of those regulations and orders.

Given the continued uncertainty in the regulatory landscape, Idaho Power continues to operate under the ESA rules in effect prior to 2019.

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.

To date, efforts to protect these species have not significantly affected generation levels or operating costs at any of Idaho Power's hydropower facilities.

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.

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.

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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.

The BLM has indicated it anticipates issuing draft land use plan amendments and associated EISs in July 2023.

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.

Migratory Bird Treaty Act Matters:

In September 2021, the USFWS announced that it revoked the previous Presidential Administration's interpretation of the Migratory Bird Treaty Act (MBTA) and implemented a new rule that reinstates the long-standing USFWS interpretation of the MBTA prohibiting the incidental take of migratory birds.

The new rule was published in the Federal Register on October 4, 2021, and went into effect on December 3, 2021.

Concurrently, the USFWS published an advanced notice of proposed rulemaking to determine whether and under what circumstances it could authorize an incidental take.

Similar to the changes in the ESA regulations described above in this MD&A, these MBTA regulations could impact the timing and feasibility of the Gateway West and Boardman-to-Hemingway transmission projects and other infrastructure projects that may interfere with migratory birds in the vicinity of such projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay construction.

ESA Issues Related to Specific Projects:

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Idaho Power prepared draft biological assessments in consultation with the USFWS and the NMFS and filed those with the FERC in October 2020.

The draft biological assessments are intended to provide the necessary information to the USFWS and the NMFS to issue their biological opinion as required under the ESA.

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

The FERC indicated that the supplemental EIS will address the new and revised measures proposed by the Section 401 certification settlement, the conditions contained in the Oregon and Idaho water quality certificates, and the information provided in the draft biological assessments.

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 in 2024 after the FERC issues a final supplemental EIS, which is scheduled for December 2023 according to the FERC's notice of intent.

Gateway West and Boardman-to-Hemingway Transmission Projects and Other Infrastructure - Slickspot Peppergrass and Washington Ground Squirrel Designations :

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.

to increase the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation and potential mitigation.

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 is uncertain whether such increases will be significant.

The Washington ground squirrel inhabits various locations throughout two of the counties within the proposed routes for Boardman-to-Hemingway.

It is not listed under the federal ESA, but it is considered endangered under Oregon law and the Boardman-to-Hemingway project will need to avoid ground squirrel colonies during construction.

If colonies are found within the proposed site boundary during pre-construction surveys, re-siting the transmission would require additional permitting and would likely involve increased permitting costs and could further delay the in-service date of the project.

Lower Snake River Hydroelectric Projects :

In May 2016, the United States District Court for the District of Oregon issued an opinion finding that in the context of hydropower facilities owned and operated by the U.S.

Army Corps of Engineers (USACE) and located on the lower Snake River, National Oceanic and Atmospheric Administration's National Marine Fisheries Service (NOAA Fisheries) violated the ESA by using improper standards, failing to consider adequately the impact of climate change on habitat conditions, and placing undue reliance on unproven, future federal habitat conservation measures, particularly to the degree that the success of the measures could be undermined by climate change.

The court also found that other federal agencies violated the NEPA by failing to prepare a comprehensive EIS on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives.

The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could result in considerable increases in cost beyond the cost of additional analysis in the NEPA process.

In September 2016, federal agencies initiated an EIS to examine hydropower dams on the lower Snake River.

In September 2020, the federal agencies signed a record of decision on the EIS that will guide the operation of those dams and may expedite projects and reduce the number of actions subject to NEPA review.

None of Idaho Power’s hydropower facilities are included in the studies.

National Environmental Policy Act (NEPA) Matters

National Environmental Policy Act Matters

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

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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.

Also in April 2022, the current Presidential Administration announced that the CEQ will propose a second phase of changes to NEPA that are aimed at further climate change-related reform, which could cause similar cost and project delays.

In July 2023 the CEQ proposed a

second round 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.

Climate Change and the Regulation of Greenhouse Gas Emissions

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• 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 carbon dioxide (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.

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.

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 2021 IRP identifies a preferred resource portfolio and action plan that anticipates (1) ending Idaho Power's participation in coal-fired operations at the North Valmy plant unit 2 no later than the end of 2025;

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

and (3) ending Idaho Power's participation in the remaining two coal-fired units at the Jim Bridger plant by the end of 2028.

As discussed above in the "Regulatory Matters" section of this MD&A, as of the date of this report, discussions among the IPUC Staff, Idaho Power, and the co-owner regarding this potential conversion and the environmental regulations related to the Jim Bridger plant are ongoing.

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;

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

and (3) converting units 3 and 4 at the Jim Bridger plant from coal to natural gas in 2030.

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

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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 promulgated 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 January 2021, the U.S.

Court of Appeals for the District of Columbia Circuit vacated the EPA's repeal of the CPP and also vacated the ACE rule in its entirety, directing the EPA to create a new regulatory approach.

In February 2021, the EPA issued a memorandum notifying states that it will not require states to submit plans to the EPA under Section 111(d) of the CAA because the circuit court vacated the ACE rule without reinstating the CPP.

On June 30, 2022, the U.S.

Supreme Court vacated the circuit court's decision and remanded the case for further proceedings, finding that the EPA does not have authority to devise emissions caps based on the generation-shifting approach identified in the CPP.

Despite the status of the CAA 111(d) rulemaking, the EPA will continue to evaluate climate-related impacts of fossil fuel generation and, as of the date of this report, Idaho Power expects to continue with its planned retirements and other planned upgrades at generating facilities.

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.

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

State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative:

In August 2007, the Oregon legislature enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050.

Oregon legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was also enacted in March 2016, and requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030.

In 2007, Oregon enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050.

Oregon also established its Oregon Clean Electricity and Coal Transition Plan in 2016, which requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030.

Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states.

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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, a national, voluntary GHG emissions reporting system.

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

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, Oregon, Wyoming, and Nevada) are members of the

Climate Registry.

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

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 Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS), New Source Review / Prevention of Significant Deterioration Rules, and the Regional Haze Rule.

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.

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

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

States are then required to develop emissions reduction strategies through State Implementation Plans (SIPs), based on attainment of these ambient air quality standards.

Recent developments and pending actions related to certain of those items relevant to Idaho Power.

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

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.

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

In April 2022, the EPA issued a proposed rule under the CAA called the Federal Implementation Plan Addressing Regional Ozone Transport for the 2015 National Ambient Air Quality Standards (Good Neighbor Rule) to establish NO x emissions budgets requiring fossil fuel-fired power plants to participate in an allowance-based ozone season trading program beginning in 2023.

If the proposed Good Neighbor Rule were implemented, under certain conditions the company could have reduced ability to use the full available output at the North Valmy and Jim Bridger plants in order to comply with the Good Neighbor Rule limitations.

As of the date of this report, Idaho Power is evaluating the specific impacts to both plants and how the Good Neighbor Rule would impact its operations.

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.

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).

Clean Water Act Matters

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

Since 2015, the EPA and USACE have been struggling to define the scope of "waters of the United States" (WOTUS) under the CWA.

The WOTUS definition 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 December 2022, after multiple rulemakings involving various Presidential Administrations and federal court reviews of those rules, the EPA and USACE most recently issued a final rule revising and expanding the definition of WOTUS under the CWA which goes into effect on March 20, 2023.

Although Idaho Power expects the new rule may cause Idaho Power to incur additional permitting, regulatory requirements, and other associated costs, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the relatively arid climate of Idaho Power's service area.

Similarly, because the CWA applies to most of Idaho Power's facilities, including its hydropower plants, Idaho Power does not expect this new rule to materially impact Idaho Power's operations or financial condition.

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, and the EPA under the current Presidential

Administration has filed a notice of intent to repeal the July 2020 rule.

While the EPA finalizes a new certification rule, Idaho Power plans to continue to operate under the current CWA Section 401 regulations as described above.

The EPA’s new rule is expected to expand state and tribal authority over water quality certifications;

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

CWA Permitting:

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

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

Idaho Power has in the past, and expects in the future, to incur costs and expenses associated with those permitting and compliance obligations, but as of the date of this report, Idaho Power is unable to estimate with any reasonable certainty those costs and expenses.

Idaho Power also expects to incur additional expenses associated with the relicensing of its hydroelectric facilities, as discussed elsewhere in this report.

In June 2022, Idaho Power and the IDEQ entered into a consent judgment in the district courts for the third, fourth, fifth, and sixth judicial districts of the State of Idaho to resolve a National Pollutant Discharge Elimination System permitting issue related to 15 of Idaho Power’s hydropower projects that required Idaho Power to pay a $1.1 million fine, implement interim measures for compliance, and ultimately submit applications for new permits at each of the dams subject to the consent judgment.

As of the date of this report, Idaho Power has submitted new permit applications for 5 of the dams and anticipates completing all submissions by June 2024.

Due to a misinterpretation of law, the EPA cancelled water discharge permits in the mid-1990’s, and Idaho Power recently determined that those permits are applicable for operation of the dams.

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

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

Idaho Power has in the past, and expects in the future, to incur costs associated with those permitting and compliance obligations, but as of the date of this report, Idaho Power is unable to estimate with any reasonable certainty those costs.

Idaho Power also expects to incur additional costs associated with the relicensing of its hydropower facilities, as discussed elsewhere in this report.

In June 2022, Idaho Power and the IDEQ entered into a consent judgment in the Idaho state district courts to resolve a National Pollutant Discharge Elimination System permitting issue related to 15 of Idaho Power’s hydropower projects that required Idaho Power to pay a $1.1 million fine, implement interim measures for compliance, and ultimately submit applications for new permits at each of the dams subject to the consent judgment.

Due to a misinterpretation of law, the EPA cancelled water discharge permits in the mid-1990’s, which Idaho Power subsequently determined were applicable for operation of the dams.

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

As of the date of this report, Idaho Power has submitted new permit applications for twelve of the dams and anticipates completing all submissions by June 2024.

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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

When preparing financial statements in accordance with the accounting principles generally accepted in the United States of America (GAAP), IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosures.

When preparing financial statements in accordance with GAAP, IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosures.

These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control.

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IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities.

The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently.

Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.

Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes.

Deferred income taxes for other items are recorded for the temporary differences between the income tax and financial accounting treatment of such items.

Unless contrary to applicable income tax guidance, deferred income taxes are not recorded for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.

Refer to Note 1 - “Summary of Significant Accounting Policies” and Note 2 - “Income Taxes” to the consolidated financial statements included in this report for additional information relating to income taxes.

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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, 2023, with maturities matching the projected cash outflows of the plans.

Based on the results of this analysis, the discount rate used to calculate the 2023 defined benefit plan pension expense increased to 5.45 percent from the 3.05 percent rate used in 2022.

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.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes.

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At December 31, 2023, a total of $255 million of expense was deferred as a regulatory asset.

Idaho Power expects to defer approximately $3 million of expense in 2023.

Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $19 million in 2022 and 2021.

Idaho Power expects net amortization of the regulatory asset of approximately $19 million in 2024.

Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $18 million in 2023 and $19 million in 2022.

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

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's consolidated financial statements.

See Note 1 - “Summary of Significant Accounting Policies” to the consolidated financial statements included in this report for a summary of significant accounting policies.

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.

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