IDACORP INC (IDA) FY 2022 MD&A

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

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. The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 2021 compared with 2020 can be found in their Annual Report on Form 10-K for the year ended December 31, 2021. See Part II - Item 7 - MD&A in that report for further information on the companies' prior period results of operations. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part I - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report.

INTRODUCTION

IDACORP is a holding company whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the Idaho Public Utilities Commission (IPUC), Public Utility Commission of Oregon (OPUC), and Federal Energy Regulatory Commission (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. 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).

EXECUTIVE OVERVIEW

IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, since Idaho Power’s regulated electric utility operations are the primary driver of IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements, notable events, milestones, and recognitions during 2022 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 again 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; and

•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.

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Summary of 2022 Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2022, 2021, and 2020 (in thousands, except earnings per share amounts):

The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2022, from the year ended December 31, 2021 (items are in millions and are before tax unless otherwise noted):

IDACORP's net income increased $13.4 million for 2022 compared with 2021, 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.

The net increase in retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $24.4 million in 2022 compared with 2021. 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. Idaho

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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.

Non-operating expense, net, decreased $15.7 million in 2022 compared with 2021. 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.

2023 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. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to safely provide reliable, affordable, clean energy to its customers from diversified generation resources, including an increasingly clean portfolio of generation as Idaho Power works toward its “Clean Today. Cleaner Tomorrow®” goal of 100% clean energy by 2045. More specific information on IDACORP’s strategy is included in Item 1 – “Business,” in this report.

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

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

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•Economic Conditions and Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. In recent years, Idaho Power has seen significant growth in the number of customers in its service area. In 2022, 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. (Micron). For comparison purposes, the analogous average annual growth rates used in the prior two IRPs are included.

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: 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, 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

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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.

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

Further, as Idaho Power's hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydropower generation decreases, Idaho Power must rely on more expensive generation 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

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

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

•Regulatory and Environmental Compliance Costs; Coal Plant Retirements: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Moreover, environmental laws and regulations may increase the cost of constructing new facilities, may increase the cost of operating generation plants, may require that Idaho Power install additional pollution control devices at existing generating plants, may result in penalties for non-compliance, even where inadvertent, or may require that Idaho Power curtail or cease operating certain generation plants. Idaho Power expects to spend significant amounts on environmental compliance and controls for the foreseeable future. Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its 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. 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.

•Water Management and Relicensing of Hydropower Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal licenses for the HCC, its largest hydropower generation source, and for American Falls, its second largest hydropower generation source. Given the number of parties involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. 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: In recent years, the western United States has experienced an increasing trend in the degree of annual destruction from wildfires. A variety of factors have contributed to this trend including climate change, increased wildland-urban interfaces, historical land management practices, and overall wildland and forest health. While Idaho Power has not experienced to date the extent of catastrophic wildfires within its service area that have occurred in California and elsewhere in the western United States, Idaho Power is taking a proactive approach to wildfire threat in its service area and transmission corridors. 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's approach to achieve these objectives includes identifying areas subject to elevated risk; system hardening programs, vegetation management, and field personnel practices to mitigate wildfire risk; incorporating current and forecasted weather and field conditions into operational practices; public safety power shutoff protocols adopted in 2022; and evaluating the performance and effectiveness of the strategies identified in the WMP through metrics and monitoring. In June 2021,

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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.

RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings. In this analysis, the results for 2022 are compared with 2021.

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

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

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

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

Sales Volume and Generation: In 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.

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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.

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

Operating Revenues

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

(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.

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

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Retail Revenues: Retail revenues increased $120.4 million in 2022 compared with 2021. The primary factors affecting retail revenues during the period were the following:

•Rates: Customer rates, excluding collections of amounts related to the power cost adjustment mechanisms, increased retail revenues by $24.4 million in 2022 compared with 2021, 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 $70.3 million in 2022 compared with 2021. 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.

•Customers: Customer growth of 2.4 percent increased retail revenues by $19.5 million in 2022 compared with 2021.

•Usage: 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.

•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.

•Sharing: 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.

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).

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.

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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.

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

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).

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.

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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).

(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 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. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods.

Fuel expense 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.

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.

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

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

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

Income Taxes

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. 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

Overview

Idaho Power continues to pursue significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and component replacement. Cash capital expenditures, excluding AFUDC and net costs of removing assets from service, were $419 million in 2022 and $288 million in 2021. Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $3.3 billion over the period from 2023 through 2027.

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.

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As of February 10, 2023, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

•their respective $100 million and $300 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;

•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; and

•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. 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.

IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent equity. Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2022, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:

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

Operating Cash Flows

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

IDACORP’s and Idaho Power’s operating cash inflows in 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. 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 2022 when compared with 2021 were as follows:

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•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; and

•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;

◦the changes in materials, supplies, and fuel stock decreased operating cash flows by $13 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; and

◦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.

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. IDACORP's and Idaho Power's net investing cash outflows for 2022 were $424 million and $410 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; and

•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.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. IDACORP's and Idaho Power's net financing cash inflows for 2022 were $35 million and $78 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 2022 were as follows:

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•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; and

•IDACORP and Idaho Power paid dividends of $154 million and $114 million in 2022, respectively.

Financing Programs and Available Liquidity

IDACORP Equity Programs: IDACORP issued no equity securities in 2022 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.

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.

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

In December 2022, Idaho Power entered into a Bond Purchase Agreement with certain institutional purchasers, relating to the sale by the Idaho Power of $170 million in aggregate principal amount of first mortgage bonds, secured medium-term notes, Series N (Series N Notes). Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated December 20, 2022, to the Indenture (Fifty-second Supplemental Indenture). The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series N Notes pursuant to the Indenture. The Series N Notes consist of four tranches of bonds, due in 2032, 2042, 2043, and 2053, respectively. The first two tranches were issued on December 22, 2022, and 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. At December 31, 2022, $48 million in principal amount of Series N Notes had been issued and was outstanding. For more detailed information about the Series N Notes, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.

IDACORP and Idaho Power Credit Facilities (Credit Facilities): 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. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.

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

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

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2022, the leverage ratios for IDACORP and Idaho Power were 45 percent and 46 percent, respectively. IDACORP's and Idaho Power's ability to utilize their respective Credit Facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the Credit Facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2022, IDACORP and Idaho Power believe they were in compliance with all of their respective Credit Facility covenants and, as of the date of this report, do not believe they will be in violation or breach of such covenants during 2023.

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

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

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.

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

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Available Short-Term Borrowing Liquidity

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

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.

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:

These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. 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

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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.

Capital Requirements

Idaho Power's cash capital expenditures, excluding AFUDC, were $419 million during the year ended December 31, 2022. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2023 through 2027 (in millions of dollars). The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings. Given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and 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. The timing and amount of actual constructed projects and capital expenditures could be affected by Idaho Power’s ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, regulatory determinations, inflationary pressures, macroeconomic conditions, or other issues, including those described below.

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of relatively small projects as Idaho Power continues to add to its system to accommodate growth and maintain reliability and operational effectiveness. These projects involve significant capital expenditures in the aggregate. Examples of anticipated system enhancements planned for 2023 through 2027 and estimated costs include the following:

•$50-$150 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;

•$125-$170 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;

•$10-$50 million per year for ongoing improvements and replacements at thermal plants;

•$80-$130 million per year for hydropower plant improvement programs, including relicensing costs; and

•$50-$80 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.

Other Major Infrastructure Projects: Idaho Power has recently completed or is engaged in the development of a number of significant projects and has entered into arrangements with third parties for joint development of infrastructure projects. The most notable projects are described below.

Resource Additions to Address Projected Energy and Capacity Deficits: 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. 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

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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.

Idaho Power has spent approximately $154 million, including Idaho Power's AFUDC, on the Boardman-to-Hemingway project through December 31, 2022. 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. 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.

Total cost estimates for the project are between $1.1 billion and $1.3 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $430 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.

Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a high-voltage transmission lines project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho. In 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $52 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2022. 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. The capital requirements table above includes approximately $40 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.

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

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. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant. 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 $30 million to $40 million until issuance of the 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 compliance 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.

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

Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term, mid-term, and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in 2021. 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.

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 estimates that it has no minimum required contribution to be made during 2023. Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $40 million to the pension plan during 2023. 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

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mitigate the cost of being in an underfunded position. Beyond 2023, Idaho Power expects continuing contributions under the pension plan could be significant. Refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.

Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. At December 31, 2022 and 2021, Idaho Power's deferral balance associated with the Idaho jurisdiction was $250 million and $234 million, respectively. Deferred pension costs are amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. The IPUC has authorized Idaho Power to recover and amortize $17 million of deferred pension costs annually, and has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Contractual Obligations

IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2022, include long-term debt, interest payments, purchase obligations, pension and post-retirement benefit plans, and other long-term liabilities specific to IDACORP, most of which are discussed throughout this MD&A. Refer to Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to purchase obligations and other long-term liabilities.

Dividends

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

IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 60 percent and 70 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of directors' dividend decisions. Notwithstanding the dividend policy adopted by IDACORP's board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the factors above, among others. In September of 2022 and 2021, IDACORP's board of directors voted to increase the quarterly dividend to $0.79 per share and $0.75 per share of IDACORP common stock, respectively. IDACORP's dividends during 2022 were 59.5 percent of actual 2022 earnings.

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

Contingencies and Proceedings

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

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

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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.

REGULATORY MATTERS

Introduction

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

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

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Notable Retail Rate Changes in Idaho and Oregon

The table below presents notable rate changes during 2022 and 2021 that affected Idaho Power's results for the periods or that will likely affect future periods. Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanisms and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A.

Idaho and Oregon 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.

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

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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):

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: 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.

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.

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

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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.

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 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 the 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.

Customer-Owned Generation Filing: Customer-owned generation enables customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid. If a customer requires more energy than its system generates, it uses energy supplied by Idaho Power’s grid and infrastructure. If a customer's system generates more energy than the customer uses, the energy is transferred to the grid and Idaho Power applies a corresponding kWh credit to the customer’s bill. 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. 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

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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.

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: (1) rename its existing green power program; (2) maintain and expand procurement options for the renewable energy credits (REC); (3) establish a regulatory framework for a future voluntary subscription green power service program; (4) offer a tailored renewable option for Idaho Power's largest customers; and (5) procure the associated additional resources outside of the IPUC's current competitive procurement requirements. 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. 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

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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.

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.

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.

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

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

Open Access Transmission Tariff Rate

Idaho Power uses a formula rate for transmission service provided under its OATT, which 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. Idaho Power's final rate was based on a net annual transmission revenue requirement of $132.7 million. The OATT rate in effect from October 1, 2021 to September 30, 2022, was $31.19 per kW-year based on a

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net annual transmission revenue requirement of $127.3 million. The increase in the OATT rate is largely attributable to increased transmission plant in service.

Relicensing of Hydropower Projects

Overview: Idaho Power, like other utilities that operate non-federal hydropower projects on qualified waterways, obtains licenses for its hydropower projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. 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. 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 of $423.1 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, 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.

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. 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 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.

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.

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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.

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. 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, 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.

American Falls Relicensing: In April 2020, the FERC formally initiated the relicensing of the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a generating capacity of 92.3 MW. Idaho Power owns the generation facility but not the structural dam itself, which is owned by the U.S. 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. 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. 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

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PURPA. 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.

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

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the 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. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's two co-owned coal-fired power plants and three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydropower projects are also subject to a number of water discharge standards and other environmental requirements.

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Compliance with current and future environmental laws and regulations may:

•increase the operating costs of generating plants;

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

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

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

•reduce the output from current generating facilities; or

•require the acquisition of alternative sources of energy or storage technology, increased transmission wheeling, or require 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. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.

Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2023 to 2025. Given the uncertainty of future environmental regulations and technological advances, there is uncertainty around near-term estimates, and Idaho Power is also unable to predict its environmental-related expenditures beyond 2025, though they could be substantial. Furthermore, several executive orders issued since 2017 concerning environmental regulations, including executive orders issued by the current Presidential Administration to establish new federal environmental mandates, revoke several existing executive orders, and require agencies to review environmental regulations issued by the previous Presidential Administration, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. The outcome of federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or conversions, or reduction or elimination of permitting requirements. More strict or robust regulations, or additional regulations, on the other hand, would likely increase Idaho Power's costs of operating and maintaining its facilities, and could impact Idaho Power's plans and pre-construction activities related to its major transmission projects, which could lead to substantially higher construction and permitting costs and could delay construction. Executive orders may be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level. Therefore, as of the date of this report, and except as specifically described below in this MD&A, Idaho Power is uncertain whether and to what extent 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.

Endangered Species Act Matters

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

Over the past few years and as a result of changes in Presidential Administrations, regulatory developments and executive orders have called into question the existing requirements under the ESA. Subsequent federal court decisions have in some cases undermined the effectiveness of those regulations and orders. Given the continued uncertainty in the regulatory landscape, Idaho Power continues to operate under the ESA rules in effect prior to 2019.

There are a number of threatened or endangered species within Idaho Power's service area located in waterways in which Idaho Power has hydropower facilities, and within or near proposed transmission line routes. To date, efforts to protect these species have not significantly affected generation levels or operating costs at any of Idaho Power's hydropower facilities. However, the

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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.

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

In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. Following a series of interim measures, in February 2022, the BLM issued a notice of intent to amend its land use plans regarding sage grouse conservation and prepare associated EISs, soliciting public comments on the planning initiative. The BLM has indicated it anticipates issuing draft land use plan amendments and associated EISs in July 2023.

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:

Hells Canyon Relicensing Project: In December 2004, Idaho Power and eleven other parties, including the NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Idaho Power prepared draft biological assessments in consultation with the USFWS and the NMFS and filed those with the FERC in October 2020. The 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: In August 2016, the USFWS re-instated the threatened species status of slickspot peppergrass under the ESA. In July 2020, the USFWS published a revised proposed rule designating critical habitat for the species, most of which are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed route for the Gateway West transmission line project and other transmission and distribution lines

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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

NEPA is a federal law that requires federal agencies to consider the environmental impacts of their actions and decisions. NEPA applies to Idaho Power’s transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions. In April 2022, the 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.

Climate Change and the Regulation of Greenhouse Gas Emissions

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

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

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

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

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

•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 (CO2) emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Stringent emissions standards could result in significant increases in capital

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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.

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

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

In May 2010, the EPA issued the “Tailoring Rule,” which set thresholds for GHG emissions that define when permits are required for new and existing industrial facilities. 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 CO2 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.

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. Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states. To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base.

Idaho has not passed legislation specifically regulating GHGs. Wyoming 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. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, Oregon, Wyoming, and Nevada) are members of the

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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."

Other Clean Air Act Matters

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

The MATS rule under the CAA provides that sources must comply with emission limits by April 2015. Idaho Power and the co-owners of Jim Bridger and North Valmy coal-fired generating plants have installed mercury continuous emission monitoring systems on all coal-fired units at the plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule.

The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, and sulfur dioxide (SO2). 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. However, as of the date of this report, Idaho Power does not expect the recent changes in the NAAQS to significantly impact its operations or materially increase Idaho Power’s capital and operating costs.

In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas. This includes all units at the Jim Bridger plant, which are subject to regulation by both EPA and WDEQ. In 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 NOx 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.

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.

Section 401 Water Quality Certification: As described more fully under “Relicensing of Hydropower Projects” in the "Regulatory Matters" section of this MD&A, Idaho Power filed water quality certification applications, required under Section 401 of the CWA, with Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards. The states issued final certifications in May 2019.

In 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

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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.

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.

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. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.

Accounting for Rate Regulation

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

Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded approximately $1.5 billion of regulatory assets and $0.9 billion of regulatory liabilities at December 31, 2022. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.

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

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Income Taxes

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

Pension and Other Postretirement Benefits

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

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

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2022, 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.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. The long-term rate of return used to calculate the 2023 pension expense will be 7.4 percent, the same assumption as used in 2022.

Total net periodic pension and other postretirement benefit cost for these plans totaled $42.3 million and $65.6 million for the years ended December 31, 2022 and 2021, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2023, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $30.6 million, which takes into account the change in the discount rate noted above.

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

Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $68.6 million decrease in the combined benefit obligations of the plans as of December 31, 2022. A 0.5 percent decrease in the plans' discount rates would have resulted in an $76.4 million increase in the combined benefit obligations of the plans as of December 31, 2022.

The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2022, a total of $250 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.

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.