IDACORP INC (IDA) FY 2021 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 2020 compared with 2019 can be found in their Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report). See Part II - Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2020 Annual 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 generating plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc. (IFS), 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 and recognitions during 2021 include:

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

•IDACORP increased its quarterly common stock dividend to $0.75 per share from $0.71 per share, as a part of a 150 percent increase in quarterly dividends approved over the last ten years. The increase keeps IDACORP within its current target payout ratio of between 60 and 70 percent of sustainable IDACORP earnings, annualizing the most recently declared quarterly dividend;

•Idaho Power's customer count grew 2.8 percent in 2021. On June 30, 2021, Idaho Power set a new all-time system peak demand of 3,751 megawatts (MW), exceeding the previous high of 3,422 MW set on July 7, 2017. The previous high from July 2017 was exceeded multiple times during the heat wave in Idaho Power's service area in June and July of 2021;

•Idaho Power continued its strong safety performance in 2021, tying its previous record for lowest number of Occupational Safety and Health Administration (OSHA) recordable incidents in Idaho Power's history. In January 2022, in recognition of Idaho Power's nontraditional approach of combining psychological safety and behavioral safety with practical application of human performance principles, the Edison Electric Institute (EEI) presented Idaho Power with the inaugural Thomas F. Farrell, II Safety Leadership and Innovation Award; and

•In December 2021, Idaho Power issued its 2021 Integrated Resource Plan (IRP) that contemplates no new fossil fuel resources for Idaho Power's power supply mix and plans for substantial renewable resource additions over the next 20 years. The 2021 IRP also includes the end to Idaho Power's participation in coal-fired generation facilities by the end of 2028, including the conversion of two coal-fired units at the Jim Bridger plant to natural gas in 2024 which facilitates Idaho Power's transition toward its "Clean Today, Cleaner Tomorrow.®" goal to provide Idaho Power's customers with 100 percent clean energy by 2045.

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Coronavirus (COVID-19) Response and Impacts

In response to the COVID-19 public health crisis, in 2020 Idaho Power implemented its emergency management, business continuity, and enterprise pandemic plans. Idaho Power's internal emergency management team responded in accordance with the plans in an effort to ensure Idaho Power continues to provide reliable service to its customers during the public health crisis and to protect employees, customers, the general public, and Idaho Power's electrical system. Idaho Power's provision of electricity to customers through its power supply, transmission, and distribution operations, as of the date of this report, continues largely uninterrupted.

In March 2020, in consideration of COVID-19, Idaho Power temporarily suspended disconnections and late fees for late payment or non-payment. As approved by the IPUC in July 2020, Idaho Power resumed disconnections and accruing late fees for customers in its Idaho service area beginning in early August 2020. In recognition of the economic impact of the COVID-19 public health crisis, Idaho Power continues to carry a higher allowance for uncollectible receivables compared with historical levels. Idaho Power's allowance for estimated uncollectible receivables was $4.5 million at December 31, 2021, $4.8 million at December 31, 2020, and $1.4 million at December 31, 2019.

In 2020, the IPUC and OPUC issued orders granting Idaho Power the authority to defer unanticipated, emergency-related expenses due to COVID-19, net of any cost savings, for possible recovery through future rates. As of December 31, 2021, Idaho Power had recorded an immaterial regulatory asset for its estimate of unanticipated, emergency-related expenses, including higher bad debt expense, net of estimated savings.

In September 2021, the Presidential Administration issued an executive order announcing new U.S. Department of Labor’s OSHA requirements that all employers with more than 100 employees ensure their workforce is fully vaccinated or require any workers who remain unvaccinated to undergo weekly testing before coming to work. In January 2022, the Presidential Administration withdrew the OSHA requirements. If the requirements are reinstated or if there are new requirements imposed that are applicable to Idaho Power's workforce, vendors, or suppliers, Idaho Power is uncertain to what extent the requirements could disrupt the supply chain or result in Idaho Power losing skilled or specialized employees or limit Idaho Power’s ability to attract and retain skilled or specialized employees who are unwilling to obtain a vaccine or subject themselves to weekly testing or other new requirements. Idaho Power, based on discussions with employees, does believe that attrition of skilled workers could result from application of the mandate for COVID-19 vaccines and testing or other requirements to Idaho Power's workforce. If Idaho Power loses key portions of its skilled or specialized workforce, or significant supply chain disruptions occur, those events could adversely impact Idaho Power's ability to provide reliable service to its customers and its business and results of operations.

As of the date of this report, Idaho Power is uncertain how long the COVID-19 public health crisis will last and how significantly it will ultimately impact its business operations, results of operations, cash flows, financial condition, or capital resources. For a discussion of certain risks IDACORP and Idaho Power are confronting as a result of the public health crisis, see Part II - Item 1A - "Risk Factors" in this report.

Summary of 2021 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, 2021, 2020, and 2019 (in thousands, except earnings per share amounts):

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The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2021, from the year ended December 31, 2020 (items are in millions and are before tax unless otherwise noted):

IDACORP's net income increased $8.2 million for 2021 compared with 2020, due primarily to higher net income at Idaho Power.

Idaho Power's customer growth of 2.8 percent added $16.0 million to Idaho Power's operating income compared with 2020. Higher sales volumes on a per-customer basis increased operating income by $13.4 million in 2021 compared with 2020, due mostly to warmer and drier weather in the spring and early summer that caused irrigation customers to use more energy for irrigation pumps and residential customers to use more energy for cooling in 2021 compared with 2020. The increase in usage per residential customer from the spring and early summer was mostly offset by lower usage per residential customer from August through December 2021 compared with those same months in 2020 due to milder temperatures. Also, a return to more normal economic conditions for commercial and industrial customers in 2021 compared with 2020 increased sales volumes on a per-customer basis, as 2020 was affected by negative COVID-19-related business conditions.

The net decrease in retail revenues per megawatt-hour (MWh) reduced operating income by $13.4 million in 2021 compared with 2020, primarily due to higher power supply costs. During the summer of 2021, higher wholesale energy market prices due to a heat wave in the western United States and higher energy usage by Idaho Power customers increased Idaho Power's net power supply expenses. The increase in the amount of net power supply expenses that were not deferred through Idaho Power's power cost adjustment mechanisms contributed to the negative variance in net retail revenues per MWh between the comparison periods. Also, Idaho Power decreased annual Idaho customer rates an estimated $3.9 million on January 1, 2021, and decreased annual Oregon customer rates an estimated $0.3 million on November 1, 2020, to reflect full depreciation of all Boardman power plant investments after ceasing coal-fired operations at the Boardman power plant in October 2020.

During 2021, transmission wheeling-related revenues increased $16.4 million compared with 2020, as the warmer and drier weather in the western United States in the spring and early summer, along with two new long-term wheeling agreements which began in April 2021, increased wheeling volumes. Colder winter weather in the southwest United States during the first quarter of 2021 also contributed to increased wheeling volumes in 2021 compared with 2020. In addition, Idaho Power's open access transmission tariff (OATT) rates increased approximately 10 percent during the period from October 1, 2020, to September 30, 2021, as compared with the rates in effect from October 1, 2019, to September 30, 2020. The rate increased an additional four percent on October 1, 2021.

Other O&M expenses increased $9.2 million in 2021 compared with 2020, primarily due to a return to more normal levels of purchased services and maintenance activity compared with 2020, which was affected by the COVID-19 public health crisis. Also, labor-related other O&M expenses increased slightly in 2021 compared with 2020.

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In 2021, Idaho Power recorded $0.6 million as a provision against current revenues to be refunded to customers through a future rate reduction, through the Idaho-jurisdiction power cost adjustment (PCA) mechanism pursuant to a settlement stipulation approved by the IPUC as described in "Regulation of Rates and Cost Recovery" below.

Non-operating expense, net, increased $3.1 million in 2021 compared with 2020, primarily due to increased costs of an Idaho Power postretirement medical plan that are not expected to recur.

The $7.7 million increase in Idaho Power income tax expense in 2021 compared with 2020 was primarily due to greater 2021 pre-tax income and other plant-related income tax return adjustments.

2022 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 provide reliable, affordable, clean energy to its customers from diversified generation resources.

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:

•Rate Base Growth and Infrastructure Investment: The rates established by the IPUC and OPUC 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 and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. Idaho Power is pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydropower generation resource. Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding.

Existing and sustained growth in customers and peak demand for electricity will require Idaho Power to continue to enhance its power supply, transmission, and distribution infrastructure. Idaho Power's 2021 IRP indicates Idaho Power will have a resource capacity deficit for peak needs of 101 MW in 2023, an additional 85 MW deficit in 2024, and an additional 125 MW deficit in 2025. To help meet peak needs in 2023, Idaho Power plans to acquire and own 120 MW of battery storage assets, 40MW of which would be interconnected to a planned 40 MW solar facility from which Idaho Power will purchase the output through a 20-year power purchase agreement signed in February 2022. The interconnected battery storage facility is expected to qualify for investment tax credits. To help address the capacity deficits projected for 2024 and 2025, Idaho Power issued a request for proposals in December 2021. Based on current estimates, Idaho Power expects it could invest over $400 million in capital expenditures from 2022 through 2025 for resource additions to help meet the projected capacity deficits noted above. For more information on the 2021 IRP, including the load forecast assumptions Idaho Power used in its 2021 IRP, refer to "Resource Planning" in Item 1 - "Business" in this report. 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: 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

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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 certain tax credits 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. The settlement stipulation has no expiration date but the minimum Idaho ROE would revert back to 95 percent of the allowed return on equity in the next 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 anticipated significant infrastructure investments that are intended to help meet projected near-term capacity deficits, Idaho Power’s evaluations indicate that the appropriate time to file general rate cases in both Idaho and Oregon is approaching. The resulting expected increase in rate-base eligible assets as these projects are placed into service, along with the significant amounts of capital expenditures Idaho Power has made since its last general rate case filed in 2011, will increase and potentially accelerate Idaho Power’s need to file general rate cases. 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.

•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 2021, Idaho Power's customer count grew by 2.8 percent. Idaho Power set a new all-time system peak demand of 3,751 MW on June 30, 2021, exceeding the previous high of 3,422 MW set on July 7, 2017. The previous peak demand from July 2017 was exceeded multiple times during the heat wave in Idaho Power's service area in June and July of 2021. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Idaho Power also expects that existing and sustained growth in customers and peak demand for electricity will require Idaho Power to continue to enhance its capacity resources, transmission, and distribution infrastructure, including the Boardman-to-Hemingway and Gateway West transmission projects. That growth has resulted in the need for Idaho Power to procure additional new sources of energy and capacity to serve growing demand and to maintain system reliability, as noted above. Further, recent changes in the regional transmission markets have constrained the transmission system external to Idaho Power's service area and impacted Idaho Power's ability to import energy from energy markets in the western United States during peak load periods.

•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, 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 Fixed Cost Adjustment (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 wholesale energy sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms. For 2022, due to relatively low reservoir storage carryover combined with current and forecasted snowpack conditions, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 to 7.5 million MWh, compared with average total annual hydropower generation of approximately 7.7 million MWh over the last 30 years.

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•Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies significantly on natural gas and coal to fuel its generation facilities 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, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in power supply costs.

•Regulatory and Environmental Compliance Costs: 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. Energy industry regulators may issue substantial penalties for utilities alleged to have violated reliability and critical infrastructure protection requirements. Moreover, environmental laws and regulations, in particular, may increase the cost of constructing new facilities, may increase the cost of operating generation plants, including Idaho Power's jointly-owned coal-fired generating plants, may require that Idaho Power install additional pollution control devices at existing generating plants, or may require that Idaho Power cease operating certain generation plants. Idaho Power expects to spend significant amounts on environmental compliance and controls in the next decade. 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), ceasing operations at one unit in 2019. In 2021, the IPUC acknowledged that Idaho Power's year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs. Idaho Power's jointly-owned coal plant in Boardman, Oregon, ceased operations as planned in October 2020. In June 2021, Idaho Power filed an application with the IPUC requesting, among other things, authorization to allow the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. The status of Idaho Power's application 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 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 in varying degrees 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, Oregon, Colorado, and elsewhere in the western United States, Idaho Power is taking a proactive approach to wildfire threat in its service area. 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; and evaluating the performance and effectiveness of the strategies identified in the WMP through metrics and monitoring. In June 2021, the IPUC authorized Idaho Power to defer, for future amortization, the Idaho jurisdictional share of actual incremental O&M expenses and depreciation expense of certain capital investments necessary to implement the WMP. The WMP case with the IPUC is described in more detail in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings. In this analysis, the results for 2021 are compared with 2020.

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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 2021, retail sales volumes increased 4 percent compared with the prior year, primarily due to growth in the number of Idaho Power customers and warmer and drier spring and early summer weather that caused customers to use more energy for cooling and irrigation. The number of Idaho Power customers grew by 2.8 percent in 2021. Less precipitation in Idaho Power's service area during the spring and early summer of 2021 compared with the same time period in 2020 led agricultural irrigation customers to use 6 percent more energy per customer to operate irrigation pumps during 2021 compared with 2020. During 2021, usage per commercial and industrial customer was approximately 3 percent higher compared with the prior year, due to a return to more normal economic activity compared with 2020, which was affected by negative COVID-19-related business conditions. Usage per residential customer was approximately 1 percent higher in 2021 than 2020, which was primarily due to weather variations that caused residential customers to use more energy for cooling in the spring and early summer, but less energy from August through December. Cooling degree-days in Boise, Idaho were 28 percent higher during 2021 compared with 2020 and 48 percent above normal. Also, heating degree-days were 3 percent lower during 2021 compared with 2020 and 12 percent lower than normal.

Wholesale energy sales volumes decreased 0.6 million MWh, or 50 percent, during 2021 compared with 2020, as lower system generation and higher retail sales volumes led to less energy available for opportunistic market sales.

Total system generation decreased 13 percent in 2021 compared with the prior year, due primarily to lower hydropower generation and coal-fired generation, partially offset by increased natural gas generation. Hydropower generation decreased 23 percent during 2021 compared with 2020, due primarily to lower reservoir storage carryover and weaker snowpack in the Snake River Basin. Coal-fired generation also decreased 20 percent during 2021, due to mostly to economic displacement by power purchased from the energy imbalance market in the western United States (Western EIM) and to a lesser extent due to the

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October 2020 closure of the coal-fired generation plant in Boardman, Oregon. Natural gas generation increased 31 percent due mostly to the decrease in hydropower and coal-fired generation.

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 allowance for funds used during construction (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 $84.6 million in 2021 compared with 2020. 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, decreased retail revenues by $6.4 million in 2021 compared with 2020. Idaho Power decreased annual Idaho customer rates an estimated $3.9 million on January 1, 2021, and decreased annual Oregon customer rates an estimated $0.3 million on November 1, 2020, to reflect full depreciation of all Boardman power plant investments after ceasing coal-fired operations at the Boardman power plant in October 2020. Customer rates also include adjustments related to the PCA mechanism, which increased revenues by $42.0 million in 2021 compared with 2020. The adjustments related to the PCA mechanism in rates do not have a significant effect on operating income as a corresponding amount is recorded in expense in the same period.

•Customers: Customer growth of 2.8 percent increased retail revenues by $22.0 million in 2021 compared with 2020.

•Usage: Higher usage (on a per customer basis), in all customer classes, increased retail revenues by $27.2 million during 2021 compared with 2020. Less precipitation in Idaho Power's service area during the spring and early summer of 2021 compared with the same time period in 2020 led agricultural irrigation customers to use 6 percent more energy per customer to operate irrigation pumps during 2021. A return to more normal economic conditions in 2021 for commercial and industrial customers increased usage by both customer classes approximately 3 percent on a per-customer basis, as 2020 was affected by negative COVID-19-related business conditions. Usage per residential customer was approximately 1 percent higher than 2020, which was primarily due to weather variations that caused residential customers to use more energy at home for cooling in the spring and early summer of 2021, compared with 2020, but less energy from August through December. Cooling degree-days in Boise, Idaho were 28 percent higher during 2021 compared to 2020 and 48 percent above normal. Also, heating degree-days in that area were 3 percent lower during 2021 compared to 2020 and 12 percent lower than normal.

•Sharing: During 2021, Idaho Power recorded $0.6 million as a provision against current revenues to be refunded to customers through a future rate reduction. If approved, the rate reduction would be included in PCA rates beginning in June 2022. Idaho Power did not record any provision for sharing in 2020. 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 related to the May 2018 Idaho Tax Reform Settlement Stipulation. The May 2018 Idaho Tax Reform Settlement Stipulation is described further 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 MWh amounts).

In 2021, wholesale energy revenue increased by $7.2 million, or 21 percent, compared with 2020, as higher average wholesale energy prices more than offset a decrease in volumes sold. Wholesale energy prices were higher compared with 2020 as extreme summer weather resulted in higher demand and lower supply of energy to the wholesale markets in the region. Wholesale energy sales volumes decreased 50 percent in 2021 compared with 2020, as lower system generation and higher retail sales volumes led to less energy available for opportunistic market sales.

Transmission Wheeling-Related Revenues: Revenue related to transmission wheeling increased $16.4 million in 2021 compared with 2020, as warmer, drier spring and summer weather in the western United States, along with two new long-term wheeling agreements that began in April 2021, increased wheeling volumes. In addition, Idaho Power's OATT rates increased approximately 10 percent during the period from October 1, 2020, to September 30, 2021, as compared with the rates in effect from October 1, 2019, to September 30, 2020. Also, Idaho Power's OATT rate increased 4 percent in October 2021. Refer to "Regulatory Matters" in this MD&A for more information on Idaho Power's OATT rate.

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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, 2021, Idaho Power's energy efficiency rider balances were a $6.9 million regulatory asset in the Idaho jurisdiction and a $0.7 million regulatory asset in the Oregon jurisdiction. In December 2020, the IPUC authorized Idaho Power to increase the Idaho energy efficiency rider collection percentage from 2.75 percent to 3.1 percent, effective January 1, 2021.

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 and 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 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 $96.3 million, or 32 percent, in 2021 compared with 2020. The increase was primarily due to a 91 percent increase in MWh purchased from sources other than PURPA contracts as power purchased from the Western EIM economically displaced coal-fired generation at greater volumes in 2021 compared with 2020.

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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 $7.8 million, or 5 percent, in 2021 compared with 2020, primarily due to a 31 percent increase in natural gas generation and a 22 percent increase in the average cost per natural gas MWh generated primarily from higher natural gas market prices. These increases were partially offset by a decrease in coal-fired generation due to economic displacement by power purchased from the Western EIM.

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 2021, gains on financial gas hedges of $12.1 million reduced natural gas fuel expense, while in 2020, losses on financial gas hedges of $4.8 million increased natural gas fuel expense. Most of these realized hedging gains and losses 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 2021, 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 $9.2 million, or 3 percent, in 2021 compared with 2020, primarily due to a return to more normal levels of purchased services and maintenance costs compared with 2020, which was affected by the COVID-19 public health crisis. In 2020, the response to the COVID-19 public health crisis affected the availability and performance of some of Idaho Power's service providers, contractors and vendors, which resulted in lower other O&M expenses. Also, labor-related other O&M expenses increased slightly in 2021, compared with 2020.

Income Taxes

IDACORP's and Idaho Power's 2021 income tax expense increased $8.2 million and $7.7 million, respectively, when compared with 2020. The increases were primarily due to higher pre-tax earnings and other plant-related income tax return adjustments at Idaho Power. For additional information relating to IDACORP's and Idaho Power's income taxes, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.

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 excluding net costs of removing assets from service, were $288 million in 2021 and $299 million in 2020. Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $2.8 billion over the period from 2022 through 2026.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. As of February 11, 2022, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

•their respective $100 million and $300 million revolving credit facilities (Credit Facilities);

•IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 17, 2019, 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 17, 2019, which may be used for the issuance of first mortgage bonds and debt securities; $190 million is 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.

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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, 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.

Based on planned capital expenditures and O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during 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 long-term debt markets.

IDACORP and Idaho Power 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, 2021, 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 2021 were $363 million and $323 million, respectively, decreases of $25 million and $30 million for IDACORP and Idaho Power, respectively, when compared with 2020. Significant items that affected the companies' operating cash flows in 2021 relative to 2020 were as follows:

•an $8 million and a $10 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 and energy efficiency program cost mechanisms, increased operating cash inflows by $3 million;

•changes in deferred taxes and in taxes accrued and receivable combined to decrease IDACORP and Idaho Power cash flows by $28 million and $37 million, respectively; and

•changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, accounts payable, other current assets, and other current liabilities, as follows:

◦timing of collections of accounts receivable balances decreased operating cash flows by $6 million for IDACORP and $3 million for Idaho Power;

◦timing of accounts payable payments increased operating cash flows by $18 million for IDACORP and Idaho Power;

◦the changes in other current assets decreased operating cash flows by $13 million for IDACORP and Idaho Power, which was primarily due to the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants, offset partially by fluctuations in the balance in accrued unbilled revenues; and

◦the changes in other current liabilities, which includes non-incentive compensation, customer deposits, accrued interest, and other miscellaneous liabilities, decreased operating cash flows by $5 million for IDACORP and Idaho Power.

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Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction of and improvements to Idaho Power’s power supply, transmission, and distribution facilities. Idaho Power's capital expenditures, including AFUDC, were $300 million and $311 million in 2021 and 2020, respectively. These capital expenditures 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. As discussed in "Capital Requirements" below, Idaho Power received $6 million and $3 million in 2021 and 2020, respectively, from Boardman-to-Hemingway project joint permitting participants relating to a portion of these permitting expenditures.

Idaho Power's investing cash inflows include $14 million and $1 million return of investment from IERCO, a wholly-owned subsidiary of Idaho Power, in 2021 and 2020, respectively.

Idaho Power has a Rabbi trust designated to provide funding for obligations of its nonqualified defined benefit plans. In the Rabbi trust, Idaho Power purchased equity securities of $16 million in 2021 and $33 million in 2020. Idaho Power received $11 million and $26 million of proceeds in the Rabbi trust from the sales of equity securities in 2021 and 2020, respectively.

During 2021, IDACORP's investing cash inflows also included $50 million of proceeds from maturities of short-term investments. During 2021 and 2020, IDACORP's investing cash outflows included $25 million of purchases of short-term investments in addition to $15 million and $14 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.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, dividends, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility operating expenses through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significant items and transactions that affected financing cash flows in 2021 and 2020:

•in April 2020, Idaho Power issued $230 million in principal amount of its 4.20 percent first mortgage bonds, secured

medium term notes, Series K, maturing March 1, 2048. The bonds were issued at a reoffer yield of 3.422 percent,

which resulted in a net premium of 13.0 percent and net proceeds to Idaho Power of $260 million;

•in June 2020, Idaho Power issued $80 million in principal amount of its 1.90 percent first mortgage bonds, secured

medium term notes, Series L, maturing July 15, 2030;

•in July 2020, Idaho Power redeemed, prior to maturity, $75 million in principal amount of 2.95 percent first mortgage

bonds, medium-term notes, Series H due in April 2022. In accordance with the redemption provisions of the notes, the

redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the

aggregate amount of $3 million;

•in August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in

November 2020; and

•IDACORP and Idaho Power paid dividends of approximately $146 million and $138 million in 2021 and 2020, respectively.

Financing Programs and Available Liquidity

IDACORP Equity Programs: IDACORP has no current plans to issue equity securities other than under its equity compensation plans during 2022.

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 April and May 2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Following the June 2020 issuance of Series L medium-term notes and the April 2020 issuance of Series K medium-term notes described above, $190 million of debt securities remains available for issuance under the orders. Authority from the IPUC is effective through May 31,

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2022, subject to extension upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of seven percent.

In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and Deed of Trust dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

In June 2020, Idaho Power entered into a selling agency agreement with six banks named in the agreement in

connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first

mortgage bonds, secured medium term notes, Series L (Series L Notes), under Idaho Power’s Indenture of Mortgage and Deed

of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also in June 2020, Idaho Power

entered into the Forty-ninth Supplemental Indenture, dated effective as of June 5, 2020, to the Indenture (Forty-ninth

Supplemental Indenture). The Forty-ninth Supplemental Indenture provides for, among other items the issuance of up to

$500 million in aggregate principal amount of Series L Notes pursuant to the Indenture.

The Indenture limits the amount of first mortgage bonds at any one time outstanding to $2.5 billion, and as a result, the maximum amount of additional first mortgage bonds Idaho Power could issue as of December 31, 2021, was limited to approximately $534 million. Idaho Power may increase the $2.5 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of December 31, 2021, Idaho Power could issue approximately $2.1 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

IDACORP and Idaho Power 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 London interbank offered rate (LIBOR) Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero. The Secured Overnight Financing Rate (SOFR) plus a defined benchmark adjustment would replace the LIBOR Market Index rate during any period in which the LIBOR rate is unavailable or unascertainable. If during any period both the LIBOR and SOFR rates are 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. In December 2021, IDACORP and Idaho Power amended the Credit Facilities to extend the termination dates of each facility to December 6, 2025, and provided additional information on potential alternatives, successors or replacement rates for LIBOR in the event it is no longer available as of the date of borrowing, among other things. While the Credit Facilities provide for a maturity date of December 6, 2025, the credit agreements grant IDACORP and Idaho Power the right to request up to two-one-year extensions, subject to certain conditions.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including,

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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, 2021, the leverage ratios for IDACORP and Idaho Power were 43 percent and 45 percent, respectively. IDACORP's and Idaho Power's ability to utilize the 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, 2021, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, as of the date of this report, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during 2022.

The events of default under both 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 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.

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, 2021 and 2020. At February 11, 2022, neither IDACORP nor Idaho Power had loans outstanding under their credit facilities and neither

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had commercial paper outstanding.

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 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. There have been no changes to IDACORP's or Idaho Power's ratings by Standard & Poor’s Ratings Services (S&P) or Moody’s Investors Service (Moody's) from those included in the 2020 Annual Report. However, 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. In June 2021, Moody's rating outlook for IDACORP and Idaho Power were modified to negative, from stable, due to Moody's perception of the companies' financial profile relative to its A-rated peers. Moody's rating outlook indicated that it expected that IDACORP and Idaho Power would not take any material actions to improve their cash flows over the following 12-18 months. Moody's credit ratings of IDACORP and Idaho Power are currently higher than the similar ratings of S&P. Were IDACORP’s and Idaho Power’s credit ratings at Moody’s to decrease to a similar level as S&P, the companies’ credit ratings would nonetheless remain investment grade and the companies do not believe it would 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. Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.

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, 2021, Idaho Power had no performance assurance collateral posted. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2021, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $25.7 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 $288 million during the year ended December 31, 2021. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to electric plant for 2022 through 2026 (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. However, given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table. The timing and amount of actual capital expenditures could be significantly affected by Idaho Power’s ability to timely obtain labor

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or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, or other issues. For future resources that Idaho Power is currently planning to own, if Idaho Power were to enter into power purchase arrangements instead of owning those resources it would decrease Idaho Power's expected capital expenditures.

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of 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. Examples of anticipated system enhancements planned for 2022 through 2026 and estimated costs include the following:

•$40-$70 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-$80 million per year for ongoing improvements and replacements at thermal plants;

•$70-$110 million per year for hydropower plant improvement programs, including relicensing costs; and

•$50-$75 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, existing and sustained growth in customers and peak demand for electricity, transmission constraints, and Idaho Power’s planned exit from coal-fired generation, will also require Idaho Power to acquire significant generation and storage resources to meet energy and capacity needs over the next several years. Idaho Power's 2021 IRP indicates Idaho Power could have a resource capacity deficit for peak needs of 101 MW in 2023, an additional 85 MW deficit in 2024, and an additional 125 MW deficit in 2025. To help meet peak needs in 2023, Idaho Power plans to acquire and own 120 MW of battery storage assets, 40MW of which would be interconnected to a planned 40 MW solar facility from which Idaho Power will purchase the output through a 20-year power purchase agreement signed in February 2022. The interconnected battery storage facility is expected to qualify for investment tax credits. To help address the capacity deficits projected for 2024 and 2025, Idaho Power issued a request for proposals in December 2021. Based on current estimates, Idaho Power expects it could invest over $400 million in capital expenditures from 2022 through 2025 for resource additions to help meet the projected capacity deficits noted above.

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. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to pursue permitting of the project. The joint funding agreement provided that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC.

Approximately $125 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through December 31, 2021. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $81 million in reimbursement as of December 31, 2021, 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 the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, and certain other federal agencies. The BLM issued its record of decision for the project in November 2017, approving a right-of-way grant for the project to cross approximately 86 miles of BLM-administered land. The U.S. Forest Service issued its record of decision in November 2018 authorizing the project to cross approximately seven miles of National Forest lands. In September 2019, the Department of the Navy issued its record of decision authorizing the project to cross approximately seven miles of Department of the Navy lands.

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In November 2019, third parties filed a lawsuit in the federal district court of Oregon challenging the BLM and U.S. Forest Service records of decision for the Boardman-to-Hemingway project on several grounds. In August 2021, the federal district court of Oregon dismissed the third-party lawsuits challenging the records of decision for the Boardman-to-Hemingway project and the third parties did not file to appeal that decision by the deadline in October 2021.

In the separate State of Oregon permitting process, the Oregon Department of Energy (ODOE) issued a Proposed Order in July 2020 that recommends approval of the project to the state's Energy Facility Siting Council (EFSC). The project permit is actively undergoing the EFSC administrative process, and Idaho Power currently expects the EFSC to issue a final order in the second half of 2022.

As the current joint funding agreement covers primarily permitting activities, which are nearing completion, Idaho Power and its co-participants have been exploring several scenarios of ownership, asset, and service arrangements aimed at maximizing the value of the project to each of the co-participants' customers. 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. 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 deliver transmission service to BPA's customers across Southern Idaho.

The capital requirements table above includes approximately $380 million of Idaho Power's share of estimated costs related to the remaining permitting phase of the project (excluding AFUDC), and the costs related to design, material procurement, and construction phases of the project. The preliminary estimates of Idaho Power’s share of construction costs could significantly change as the construction timeline nears and as the project participants further align on future cost estimates.

In July 2021, Idaho Power awarded contracts for detailed design, geotechnical investigation, land surveying, and right-of-way option acquisition; and work commenced in the third quarter of 2021. 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 January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $48 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2021. 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 $250 million and $450 million, including AFUDC. Idaho Power's estimated share of ongoing expenditures for the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potential early construction costs are excluded from the capital requirements table above because the timing of construction of Idaho Power's portion of the project is uncertain.

The permitting phase of the Gateway West project was subject to review and approval of the BLM. The BLM has published its records of decision for all segments of the transmission line. PacifiCorp recently constructed 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. The FERC could issue the license as early as 2023, but as of the date of this report Idaho Power believes issuance is more 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

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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 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. As of the date of this report, proceedings relating to the 2021 IRP are pending at the IPUC and OPUC. 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 2021 and 2020. Idaho Power estimates that it has no minimum required contribution to be made during 2022. Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $40 million to the pension plan during 2022. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position. Beyond 2022, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to Note 12 – “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, 2021 and 2020, Idaho Power's deferral balance associated with the Idaho jurisdiction was $234 million and $201 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, 2021, 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 10 – “Commitments” to the consolidated financial statements included in this report for additional information relating to purchase obligations and other long-term liabilities.

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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 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 2021 and 2020, IDACORP's board of directors voted to increase the quarterly dividend to $0.75 per share and $0.71 per share of IDACORP common stock, respectively. IDACORP's dividends during 2021 were 59.4 percent of actual 2021 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 7 – “Common Stock” to the consolidated financial statements included in this report.

Contingencies and Proceedings

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

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

Off-Balance Sheet Arrangements

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 $51.6 million at December 31, 2021, representing IERCo's one-third share of BCC's total reclamation obligation of $154.7 million. BCC has a reclamation trust fund set aside and specifically for the purpose of paying these reclamation costs. At December 31, 2021, the value of the reclamation trust fund totaled $211.2 million. During 2021, the reclamation trust fund made $21.1 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,

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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 fixed cost adjustment mechanism, power cost adjustment mechanisms, 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 that are intended to help meet projected near-term capacity deficits, Idaho Power’s evaluations indicate that the appropriate time to file general rate cases in both Idaho and Oregon is approaching. The resulting expected increase in rate-base eligible assets as these projects are placed into service, along with the significant amounts of capital expenditures Idaho Power has made since its last general rate case filed in 2011, will increase and potentially accelerate Idaho Power’s need to file general rate cases.

Notable Retail Rate Changes in Idaho and Oregon

The table below presents notable rate changes during 2021 and 2020 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.

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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

October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional accumulated deferred investment tax credits (ADITC) if Idaho Power's actual Idaho ROE was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). Under the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, when Idaho Power's actual calendar-year Idaho ROE exceeded 10.0 percent, Idaho Power was required to share a portion of its calendar-year Idaho-jurisdiction earnings with Idaho customers for the period from 2015 through 2019. The more specific terms and conditions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "May 2018 Idaho Tax Reform Settlement Stipulation" of this MD&A.

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 the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation described above beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism that became effective beginning January 1, 2020, with no defined end date. The May 2018 Idaho Tax Reform Settlement Stipulation does not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its term and includes provisions for the accelerated amortization of ADITC to help achieve a minimum 9.4 percent (9.5 percent prior to 2020) Idaho ROE. In addition, under the May 2018 Idaho Tax Reform Settlement Stipulation, minimum Idaho ROE would revert back to 95 percent of the authorized return on equity in the next general rate case. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the May 2018 Idaho Tax Reform Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its full-year Idaho ROE exceeded 10.0 percent. Idaho Power recorded no provision against current revenue for sharing with customers in 2020, as its full-year ROE was between 9.4 percent and 10.0 percent. At December 31, 2021, 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 December 2011 and October 2014 Idaho Settlement Stipulations and the May 2018 Idaho Tax Reform Settlement Stipulation (in millions):

(1) The 2011 sharing amounts were recorded pursuant to a regulatory mechanism preceding the December 2011 Idaho settlement stipulation.

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For more information on the settlement stipulations and their impacts on results, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Oregon Tax Reform Matters: In May 2018, the OPUC issued an order approving a settlement stipulation that provided for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform (May 2018 Oregon Income Tax Reform Settlement Stipulation). In May 2020, the OPUC issued an order approving the quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and state income tax changes resulting from tax reform and adjusting Idaho Power's customer rates to reflect this amount, effective June 1, 2020, until the company's next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.

2021 Integrated Resource Plan and Resource Procurement Filings: Idaho Power filed its most recent IRP with the IPUC and OPUC in December 2021, as described in Part 1, Item 1 - "Resource Planning and Renewable Energy Projects" in this report. The 2021 IRP identified the need for resources to meet projected capacity deficits in the near-term.

Also in December 2021, Idaho Power filed an application with the IPUC requesting approval to procure additional capacity resources to provide adequate, reliable, and fair-priced service to customers due to recent customer growth and an increase in energy demand. In its application, Idaho Power requested the IPUC issue an order: (1) eliminating the IPUC requirement to comply with the OPUC’s resource procurement rules in favor of a competitive, but expedited process; (2) authorizing Idaho Power to move forward expeditiously with resource procurement to meet identified resource needs in 2023, 2024, and 2025; and (3) affirming support and the continuation of the state of Idaho’s system of public utility regulation under which Idaho Power believes the interests of customers are best served by a vertically integrated electric utility maintaining ownership of the power supply, transmission, and distribution utility functions, with limited exceptions. As of the date of this report, the IPUC's decision in this matter is pending.

Similarly, in December 2021, Idaho Power filed an application with the OPUC requesting a waiver of Oregon's competitive bidding rules. Specifically, Idaho Power requested 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 competitive process and authorizing Idaho Power to move forward expeditiously with resource procurement to meet identified resource needs in 2023, 2024, and 2025. As of the date of this report, the OPUC's decision in this matter is pending.

Large Customer Rate Proceedings:

Speculative High-Density Load: In November 2021, Idaho Power filed an application with the IPUC to create a new customer class that would be applicable to commercial and industrial cryptocurrency mining operations smaller than 20 MW. Idaho Power 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 economics of cryptocurrency mining change. Idaho Power believes that the financial and system risks of Speculative High-Density Load can be mitigated through rate design for this customer class, which prices energy at a marginal rate, and through a requirement that Speculative High-Density Load customers be interruptible at Idaho Power's discretion from June 15 through September 15, Idaho Power's summer peak season. As 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 (RECs); (3) establish a regulatory framework for a future voluntary subscription green power service program; (4) offer a tailored renewable option for Idaho Power's largest customers; and (5) procure the associated additional resources outside of the IPUC's current competitive procurement requirements. 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 expected to begin operations in 2025. 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

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its application, Idaho Power requested authority to procure the necessary resources contemplated within its agreement with Brisbie without seeking IPUC approval for each such procurement and requested assurance from the IPUC that each such resource procurement would receive the same ratemaking treatment outlined in the case, unless otherwise modified in a subsequent proceeding. As of the date of this report, the IPUC's decision in this matter is pending.

Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for the North Valmy coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 no later than the end of 2025. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). 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 February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy plant in 2019 and 2025, respectively. In May 2019, the IPUC issued an order approving the North Valmy plant exit agreement and allowing Idaho Power to recover through customer rates the $1.2 million incremental annual levelized revenue requirement associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned, Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1.

In June 2017, the OPUC also approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery of incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provided for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, with yearly adjustments, if warranted. In May 2018, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant exit agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1. In September 2021, the IPUC issued an order acknowledging Idaho Power's year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs.

Boardman Power Plant Filings: In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant. In December 2020, the IPUC issued an order authorizing a determination that all actual Boardman power plant investments made through June 30, 2020, were prudently incurred and decreasing Idaho customer rates $3.9 million to reflect full depreciation of all Boardman power plant investments, effective January 1, 2021. In October 2020, the OPUC issued a similar order approving a $0.3 million decrease in Oregon customer rates, effective November 1, 2020.

Customer-Owned Generation Filing: Customer-owned generation allows 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 utilizes energy supplied by Idaho Power’s grid. If a customer's system generates more energy than the customer uses, the energy goes back to the grid and Idaho Power applies a corresponding kilowatt-hour 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. Since October 2018, 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 whether, and to what extent, there should be modifications to the customer-owned generation pricing structure for residential and small general service customers, and large commercial, industrial, and irrigation customers (CI&I). The IPUC issued orders in one of the residential and small commercial cases during 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 customers with on-site generation prior to December 20, 2019, to be subject to the billing terms in place on that date until December 20, 2045. In December 2020, the IPUC issued an order establishing a 25-year grandfathering term for CI&I customers, similar to the terms approved for the residential and small commercial customer classes.

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In March 2021, the IPUC issued an order approving Idaho Power's application as filed that establishes a smart inverter requirement for all new on-site energy-generating resources interconnected to the company's system, among other things. In June 2021, Idaho Power filed an application requesting that the IPUC initiate the multi-phase process for a comprehensive study of the costs and benefits of on-site generation as directed by previous IPUC orders. In December 2021, the IPUC issued an order requiring Idaho Power to complete the study design for its comprehensive study on the costs and benefits of on-site generation based on the IPUC’s study framework findings and conclusions and requiring that Idaho Power complete the study in 2022 as soon as feasible. As of the date of this report, Idaho Power expects to complete the study in the first half of 2022.

Depreciation Rate Requests: In 2021, Idaho Power conducted a depreciation study of electric plant-in-service, which it performs approximately every five years. The study provided updates to net salvage percentages and service life estimates for Idaho Power plant assets. In November 2021, Idaho Power filed stipulations in both jurisdictions, adopting new depreciation rates, and agreeing to no increases in either the Idaho or Oregon jurisdictional revenue requirement and no changes in customer rates. The IPUC and OPUC approved the stipulations, to be effective January 1, 2022.

Jim Bridger Power Plant Rate Request: In June 2021, Idaho Power filed an application with the IPUC requesting authorization to (1) accelerate depreciation for the Jim Bridger plant, to allow the plant to be fully depreciated and recovered by December 31, 2030, (2) establish a balancing account to track the incremental costs and benefits associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (3) adjust customer rates to recover the associated incremental annual levelized revenue requirement.

In September 2021, the co-owner and operator of the Jim Bridger Plant submitted its IRP to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 and converting those units to natural gas generation by 2024. Idaho Power's 2021 IRP includes the same plan. At a public meeting in October 2021, the IPUC approved a joint motion by Idaho Power and the IPUC Staff to suspend the procedural schedule in Idaho Power's rate request case to assess new developments that impact operations at the Jim Bridger plant, citing the potential option to convert the two units to natural gas generation as well as ongoing regional haze compliance discussions. In February 2022, Idaho Power filed a request to resume the procedural schedule with an amended application to the IPUC that contemplates the conversion of units 1 and 2 to natural gas in 2024 and therefore removes from the application all investments for the portion of the plant that will be converted to support gas-fired operations, leaving just coal-related plant investments in the requested regulatory treatment. The updated filing requests authorization to adjust customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of $27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operations at the Jim Bridger plant. The proposed adjustment in this application would result in an overall rate increase of 2.12 percent in Idaho. As of the date of this report, the case remains pending at the IPUC.

Deferred Costs for COVID-19 Public Health Crisis: Idaho Power has incurred, and expects to continue to incur, costs associated with its response to the COVID-19 public health crisis, including information technology expenditures for remote work and higher than average levels of bad debt expense related to uncollectible accounts associated in part with its temporary suspension of disconnects and late payment fees. Accordingly, in March and April 2020, Idaho Power submitted applications to the OPUC and IPUC, respectively, requesting authorization to defer incremental costs associated with its response to the COVID-19 public health crisis. Idaho Power requested authorization to establish a new regulatory asset to record the deferral of incremental costs and, in the Idaho jurisdiction, unrecovered costs associated with the COVID-19 response. Both applications requested only the authority to defer these costs and to determine ratemaking treatment at a later date. Subsequent to Idaho Power's application, the IPUC opened a general docket to address the issue. In July 2020, the IPUC issued an order authorizing Idaho Power and other utilities to account for unanticipated, emergency-related expenses incurred due to the COVID-19 public health crisis by recording the expenses as regulatory assets for possible recovery through future rates. The order also requires utilities to account for the decreases in expenses resulting from the COVID-19 public health crisis, such as reduced employee travel and training, and apply these reductions in expenses to offset the deferral account balance. Additionally, the order addressed potential reductions in revenue due to the COVID-19 public health crisis, allowing utilities to track reduced revenues from customer classes not included in an FCA-type mechanism for possible movement to the regulatory asset account at a later date. Idaho Power resumed assessing late fees and disconnections in early August 2020 in its Idaho service area. In October 2020, the OPUC issued an order authorizing Idaho Power to defer certain COVID-19-related costs for the 12-month period beginning March 24, 2020. In March 2021, Idaho Power requested that the OPUC re-authorize such deferral for an additional 12-month period. As of December 31, 2021, Idaho Power had recorded an immaterial regulatory asset for its estimate of unanticipated, emergency-related expenses, including higher bad debt expense, net of estimated savings.

Wildfire Mitigation Cost Recovery: 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

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IPUC also authorized Idaho Power to record these deferred expenses as a regulatory asset until the company can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review actual costs and determine the amount of prudently incurred costs that Idaho Power can recover through retail rates. In the filing, Idaho Power projected spending approximately $47 million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening capital incremental 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, 2021, Idaho Power’s deferral related to the WMP was $6.1 million. Idaho Power expects that it will continue to incur additional incremental costs from its enhanced wildfire mitigation efforts in future periods.

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. Idaho Power does not expect the modifications to 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.

Deferred (Accrued) 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 Proceedings

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system. In September 2021, Idaho Power filed its 2021 final transmission rate with the FERC, reflecting a transmission rate of $31.19 per kW-year, effective for the period from October 1, 2021, to September 30, 2022. 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 $127.3 million. The OATT rate in effect from October 1, 2020, to September 30, 2021, was $29.95 per kW-year based on a net annual transmission revenue requirement of $117.7 million. The increase in the OATT rate is largely attributable to increased transmission plant as well as decreased short-term firm and non-firm transmission revenues in 2020, which serve as an offset to the transmission revenue

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requirement. Historical OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

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 $389 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, 2021. 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, 2021, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $187.7 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, including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process 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. In August 2007, the FERC Staff issued a final environmental impact statement (EIS) for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The FERC may require a supplemental, updated EIS prior to the issuance of a new license for the HCC. The purpose of the final EIS is to inform 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 September 2007, in connection with the issuance of its final EIS, the FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species, including the bull trout and fall Chinook salmon and steelhead, under the NMFS's and USFWS's jurisdiction and requested that the NMFS and USFWS initiate formal consultation under Section 7 of the ESA on the licensing of the HCC. Both the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process. The NMFS and USFWS each therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.

In connection with its relicensing efforts, Idaho Power filed 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 project comply with applicable state water quality standards. Section 401 of the CWA requires that a state either approve or deny a Section 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the CWA. As a consequence, Idaho Power filed and withdrew its Section 401 certification applications with Oregon and Idaho on an annual basis while it was working with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards. In the 2016 Section 401 certification application process, Oregon required Idaho Power to comply with fish passage and reintroduction conditions. Idaho's water quality certification, however, provided that Idaho Power take no action that might result in the reintroduction or establishment of spawning populations of any fish species into Idaho's waters without consultation with and express approval of the State of Idaho. 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

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Oregon state law. 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 D.C. Circuit Court, 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. Additionally, Idaho Power is required to fund a total of $12 million of research and water quality improvements in the HCC over a 20-year period following the issuance of the license. Idaho Power estimates that the combined cost of the mandated water quality improvements and expanded hatchery production is $20 million in aggregate over the first 20 years of the new license term. In May 2019, Oregon and Idaho issued final CWA Section 401 certifications. These certifications have been submitted to the FERC as part of the relicensing process. In July 2019, three third-parties filed lawsuits against the Oregon Department of Environmental Quality in Oregon state court challenging the Oregon CWA Section 401 certification based on fish passage, water temperature, and mercury issues associated with the Snake River and the HCC. Two of the lawsuits were consolidated, and Idaho Power intervened in that lawsuit and the parties reached a settlement. The court dismissed the third challenge to the Oregon CWA 401 certification with prejudice. No parties challenged the Idaho CWA 401 certification. 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.

Idaho Power continues to work with Idaho and Oregon on measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards and associated measures identified in the final Section 401 certifications, and continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. Measures identified in the final Section 401 certifications included construction of aerated runners at the Brownlee project (part of the HCC), modification of spillways at the three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements to address water temperature exceedances during a small portion of the year. These and any other additional measures to satisfy relicensing requirements have added and will continue to add substantially to project costs.

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. In December 2020, FERC staff issued six additional information requests (AIRs) from Idaho Power to help with the analysis and baseline for the project moving forward. Idaho Power has filed responses to all six of the AIRs with FERC. Subsequently, in September 2021 FERC issued ten additional AIRs to clarify the cost of the proposed mitigation measures. Once FERC has evaluated the additional information, Idaho Power expects it to issue a Notice of Intent indicating what, if any, additional environmental analysis is necessary to issue a license. Idaho Power expects the FERC will also initiate formal ESA consultation with the USFWS and the NMFS.

As of the date of this report, 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 any new license. The FERC could issue an HCC license as early as 2023, but as of the date of this report Idaho Power believes issuance is more likely in 2024 or thereafter. 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.

American Falls Relicensing: In April 2020, the FERC formally initiated the relicensing proceeding for 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. A final license application is due to the FERC in 2023. The relicensing proceeding will begin 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

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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 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, 2021, and 2020, Idaho Power's REC sales totaled $4.7 million and $5.2 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 PURPA. As of December 31, 2021, Idaho Power had contracts to purchase energy from 129 on-line PURPA projects. An additional three contracts are with on-line non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity.

The following table sets forth, as of December 31, 2021, 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 facility hydropower project that is scheduled to be on-line in 2022, two PURPA-qualifying facility solar projects scheduled to be on-line in 2023, and one PURPA-qualifying facility solar project scheduled to be on-line in 2024. The non-PURPA solar project is scheduled to be on-line in late 2022.

In July 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

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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) requirements, 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.

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 operating 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 2022 to 2024. 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 2024, though they could be substantial. Furthermore, several executive orders issued since 2017 concerning environmental regulations, including executive orders issued by the current Presidential Administration in 2021, as described below, 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 reduction or elimination of permitting requirements. Executive orders resulting in 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. 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, and therefore, Idaho Power is uncertain whether and to what extent the orders could affect its operations, and environmental-related expenditures. Idaho Power plans to continue to monitor actions associated with or resulting from executive orders.

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Executive Orders on Environmental Matters

In January 2021, the current Presidential Administration issued several executive orders to establish new federal environmental mandates, revoke several existing executive orders, and require agencies to review regulations related to environmental matters issued by the previous Presidential Administration (January 2021 Executive Order(s)). One executive order rejoined the United States to the Paris Agreement on climate change, which requires commitments to reduce greenhouse gas (GHG) emissions, among other things. In response to another executive order, the U.S. Environmental Protection Agency (EPA) requested that the U.S. Department of Justice stay all proceedings in pending litigation seeking judicial review of any EPA regulations promulgated between 2017 and January 20, 2021. Another executive order in 2021 directed the Office of the Federal Register to stop publishing rules and other documents sent to it by the previous Presidential Administration, which Idaho Power believes may apply to the regional haze rules described in this MD&A below, and paused the effective date of certain federal rules that had not yet taken effect as of January 20, 2021. During the "freeze period," the federal agencies were directed to review any such pending actions and determine whether they should move forward or be modified on a rule-by-rule basis by the relevant federal agency. New or modified environmental regulations resulting from these orders 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. 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 January 2021 Executive Orders, any future executive orders, and the implementation of these and any future executive orders may impact Idaho Power's business, results of operations and financial condition.

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. When a species is added to the federal list of threatened and endangered species, it is protected from “take,” which is defined to include harming the species. The ESA directs that, concurrent with a designation of a threatened or endangered species, and where prudent and determinable, the applicable agencies also designate “any habitat of such species which is then considered to be critical habitat.” The ESA also provides that each federal agency must ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat. If an action is determined to result in adverse modification of critical habitat, the federal agency must adopt changes to the proposed action to avoid the adverse modification. These changes are often quite extensive and can affect the size, scope, and even the feasibility of a project moving forward.

In November 2018, the U.S. Supreme Court held that an area is eligible for designation as a critical habitat under the ESA only if it is also "habitat" for the species as defined in the statute, which generally means the area can support the species without modification, and as part of the designation, the USFWS must also consider the costs compared to the benefits of such designation. Idaho Power believes this ruling may limit the number of areas designated as critical habit and could also reduce Idaho Power’s obligations for mitigation under the ESA. Furthermore, in August 2019, the USFWS and the NMFS issued a set of regulatory changes to some of the standards under which listings, delisting, and reclassifications and critical habitat designations are made.

In June 2021, in response to the January 2021 Executive Orders directing federal agencies to review certain environmental regulations, the USFWS and the NMFS released a plan to initiate rulemaking to revise, rescind, or reinstate five ESA regulations finalized by the prior administration. The agencies announced that they intend to rescind regulations that revised the USFWS's process for considering exclusions from critical habitat designations, rescind the regulatory definition of habitat, revise regulations for listing species and designating critical habitat, revise regulations for interagency cooperation, and reinstate certain protections for species listed as threatened under the ESA. In October 2021, the USFWS and NMFS proposed new rules to remove exclusions for certain territory subject to critical habitat designations and to rescind the prior administration's regulatory definition of habitat.

The construction of power supply, transmission, or distribution facilities and the relicensing of Idaho Power's hydropower projects can be federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. In December 2020, the USFWS announced that although it will not yet list the black and orange monarch butterfly as threatened or endangered, it will continue to monitor this species for future determination in 2024, which Idaho Power believes could potentially impact right-of-way maintenance for its transmission line routes. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydropower facilities, including fall Chinook salmon, bull

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trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's hydropower facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases. These ESA regulations could impact the timing and feasibility of the HCC relicensing project and the 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 February 2016, a lawsuit was filed in the U.S. District Court of Idaho challenging 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 lawsuit challenges the plans and associated EISs across the sage grouse range and alleges 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 complaint challenges 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 May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests.

In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. In March 2019, the BLM issued a record of decision for six EISs that modified the 2015 sage grouse plans to better align the plan with state plans, conservation measures and the Department of the Interior and BLM policy. In October 2019, the U.S. District Court for Idaho placed a preliminary injunction on the implementation of the BLM's March 2019 plans. In order to address the concerns contained in the preliminary injunction, BLM initiated a supplemental EIS process that was completed in November 2020. A record of decision for the 2020 supplemental EIS was signed in January 2021. In November 2021, the BLM issued a notice of intent to address the management of sage grouse and sagebrush habitat on BLM-managed public lands in Idaho and Oregon, among other states, through a land use planning initiative. The BLM indicated that it will prepare an EIS to support the planning initiative, and will begin the scoping process to solicit public comments on the planning initiative by February 2022.

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 October 2021, also in response to the January 2021 Executive Orders, 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 USFWS long-standing interpretation of the MBTA prohibiting the incidental take of migratory birds. Concurrently, the USFWS published an advanced notice of proposed rulemaking to determine whether and under what circumstances it could authorize 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.

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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. Idaho Power expects the FERC to initiate formal ESA consultation with the USFWS and the NMFS. At the conclusion of formal consultation and with the issuance of biological opinions by the NMFS and the USFWS and an operating license by the FERC, Idaho Power may be required to implement additional measures or further modify or adjust operations to comply with Section 7 of the ESA. The issuance of a final biological opinion during 2022 is unlikely.

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 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.

Changes to NEPA: In July 2020, the previous Presidential Administration's Council on Environmental Quality (CEQ) announced its final rule to narrow federal agencies' NEPA obligations (2020 NEPA Rule), which had the potential to expedite and reduce the cost of Idaho Power's permitting and right-of-way processes. 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. Under Executive Order 13990 issued in January 2021, the current Presidential Administration’s CEQ was tasked with reviewing the 2020 NEPA Rule. In October 2021, the CEQ published a notice of proposed rulemaking to reverse the more narrow 2020 NEPA Rule, with minor modifications, which if promulgated as proposed could delay and increase the cost of Idaho Power’s transmission projects. The proposed rule’s focus on restoring consideration of indirect and cumulative environmental impacts of infrastructure projects could result in federal agencies giving greater consideration to climate change and environmental justice-related impacts in their decision-making. The proposed rule was subject to a comment period that expired in November 2021. As of the date of this report, the proposed rule is still pending.

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Climate Change and the Regulation of Greenhouse Gas Emissions

Overview: Long-term 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 plants and operations, including restrictions on the construction 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 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, and plans to end its participation in the North Valmy plant unit 2 no later than the end of 2025. Idaho Power's 2021 IRP contemplates the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024 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. 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 emission 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 released the Affordable Clean Energy (ACE) rule to replace the CPP 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 ACE rule in its entirety and directed 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 Court

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vacated the ACE rule without reinstating the CPP. 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 imposes GHG emission reporting requirements on facilities emitting 2,500 metric tons or more of CO2 equivalent annually. The Boardman power plant located in Oregon, in which Idaho Power was a 10-percent owner, was subject to and in compliance with Oregon's GHG reporting requirements but ceased coal-fired operations in 2020.

In Oregon, legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was 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.

The State of 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 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

Overview: 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.

MATS Implementation: The final MATS rule under the CAA, previously referred to as the Utility Maximum Achievable Control Technology Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Legal challenges relating to the MATS rule, to which Idaho Power is not a party and pursuant to which the EPA is performing a court-mandated cost analysis for the rule, are pending. In August 2018, the EPA began reconsidering the justification behind the MATS rule and reviewing the regulations emissions standards. In December 2018, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. The emissions standards and other requirements of the MATS rule, however, remain in place. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule, which does not significantly impact Idaho Power’s operations or financial results.

National Ambient Air Quality Standards: 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 (NO2), and sulfur dioxide (SO2). States are then required to develop emissions reduction strategies through State Implementation Plans, or 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 include the following:

•NO2: In 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a one-hour period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO2.

•SO2: In 2010, the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. In 2011, the states of Idaho, Nevada, Oregon, and Wyoming sent letters to the EPA recommending that all counties in these states be classified as "unclassifiable" under the new one-hour SO2 NAAQS because of a lack of

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definitive monitoring and modeling data. In February 2013, the EPA issued letters to the states of Idaho and Oregon, finding that the most recent air quality data for those states showed no violations of the 2010 SO2 standard. Since January 2018, the EPA has finalized designations of “unclassifiable/attainment” for SO2 for all areas in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant.

•Ozone: In late 2014, the EPA issued a proposed rule that would update the ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. In October 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of United States counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. Since January 2018, the EPA has finalized designations for all of the counties in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant and determined that they meet the standard.

As of the date of this report and based on the EPA designations described above, Idaho Power does not expect these standards to significantly impact its operations or materially increase Idaho Power’s capital and operating costs.

Regional Haze Rules: 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.

In December 2009, the WDEQ issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install selective catalytic reduction equipment for nitrogen oxide (NOx) control at Jim Bridger units 3 and 4 by December 31, 2015, and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017, to install add-on NOx controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, which was submitted in December 2017. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming regional haze state implementation plan (SIP) that are consistent with the terms of the settlement agreement. In January 2014, the EPA approved Wyoming's regional haze SIP as to the Jim Bridger plant, with the NOx control compliance dates set forth in the settlement agreement.

In February 2019, PacifiCorp submitted a SIP revision to the WDEQ as an alternative regional haze compliance plan for the Jim Bridger plant that includes a reduced plant-wide monthly limit on emissions for NOx and SO2 and an annual total emissions cap for NOx and SO2 for units 1-4. In May 2020, the WDEQ approved the alternative plan as proposed, which would eliminate the requirement to install add-on NOx controls at Jim Bridger units 1 and 2. In September 2021, PacifiCorp submitted its IRP to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 and converting those units to natural gas generation by 2024. In late-2021, the State of Wyoming and PacifiCorp issued a Notice of Intent to sue the EPA for the EPA’s failure to act on the 2019 proposed SIP revision. The Notice of Intent was intended to allow PacifiCorp and Wyoming to bring a non-delegable duty suit against the EPA. On December 27, 2021, Wyoming Governor Gordon issued a temporary emergency suspension of Wyoming’s existing SIP that allows Jim Bridger unit 2 to continue to operate through the end of April 2022. On January 12, 2022, the EPA issued a proposed rule that, if adopted, would disapprove the 2019 proposed SIP revision, and the proposed rule was published in the Federal Register on January 18, 2022. Comments on the proposed disapproval are due by February 17, 2022, and as of the date of this report, the proposed EPA rule is pending. On February 14, 2022, the State of Wyoming filed a complaint against PacifiCorp as well as a negotiated consent decree with PacifiCorp in Wyoming state court for the threat of non-compliant operation of Jim Bridger units 1 and 2. The consent decree requires that PacifiCorp: (1) submit a revised permit application and request a SIP revision that would reflect a natural gas conversion of both units; and (2) propose an RFP for carbon capture technology at units 3 and 4. As of the date of this report, the revised permit application and RFP are pending.

Clean Water Act Matters

Definition of “Waters of the United States” Under the CWA: In August 2015, the EPA and USACE final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective (WOTUS Rule). Idaho Power believes that the 2015 rule potentially expanded federal jurisdiction under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. The WOTUS Rule was widely challenged in both federal district and circuit courts. In January 2020, the EPA and USACE finalized the first of a two-part rule to repeal the WOTUS Rule and set new and more expansive standards for determining which waters are subject to the CWA, which substantially restored the definitions and guidance used prior to the WOTUS Rule. In April 2020, the EPA and USACE published the second part of the final rule to replace the WOTUS Rule

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with the "Navigable Waters Protection Rule" that provides a final definition of "waters of the United States," which ultimately narrows the scope of waters subject to federal regulation under the CWA. The Navigable Waters Protection Rule became effective in June 2020. In November 2021, in response to the January 2021 Executive Orders, the EPA and USACE announced the availability of a pre-publication version of a proposed rule that restores the protections in place prior to the WOTUS Rule and establishes a new expansive definition of "waters of the United States."

Idaho Power believes the repeal rule, the WOTUS Rule, the Navigable Waters Protection Rule, and the proposed new rule will continue to be challenged in court, but expects that, even if the WOTUS Rule is reinstated in Idaho or the expansive proposed new rule is enacted and should the revised definition take effect in Idaho, while it may cause Idaho Power to incur additional permitting, regulatory requirements, and other costs associated with the rule, 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, as interpreted even prior to the WOTUS Rule, applies to most of Idaho Power's facilities, including its hydropower plants, Idaho Power does not expect reinstatement would have a material impact on 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 the states of 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, after reaching a settlement with Idaho Power on fisheries-related matters. The Oregon certification, however, was challenged in state court by third parties. Idaho Power intervened in one of those lawsuits and is closely monitoring the other. 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 fish settlement among Idaho, Oregon, and Idaho Power. During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement and its decision relating to the Offer of Settlement is pending as of the date of this report.

In July 2020, the EPA published a rule amending regulations intended to implement the CWA Section 401 water quality certification process. The rule clarifies that a state must issue its water quality certification within a reasonable time period, up to one year from the certification request, and limits the scope of the certification to jurisdictional water quality matters. Further, the new regulations make clear that federal agencies, not the state departments of environmental quality, will enforce the certification conditions. This rule became effective in September 2020 (2020 CWA Section 401 Order). In October 2021, the U.S. District Court for the Northern District of California issued an order remanding and vacating the 2020 CWA Section 401 Order, which order applies nationwide, and requires a temporary return to the EPA's previous Section 401 of the CWA in effect since 1979. 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.

Idaho Power expects the EPA 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 unless the FERC declines to adopt the Offer of Settlement, in which case Idaho Power would file new water quality certification applications in Idaho and Oregon with revisions necessary to address changes to the regulations, which Idaho Power cannot currently predict and could delay the timing of issuance and increase the cost of obtaining a license for the HCC.

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.

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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 $0.8 billion of regulatory liabilities at December 31, 2021. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.

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

Income Taxes

IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. 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 (together, SMSP), and a postretirement benefit plan (consisting of health care and death benefits).

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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, 2021, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 2022 defined benefit plan pension expense will be increased to 3.05 percent from the 2.80 percent rate used in 2021.

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. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher. The long-term rate of return used to calculate the 2022 pension expense will be 7.4 percent, the same assumption as used in 2021.

Total net periodic pension and other postretirement benefit cost for these plans totaled $65.6 million and $53.8 million for the years ended December 31, 2021 and 2020, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2022, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $45.4 million, which takes into account the change in the discount rate noted above.

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 $119.4 million decrease in the combined benefit obligations of the plans as of December 31, 2021. A 0.5 percent decrease in the plans' discount rates would have resulted in an $135.9 million increase in the combined benefit obligations of the plans as of December 31, 2021.

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, 2021, a total of $234 million of expense was deferred as a regulatory asset. Idaho Power expects to defer approximately $16 million of expense in 2022. 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 2021 and 2020.

Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.

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