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Item 7. Management’s Discussion and Analysis

2023-02-16 compared with 2022-02-17 · 515 added, 611 removed, 710 unchanged (61% of the section changed)

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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.

The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 2021 compared with 2020 can be found in their Annual Report on Form 10-K for the year ended December 31, 2021.

See Part II - Item 7 - MD&A in that report for further information on the companies' prior period results of operations.

While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power.

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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;

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

IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc., an investor in affordable housing and other real estate tax credit investments;

and Ida-West Energy Company, an operator of small hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

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

Examples of IDACORP's and Idaho Power's achievements 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;

Examples of IDACORP's and Idaho Power's achievements, notable events, milestones, and recognitions during 2022 include:

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

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

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

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;

• 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.

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.

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

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

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

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

• As part of its “Clean Today.

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

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

Summary of 2022 Financial Results

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Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms 8.8

Idaho fixed cost adjustment (FCA) revenues (12.7)

Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms 24.4

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

Depreciation expense 5.4

Other changes in operating revenues and expenses, net (14.8)

Increase in Idaho Power operating income prior to sharing mechanism 21.4

Provision for sharing with customers (0.6)

Increase in Idaho Power operating income 20.8

Decrease in Idaho Power operating income (2.4)

Non-operating expense, net 15.7

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

Higher sales volumes on a per-customer basis increased operating income by $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.

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Higher wholesale natural gas and power market prices in the western United States and higher energy usage by Idaho Power customers, combined with below-average generation from Idaho Power's hydroelectric facilities, increased Idaho Power's net power supply expenses in 2022.

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

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

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

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

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

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

2023 Initiatives and Strategy

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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.

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

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

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

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

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

• Economic Conditions and Loads:

Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands.

In recent years, Idaho Power has seen significant growth in the number of customers in its service area.

In 2022, Idaho Power's customer count grew by 2.4 percent.

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

While current inflationary and volatile economic conditions could slow the rate of residential customer growth in the near-term, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase in the foreseeable future.

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

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

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

and Micron Technology, Inc.

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

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

(Billed MWh) Annual Peak

(Peak Demand) Retail Sales

(Billed MWh) Annual Peak

(Peak Demand)

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

2021 IRP 2.6% 2.1% 1.4% 1.4%

2019 IRP 1.3% 1.4% 1.0% 1.2%

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

This includes the Boardman-to-Hemingway and Gateway West transmission projects, along with other capacity and energy resources contemplated by the resource procurements described in the "Rate Base Growth and Infrastructure Investment" section below in this MD&A.

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

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

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

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

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

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

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

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

• Rate Base Growth and Infrastructure Investment:

The rates established by the IPUC 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.

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

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

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

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

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

Idaho Power intends to pursue timely 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.

Idaho Power intends to pursue timely

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

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

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

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

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

• Regulation of Rates and Cost Recovery;

General Rate Case Filing:

The prices that Idaho Power is authorized to charge for its electric and transmission service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition.

Those rates are established by state regulatory commissions and the FERC and are intended to

allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment.

Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment.

Idaho Power focuses on timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and prudent management of expenses and investments.

Idaho Power has a regulatory settlement stipulation in Idaho that includes provisions for the accelerated amortization of 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.

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

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

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

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

With Idaho Power’s 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.

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

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

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

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

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

• Economic Conditions and Loads:

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 enhan ce its capacity resources, transmission, and distribution infrastructure, including the Boardman-to-Hemingway and Gateway West transmission projects.

That grow th has resu lted 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:

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Relatively low and high temperatures result in greater energy use for heating and cooling, respectively.

During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps.

During the agricultural growing season, which in large part occurs during the second and third quarters of each year, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps.

Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest.

Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho Fixed Cost Adjustment (FCA) mechanism, which is described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

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

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

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

wholesale energy sales.

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

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

• Mitigation of Impact of Fuel and Purchased Power Expense:

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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.

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

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

• Regulatory and Environmental Compliance Costs;

Coal Plant Retirements:

Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council.

Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs.

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.

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.

Moreover, environmental laws and regulations may increase the cost of constructing new facilities, may increase the cost of operating generation plants, may require that Idaho Power install additional pollution control devices at existing generating plants, may result in penalties for non-compliance, even where inadvertent, or may require that Idaho Power curtail or cease operating certain generation plants.

Idaho Power expects to spend significant amounts on environmental compliance and controls for the foreseeable future.

Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its jointly-owned coal-fired generating plant in Valmy, Nevada (Valmy plant), ceasing coal-fired operations at one unit in 2019 and planning to cease its participation in coal-fired operations at the remaining unit by year-end 2025.

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

In June 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.

In June 2022, the IPUC approved Idaho Power's request to allow the coal-related assets at the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030.

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

• Water Management and Relicensing of Hydropower Projects:

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

Idaho Power cannot currently determine the ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls Facilities.

Idaho Power cannot currently determine the ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls hydroelectric facilities.

• Wildfire Mitigation Efforts:

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.

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

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

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

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

public safety power shutoff protocols;

public safety power shutoff protocols adopted in 2022;

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

In June 2021, 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.

In June 2021,

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

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

RESULTS OF OPERATIONS

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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.

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

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

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

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

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

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

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.

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

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

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

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

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

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(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.

(2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service.

Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.

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

Customer rates, excluding collections of amounts related to the power cost adjustment mechanisms, 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.

Customer rates, excluding collections of amounts related to the power cost adjustment mechanisms, increased retail revenues by $24.4 million in 2022 compared with 2021, due primarily to the June 1, 2022 rate increase for Idaho Power’s Idaho retail customers related to the Bridger Order.

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

Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which increased revenues by $70.3 million in 2022 compared with 2021.

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

• Customers :

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

Higher usage (on a per customer basis), in all customer classes, increased retail revenues by $27.2 million during 2021 compared with 2020.

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.

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.

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

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

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

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

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

• Idaho FCA Revenues:

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

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

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

This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is 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.

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

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

Wholesale Energy Sales :

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

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

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

Year Ended December 31,

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

Wholesale energy prices were higher compared with 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.

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

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

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

Transmission Wheeling-Related Revenues:

Revenue related to transmission wheeling increased $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.

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

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

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

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

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

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

At December 31, 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.

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

Operating Expenses

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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.

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

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

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

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

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.

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

Fuel Expense :

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

Fuel expense increased $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.

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

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

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

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

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

Included in fuel expense are losses and gains on settled financial gas hedges entered into in accordance with Idaho Power's energy risk management policy.

In 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.

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

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

Power Cost Adjustment Mechanisms :

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Year Ended December 31,

Power supply cost (deferral) accrual $ (22,036) $ 16,763

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

Oregon power supply cost deferral (1,079) —

Amortization of prior year authorized balances 17,414 (27,808)

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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.

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

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

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

The increases were primarily due to higher pre-tax earnings and other plant-related income tax return adjustments at Idaho Power.

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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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.

Cash capital expenditures, excluding AFUDC and net costs of removing assets from service, were $419 million in 2022 and $288 million in 2021.

Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $3.3 billion over the period from 2023 through 2027.

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

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

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

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

• their respective $100 million and $300 million revolving credit facilities;

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

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• Idaho Power's shelf registration statement filed with the SEC on May 16, 2022, which may be used for the issuance of first mortgage bonds and debt securities;

$190 million is available for issuance pursuant to state regulatory authority;

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

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

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

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.

As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue debt securities or first mortgage bonds, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent.

Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness.

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

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

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

Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions.

As of December 31, 2022, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:

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

IDACORP’s and Idaho Power’s operating cash inflows in 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;

• 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;

◦ 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.

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

With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from operating cash flows from Idaho Power.

Significant items that affected the companies' operating cash flows in 2022 when compared with 2021 were as follows:

• a $14 million and a $12 million increase in IDACORP and Idaho Power net income, respectively;

• changes in regulatory assets and liabilities, mostly related to the relative amounts of costs deferred and collected under the Idaho PCA, FCA, and energy efficiency program cost mechanisms, decreased operating cash inflows by $46 million;

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

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

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

◦ the changes in materials, supplies, and fuel stock decreased operating cash flows by $13 million for IDACORP and Idaho Power, which was primarily due to an increase in material and supply inventory offset by the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants;

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

◦ the changes in other assets and liabilities, which includes accrued paid time off and leave, customer deposits, accrued interest, and other miscellaneous liabilities, increased operating cash flows by $27 million for IDACORP and Idaho Power.

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction of and improvements to Idaho Power’s 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.

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

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

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

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

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

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

• IDACORP's investing cash outflows for 2022 and 2021 included $10 million and $15 million, respectively, of tax credit investments in affordable housing and other real estate, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits;

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

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

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

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed.

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;

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

IDACORP's and Idaho Power's net financing cash inflows for 2022 were $35 million and $78 million, respectively.

IDACORP funds its cash requirements, such as payment of taxes, payment of dividends, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities.

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

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

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

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

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

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

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

IDACORP issued no equity securities in 2022 other than under its equity compensation plans.

As described elsewhere in this MD&A, IDACORP has significant planned capital expenditures in the near-term, and the company could determine to issue equity during 2023, depending on market conditions, its financial and regulatory strategy, and other factors.

Term Loan Credit Agreement:

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

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

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

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

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

Idaho Power First Mortgage Bonds :

Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC).

In 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,

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 :

In May and June 2022, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders.

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

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

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

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

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

The first two tranches were issued on December 22, 2022, and Idaho Power has a commitment to issue the third and fourth tranches on March 8, 2023, each under the Indenture .

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

At December 31, 2022, $48 million in principal amount of Series N Notes had been issued and was outstanding.

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

IDACORP and Idaho Power Credit Facilities (Credit Facilities) :

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

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

The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or 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 interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 perc ent, or one-month SOFR rate plus 1.1 percent, or 0.0 percent, or (2) the Secured Overnight Financing Rate administered by the Federal Reserve Bank of New York (SOFR) Market Index rate, plus, in each case, an applicable margin, provided that

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

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

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

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

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 thing s.

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.

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

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

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter.

In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including,

in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement).

In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement).

“Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities.

At December 31, 2022, the leverage ratios for IDACORP and Idaho Power were 45 percent and 46 percent, respectively.

IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities.

IDACORP's and Idaho Power's ability to utilize their respective Credit Facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the Credit Facilities.

There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary.

At December 31, 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;

At December 31, 2022, IDACORP and Idaho Power believe they were in compliance with all of their respective Credit Facility covenants and, as of the date of this report, do not believe they will be in violation or breach of such covenants during 2023.

The events of default under the Credit Facilities include, without limitation, non-payment of principal, interest, or fees;

materially false representations or warranties;

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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.

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

IDACORP and Idaho Power Commercial Paper:

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Net balance available $ 100,000 $ 280,115 $ 100,000 $ 275,755

(1) Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.

(1) American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.

(2) Holding company only.

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

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

had commercial paper outstanding.

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

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

Impact of Credit Ratings on Liquidity and Collateral Obligations

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

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

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

IDACORP Idaho Power

Moody's Investors Service:

Rating Outlook Negative Negative

Long-Term Issuer Rating Baa1 A3

Rating Outlook Stable Stable

Long-Term Issuer Rating Baa2 Baa1

First Mortgage Bonds None A2

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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.

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

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

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

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

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

Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.

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

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

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

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

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

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

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

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The cash expenditure amount excludes net costs of removing assets from service.

The table below presents Idaho Power's estimated accrual-basis additions to electric plant for 2022 through 2026 (in millions of dollars).

The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2023 through 2027 (in millions of dollars).

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

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

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.

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

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

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

2023 2024 2025-2027

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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.

A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of relatively small projects as Idaho Power continues to add to its system to accommodate growth and maintain reliability and operational effectiveness.

These projects involve significant capital expenditures in the aggregate.

Examples of anticipated system enhancements planned for 2023 through 2027 and estimated costs include the following:

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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.

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.

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

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

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

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

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

Depending on factors such as RFP results, the timing of project in-service dates, estimated load and resource balances and customer growth, the nature and quantity of resources owned versus acquired under power purchase agreements or similar agreements, and the

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

Boardman-to-Hemingway Transmission Line :

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

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.

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

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

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

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

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

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

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

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

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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.

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.

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.

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.

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

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

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

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

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

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

Total cost estimates for the project are between $1.1 billion and $1.3 billion, including Idaho Power's AFUDC.

The capital requirements table above includes approximately $430 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining permitting phase, design, material procurement, and construction phases of the project.

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

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

and work commenced in the third quarter of 2021.

and that work commenced in the third quarter of 2021.

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

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

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

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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.

In 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project.

Idaho Power has expended approximately $52 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2022.

As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $300 million and $500 million, including AFUDC.

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 capital requirements table above includes approximately $40 million of Idaho Power's share of estimated costs (excluding AFUDC) for the permitting phase of the project and early construction costs, based on Idaho Power's current estimate that it may commence construction of applicable segments during that time period.

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

Bureau of Land Management (BLM).

The BLM has published its records of decision for all segments of the transmission line.

PacifiCorp recently constructed and commissioned a 140-mile segment of their portion of the project in Wyoming.

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

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

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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 t he 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.

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

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

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

In April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the

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

In April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date.

Environmental Regulation Costs:

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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.

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

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

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

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

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Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $40 million to the pension plan during 2023.

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

Beyond 2022, Idaho Power expects continuing significant contribution obligations under the pension plan.

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 2023, Idaho Power expects continuing contributions under the pension plan could be significant.

Refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.

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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.

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

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

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

Additionally,

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

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

Idaho Power develops its regulatory filings taking into consideration short-term and long-term needs for rate relief and several other factors that can affect the structure and timing of those filings.

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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.

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

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

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

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

Notable Retail Rate Changes in Idaho and Oregon

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2022 Idaho FCA 6/1/2022 (3)

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

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

2021 Idaho PCA 6/1/2021 39

2021 Idaho FCA 6/1/2021 3

Oregon North Valmy plant Exit Framework Settlement Stipulation 1/1/2020 (3)

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

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

The rate changes for the Idaho PCA and FCA are applicable only for one-year periods and represent the net change from the prior year's filing.

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

Idaho and Oregon General Rate Cases

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Other Notable Regulatory Matters

October 2014 Idaho Earnings Support and Sharing Settlement Stipulation :

In O ctober 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 desc ribed in "May 2018 Idaho Tax Reform Settlement Stipulation" of this MD&A.

May 2018 Idaho Tax Reform Settlement Stipulation:

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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.

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

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

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

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

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

In 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.

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

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

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

Idaho Power recorded the following amounts for sharing with customers under the December 2011 and October 2014 Idaho Settlement Stipulations and the May 2018 Idaho Tax Reform Settlement Stipulation (in millions):

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

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

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2011 - 2019 58.1 68.1 126.2

53.1 68.1 121.2

Total $ 58.7 $ 68.1 $ 126.8

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

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.

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

Valmy Base Rate Adjustment Settlement Stipulations:

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

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

Both commissions have approved this plan.

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

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

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

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

Jim Bridger Power Plant Rate Base Adjustment and Recovery:

In June 2022, the IPUC issued an order approving, with modifications, Idaho Power’s amended application requesting authorization to (1) accelerate depreciation for the Jim Bridger plant, to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (2) establish a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Order).The Bridger Order and associated accounting are described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.

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

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

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

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

Wildfire Mitigation Cost Deferral:

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

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

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

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

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

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

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

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

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

Fixed Cost Adjustment:

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

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

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

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

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

Integrated Resource Plan and Resource Procurement Filings:

Idaho Power filed its most recent IRP with the IPUC and OPUC in December 2021, 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.

Idaho Power filed its most recent IRP with the IPUC and OPUC in December 2021 and expects to file its next IRP during 2023, as described in Part 1, Item 1 - "Resource Planning and Renewable Energy Projects" in this report.

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

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

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

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

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

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

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

Customer-Owned Generation Filing:

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

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

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

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

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

The IPUC issued orders in December 2019 and February 2020 directing Idaho Power to (1) complete additional studies related to the costs and benefits of customer generation before changes to the compensation structure are implemented, and (2) continue to allow residential and small commercial customers with on-site generation installed prior to December 20, 2019, to be subject to the compensation and billing structure in place on that date until December 20, 2045.

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

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

In December 2021, the IPUC issued

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

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

Filings for Certificates of Public Convenience and Necessity

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

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

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

In December 2022, the IPUC issued an order:

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

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

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

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

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

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

Large Customer Rate Proceedings

Speculative High-Density Load :

In 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.

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

Idaho Power has received approximately 2,000 MW of potential customer interest from this industry and believes new system resources may be necessary to serve this speculative customer load, which could create a financial risk for Idaho Power and its customers if the underlying economics of cryptocurrency mining change.

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

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

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

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

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(1) rename its existing green power program;

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

(2) maintain and expand procurement options for the renewable energy credits (REC);

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

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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.

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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.

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.

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

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

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

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.

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.

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 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 Request s:

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.

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.

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:

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.

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

In November 2022, Idaho Power filed an application with the IPUC requesting approval for an arrangement under which Brisbie would purchase from Idaho Power energy generated by a to-be-constructed 200 MW solar facility pursuant to a long-term power purchase agreement between Idaho Power and a third party.

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

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

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

Micron Dedicated Renewable Resource :

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

The application included an arrangement under which Micron would be the purchaser from Idaho Power of the energy generated by a to-be-constructed 40-MW solar facility pursuant to a 20-year power purchase agreement between Idaho Power and a third party.

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

Idaho Power also requested in the application revised electric service rates for Micron that include new energy rates that incorporate the solar generation and compensation for capacity value and excess renewable energy generation.

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

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

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

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

Deferred Net Power Supply Costs

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

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

SO 2 allowance and renewable energy certificate (REC) sales

SO 2 allowance and REC sales

(7.0) (0.3) (7.3)

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Balance at December 31, 2022 $ 128.7 $ 0.6 $ 129.3

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, effect ive for the period from October 1, 2021, to September 30, 2022.

Open Access Transmission Tariff Rate

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

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

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

Idaho Power's final rate was based on a net annual transmission revenue requirement of $132.7 million.

The OATT rate in effect from October 1, 2020, to September 30, 2021, was $29.95 per kW-year based on a net annual transmission revenue requirement of $117.7 millio n.

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

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

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

net annual transmission revenue requirement of $127.3 mi llion.

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

Relicensing of Hydropower Projects

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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.

In December 2004, Idaho Power and eleven other parties involved in the HCC relicensing process, including National Marine Fisheries Service (NMFS) and U.S.

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

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

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

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

In 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

Oregon state law.

In connection with its relicensing efforts, Idaho Power filed annual water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards.

Challenges regarding how to meet water temperature standards below the HCC dam for spawning fall Chinook salmon, and a conflict in laws between Oregon and Idaho regarding the reintroduction and passage of fish above the HCC, delayed the issuance of the states' 401 certifications for several years.

In November 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the FPA pre-empts the Oregon state law requiring reintroduction and passage.

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

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

In February 2018, Idaho Power filed an appeal of the FERC's January 2017 order with the D.C.

Circuit Court, which is pending.

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

In April 2019, the states of Idaho and Oregon, along with Idaho Power, reached a settlement pertaining to the CWA Section 401 certification that requires Idaho Power, among other measures, to increase the number of Chinook salmon it releases each year through expanded hatchery production.

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

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

In December 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the settlement among Idaho, Oregon, and Idaho Power.

During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement, and its decision relating to the Offer of Settlement is pending as of the date of this report.

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.

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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.

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

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

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

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

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

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

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

As of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC, are likely to range from $30 million to $40 million until issuance of the license.

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

American Falls Relicensing:

In April 2020, the FERC formally initiated the relicensing 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.

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

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

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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

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.

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

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

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

Renewable Energy Standards and Contracts

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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.

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

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

An additional 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.

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

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

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

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

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

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Total non-PURPA 256 340 596

The projects not yet on-line include one PURPA-qualifying fac ility hydropower project that is scheduled to be on-line in 2022, two PURPA-qualifying fac ility 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.

certain QFs can enter into purchase agreements with utilities, and how parties can contest the eligibility of a generation facility seeking QF status.

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

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

In 2020, the FERC issued Order No.

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

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

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ENVIRONMENTAL MATTERS

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act (CAA) 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.

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

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

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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.

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

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

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Given the uncertainty of future environmental regulations and technological advances, there is uncertainty around near-term estimates, and Idaho Power is also unable to predict its environmental-related expenditures beyond 2025, though they could be substantial.

Furthermore, several executive orders issued since 2017 concerning environmental regulations, including executive orders issued by the current Presidential Administration in 2021, as described below, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters.

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

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

Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or 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.

Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or conversions, or reduction or elimination of permitting requirements.

More strict or robust regulations, or additional regulations, on the other hand, would likely increase Idaho Power's costs of operating and maintaining its facilities, and could impact Idaho Power's plans and pre-construction activities related to its major transmission projects, which could lead to substantially higher construction and permitting costs and could delay construction.

Executive orders may be affected by Congressional action and challenged in court.

Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level, and therefore, Idaho Power is uncertain whether and to what extent the orders could affect its operations, and environmental-related expenditures.

Therefore, as of the date of this report, and except as specifically described below in this MD&A, Idaho Power is uncertain whether and to what extent the orders, any future executive orders, and the implementation of these and any future executive orders could affect its business, results of operations, and financial condition.

Idaho Power plans to continue to monitor actions associated with or resulting from executive orders.

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

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

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.

Over the past few years and as a result of changes in Presidential Administrations, regulatory developments and executive orders have called into question the existing requirements under the ESA.

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

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

There are a number of threatened or endangered species within Idaho Power's service area located in waterways in which Idaho Power has hydropower facilities, and within or near proposed transmission line routes.

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

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.

In 2016, a group of lawsuits were filed in federal court to challenge the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act.

The lawsuits challenge the plans and associated EISs across the sage grouse range, including in Idaho and North Dakota, and allege that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates.

Further, the lawsuits challenge certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects.

Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans.

If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction.

In 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.

Following a series of interim measures, in February 2022, the BLM issued a notice of intent to amend its land use plans regarding sage grouse conservation and prepare associated EISs, soliciting public comments on the planning initiative.

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

As of the date of this report, the above lawsuits are stayed as the parties and the courts have agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for the lawsuits.

Migratory Bird Treaty Act Matters:

In 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.

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

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

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

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

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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.

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

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

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

As of the date of this report, Idaho Power anticipates that the final biological opinions will likely be issued in 2024 after the FERC issues a final supplemental EIS, which is scheduled for December 2023 according to the FERC's notice of intent.

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

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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.

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

As of the date of this report, Idaho Power is uncertain whether such increases will be significant.

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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.

National Environmental Policy Act (NEPA) Matters

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

NEPA applies to Idaho Power’s transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions.

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.

In April 2022, the current Presidential Administration’s Council on Environmental Quality (CEQ) published a final rule that restores a prior NEPA requirement, eliminated under the previous Administration, that federal agencies consider all indirect and cumulative environmental impacts of infrastructure projects in their decision-making, among other things, which could delay and increase the cost of Idaho Power’s infrastructure projects.

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

Climate Change and the Regulation of Greenhouse Gas Emissions

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

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

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

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• 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;

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

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

Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing carbon dioxide (CO 2 ) emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven .

Stringent emissions standards could result in significant increases in capital expenditures and operating costs, which may accelerate the retirement of coal-fired units and create power system reliability issues.

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 a result, Idaho Power ended its participation in coal-fired operations at the Boardman power plant in October 2020 and the North Valmy plant unit 1 in December 2019 .

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

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

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

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

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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.

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

A more detailed discussion of legislative and regulatory developments related to climate change follows.

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In August 2015, the EPA promulgated the Clean Power Plan (CPP) under Section 111(d) of the CAA, which required states to adopt plans to collectively reduce 2005 levels of power sector CO 2 emissions by 32 percent by the year 2030.

In June 2019, the EPA 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 June 2019, the EPA repealed the CPP and replaced it with the Affordable Clean Energy (ACE) rule under Section 111(d) of the CAA for existing electric utility generating units.

In January 2021, the U.S.

Court of Appeals for the District of Columbia Circuit vacated the 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

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.

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

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

On June 30, 2022, the U.S.

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

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

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

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

Oregon imposes GHG emission reporting requirements on facilities emitting 2,500 metric tons or more of CO 2 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 legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was also enacted in March 2016, and requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030.

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

To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base.

The State of Idaho has not passed legislation specifically regulating GHGs.

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.

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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, 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 ."

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

Idaho Power and the co-owners of Jim Bridger and North Valmy coal-fired generating plants have installed mercury continuous emission monitoring systems on all coal-fired units at the plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule.

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

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

These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide (NO 2 ), and sulfur dioxide (SO 2 ).

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:

In 2010, the EPA adopted a new NAAQS for NO 2 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 NO 2 .

In 2010, the EPA adopted a new NAAQS for SO 2 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 SO 2 NAAQS because of a lack of

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 SO 2 standard.

Since January 2018, the EPA has finalized designations of “unclassifiable/attainment” for SO 2 for all areas in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant.

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:

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

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

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

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

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

This includes all units at the Jim Bridger plant.

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 (NO x ) 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 NO x 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 NO x 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 NO x and SO 2 and an annual total emissions cap for NO x and SO 2 for units 1-4.

In May 2020, the WDEQ approved the alternative plan as proposed, which would eliminate the requirement to install add-on NO x controls at Jim Bridger units 1 and 2.

In September 2021, PacifiCorp submitted its IRP to the IPUC that co ntemplates 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.

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

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

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

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

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

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.

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

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

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

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

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

Section 401 Water Quality Certification:

As described more fully under “Relicensing of Hydropower Projects” in the "Regulatory Matters" section of this MD&A, Idaho Power filed water quality certification applications, required under Section 401 of the CWA, with 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.

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

The states issued final certifications in May 2019.

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

The rule 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.

The rule has been subject to various legal challenges, and the EPA under the current Presidential

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

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

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.

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

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

CWA Permitting:

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

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

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

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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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).

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

The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived.

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Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2022, with maturities matching the projected cash outflows of the plans.

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

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

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

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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 2023 pension expense will be 7.4 percent, the same assumption as used in 2022.

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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.

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

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

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What changed 10-K

Item 7. Management’s Discussion and Analysis