In MD&A in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. While reading this MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report. This discussion updates the MD&A included in the 2025 Annual Report, and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year, particularly in light of the seasonality of Idaho Power's sales volumes, as discussed below. INTRODUCTION IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the IPUC, OPUC, and FERC. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity. Idaho Power experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. Idaho Power is the parent of IERCo, a joint-owner of BCC, which mines and supplies coal to the Jim Bridger plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IFS, an investor in affordable housing and other real estate tax credit investments, and Ida-West, an operator of small PURPA-qualifying hydropower generation projects. EXECUTIVE OVERVIEW Management's Outlook and Company Objectives In the 2025 Annual Report, IDACORP's and Idaho Power's management included a summary of their business objectives for the companies for 2026 and beyond, under the heading "Executive Overview" in the MD&A. As of the date of this report, management's outlook and strategy remain consistent with that discussion, as updated by the discussion in this MD&A. Some notable developments that have occurred since that report include the following: •Idaho Power continues to experience and forecast positive customer growth in its service area. During the twelve months ended June 30, 2026, Idaho Power's customer count grew by approximately 15,000 customers and the customer growth rate was 2.3 percent. •So far in 2026, Idaho Power has taken important actions and several key projects achieved notable milestones, underscoring significant progress towards addressing Idaho Power's growing capacity and energy needs in 2026 and beyond: ◦In March, Idaho Power filed a CPCN request for a 222 MW natural gas-fueled facility, with an expected in-service date in 2029, and for a 430 MW natural gas-fueled facility, with an expected in-service date in 2030. As of the date of this report, the CPCN request remains subject to regulatory approval. ◦Also in March, the IPUC approved Idaho Power's agreement to purchase the output of an 80 MW solar facility, with a scheduled online date of June 2027, and Idaho Power's CPCN request for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant, with an expected in-service date in 2028. Construction commenced at the Bennett Mountain power plant in May 2026. ◦In April, Idaho Power, jointly with co-owner PacifiCorp, filed a CPCN request for Segment E-8 for the GWW transmission line, with an expected in-service date for the entire segment in 2030 or later. As of the date of this report, the CPCN request remains subject to regulatory approval. ◦In June, Idaho Power filed an application with the IPUC for an order approving a 20-year PPA with Bluebird Solar Project LLC, supplying up to 200 MW of output to Idaho Power, along with a 20-year energy storage system tolling agreement for 100 MW of dispatchable energy storage capacity. Both are expected to be in-service by June 2028. As of the date of this report, the application remains subject to regulatory approval. ◦The conversion of unit 2 at the North Valmy power plant from coal to natural gas was completed in June, ending all coal-fired generation at the plant. ◦Also in June, the Hemingway expansion and Boise Bench battery energy storage systems became fully operational, adding 250 MW of energy storage. ◦Construction commenced in June on SWIP-N, a 285-mile high voltage transmission line, with an expected in-service date in 2028. 40 Table of Contents ◦In July, Idaho Power began stringing transmission line wire on B2H and continues to expect an in-service date for B2H in late 2027. Summary of Financial Results The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share (in thousands of dollars or shares, except earnings per share amounts): Three months ended June 30, Six months ended June 30, 2026 2025 2026 2025 Idaho Power net income $ 101,276 $ 92,838 $ 167,934 $ 150,966 Net income attributable to IDACORP, Inc. $ 102,577 $ 95,781 $ 170,558 $ 155,428 Weighted average outstanding shares – diluted 57,229 54,380 56,767 54,249 IDACORP, Inc. earnings per diluted share $ 1.79 $ 1.76 $ 3.00 $ 2.87 The table below provides a reconciliation of net income attributable to IDACORP for the three months and six months ended June 30, 2026, from the same periods in 2025 (items are in millions of dollars and are before related income tax impact unless otherwise noted): Three months ended Six months ended Net income attributable to IDACORP, Inc. - June 30, 2025 $ 95.8 $ 155.4 Increase (decrease) in Idaho Power net income: Retail revenues per MWh, excluding large contract customers, net of power cost adjustment mechanisms 27.5 44.0 Customer growth, excluding large contract customers, net of associated power supply costs and power cost adjustment mechanisms 4.5 8.2 Usage per retail customer, excluding large contract customers, net of associated power supply costs and power cost adjustment mechanisms (0.1) (12.4) Idaho fixed cost adjustment (FCA) revenues 2.7 21.8 Retail revenues from large contract customers, net of associated power supply costs and the PCA mechanism 6.5 8.9 Other O&M expenses (11.7) (24.8) Depreciation and amortization expense (5.2) (10.9) Other changes in operating revenues and expenses, net 6.3 22.0 Increase in Idaho Power operating income 30.5 56.8 Non-operating expense, net (0.5) (4.6) Additional ADITC amortization (17.2) (30.2) Income tax expense, excluding additional ADITC amortization (4.4) (5.0) Total increase in Idaho Power net income 8.4 17.0 Other IDACORP changes (net of tax) (1.6) (1.8) Net income attributable to IDACORP, Inc. - June 30, 2026 $ 102.6 $ 170.6 Net Income - Second Quarter 2026 IDACORP's net income increased $6.8 million for the second quarter of 2026 compared with the second quarter of 2025, due primarily to higher net income at Idaho Power. The net increase in retail revenues per MWh, excluding large contract customers, and net of power cost adjustment mechanisms, increased operating income by $27.5 million in the second quarter of 2026 compared with the second quarter of 2025. This benefit was due primarily to an overall increase in Idaho base rates, effective January 1, 2026, from the outcome of the 2025 Settlement Stipulation. For more information on the 2025 Settlement Stipulation, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. 41 Table of Contents Customer growth, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $4.5 million in the second quarter of 2026 compared with the second quarter of 2025, as the number of Idaho Power customers grew by approximately 15,000, or 2.3 percent, during the twelve months ended June 30, 2026. Usage per retail customer, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, was relatively consistent in the second quarter of 2026 compared with the second quarter of 2025, as a 2 percent decrease in usage per residential customer was mostly offset by an increase in usage per customer for irrigation customers. A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $2.7 million. Retail revenues from large contract customers, net of associated power supply costs and the PCA mechanism, increased operating income by $6.5 million in the second quarter of 2026 compared with the second quarter of 2025. This benefit was primarily due to an increase in usage per large contract customer, the overall increase in Idaho base rates effective January 1, 2026, and the addition of one new large contract effective June 1, 2026. Other O&M expenses in the second quarter of 2026 were $11.7 million higher than the second quarter of 2025. This increase was primarily the result of previously deferred costs related to the conversion of generating units at the Jim Bridger plant from coal to natural gas, much of which is recovered in customer rates and reflected in revenues pursuant to the 2025 Settlement Stipulation. The amortization of previously deferred wildfire mitigation program expenses, which are also recovered in customer rates and reflected in revenues for both the Idaho and Oregon jurisdictions, also contributed to the increase from the second quarter of 2025. Depreciation and amortization expense increased $5.2 million in the second quarter of 2026 compared with the second quarter of 2025, due primarily to an increase in plant-in-service. Other changes in operating revenues and expenses, net, increased operating income by $6.3 million in the second quarter of 2026 compared with the second quarter of 2025, due primarily to a decrease in net power supply expenses that were not accrued for future refund in rates through Idaho Power's power cost adjustment mechanisms. Also contributing to the increase in other changes in operating revenues and expenses, net, was a decrease in property tax expense due to property tax legislative changes in Idaho. Non-operating expense, net, increased $0.5 million in the second quarter of 2026 compared with the second quarter of 2025. Higher long-term debt balances led to an increase in interest expense, while lower interest-bearing cash investments led to a decrease in interest income. This increase was mostly offset by an increase in AFUDC in the second quarter of 2026 compared with the second quarter of 2025, as the average construction work in progress balance was higher. The increase in income tax expense for the second quarter of 2026, compared with the second quarter of 2025, was primarily due to a decrease in additional ADITC amortization under the Idaho regulatory settlement stipulation and an increase in pre-tax income. Based on Idaho Power's current expectations of full-year 2026 financial results, Idaho Power recorded no additional ADITC amortization during the second quarter of 2026, compared with $17.2 million of additional ADITC amortization during the second quarter of 2025. Net Income - Year-To-Date 2026 IDACORP's net income increased $15.2 million for the first six months of 2026 compared with the first six months of 2025, due primarily to higher net income at Idaho Power. The net increase in retail revenues per MWh, excluding large contract customers, and net of power cost adjustment mechanisms, increased operating income by $44 million in the first six months of 2026 compared with the first six months of 2025. This benefit was due primarily to an overall increase in Idaho base rates, effective January 1, 2026, from the outcome of the 2025 Settlement Stipulation. Customer growth, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $8.2 million in the first six months of 2026 compared with the first six months of 2025. Usage per retail customer, excluding large contract customers, and net of associated power supply costs and power cost adjustment mechanisms, decreased operating income by $12.4 million in the first six months of 2026 compared with the first six months of 2025. Residential usage per customer decreased most significantly, as more moderate temperatures in the first six months of 2026 compared with the first six months of 2025 led residential customers to use less energy for heating and cooling purposes. A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $21.8 million. 42 Table of Contents Retail revenues from large contract customers, net of associated power supply costs and the PCA mechanism, increased operating income by $8.9 million in the first six months of 2026 compared with the first six months of 2025. This change was primarily due to an increase in usage per large contract customer, the overall increase in Idaho base rates effective January 1, 2026, and the addition of one new large contract effective June 1, 2026. Other O&M expenses in the first six months of 2026 were $24.8 million higher than the first six months of 2025. This increase was primarily the result of previously deferred costs related to the conversion of generating units at the Jim Bridger plant from coal to natural gas, much of which is recovered in customer rates and reflected in revenues pursuant to the 2025 Settlement Stipulation. The amortization of previously deferred wildfire mitigation program expenses, which are also recovered in customer rates and reflected in revenues for both the Idaho and Oregon jurisdictions, also contributed to the increase from the first six months of 2025. Depreciation and amortization expense increased $10.9 million for the first half of 2026 compared with the first half of 2025, due primarily to an increase in plant-in-service. Other changes in operating revenues and expenses, net, increased operating income by $22.0 million in the first six months of 2026 compared with the first six months of 2025, due primarily to a decrease in net power supply expenses that were not accrued for future refund in rates through Idaho Power's power cost adjustment mechanisms. Also contributing to the increase in other changes in operating revenues and expenses, net, was a decrease in property tax expense due to property tax legislative changes in Idaho. Non-operating expense, net, increased $4.6 million in the first six months of 2026 compared with the first six months of 2025. Higher long-term debt balances led to an increase in interest expense. This increase was partially offset by an increase in AFUDC in the first six months of 2026 compared with the first six months of 2025, as the average construction work in progress balance was higher. In addition, interest income decreased due to lower cash and cash equivalent balances in the first six months of 2026 compared with the first six months of 2025. The increase in income tax expense was principally the result of a decrease in additional ADITC amortization and higher pre-tax income. Based on Idaho Power's current expectations of full-year 2026 financial results, Idaho Power recorded $6.3 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during the first six months of 2026, compared with $36.5 million of additional ADITC amortization during the same period in 2025. Overview of General Factors and Trends Affecting Results of Operations and Financial Condition IDACORP's and Idaho Power's results of operations and financial condition are affected by several factors and trends, and the impact of those factors and trends is discussed in more detail below in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors and trends are as follows: •Regulatory Filings: The prices that Idaho Power is authorized to charge for its electric and transmission service are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power is focused on timely recovery of its costs through filings with its regulators and prudent management of expenses and investments. Idaho Power filed its most recent general rate case in Idaho in May 2025. The IPUC approved a settlement stipulation for the general rate case in December 2025, with rates effective January 1, 2026. The general rate case filing and the settlement stipulation are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. Idaho Power continues to evaluate the timing of its next general rate cases in Idaho and Oregon. •Rate Base Growth and Infrastructure Investment: The rates established by the IPUC, OPUC, and FERC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred income taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation of utility plant and write-offs as authorized by the IPUC and OPUC. Idaho Power is pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and provide service to new customers, including major ongoing transmission projects such as the 43 Table of Contents B2H, GWW, and SWIP-N projects. To help meet growing capacity and energy needs, Idaho Power is planning to construct three new natural gas-fired generating facilities with planned generation capacities of 167 MW, 222 MW, and 430 MW, and expected in-service dates in 2028, 2029, and 2030, respectively. Idaho Power also has RFPs outstanding for resources beyond those years. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company continues a significant relicensing effort for the HCC, its largest hydropower generation resource. Idaho Power intends to pursue timely inclusion of completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding, but the company incurs the cash requirements of constructing and the costs of financing those resources before they are in rates and customer revenues. Idaho Power expects its capital expenditures on infrastructure investments in the next five years or more will be considerable. For more information about forecasted capital expenditures and expected rate base growth, see the "Liquidity and Capital Resources" section of this MD&A. •Economic Conditions and Loads: 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. Over the twelve months ended June 30, 2026, Idaho Power's customer count grew by 2.3 percent. While recessionary or volatile economic conditions could slow the rate of customer growth, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase in the foreseeable future. This was visible during the second quarter of 2026, with an increase in industrial loads and revenues over the prior year's second quarter driven by the ramp-up in electric service and in revenues by two large load customers. Idaho Power expects these customers, together with other large load industrial customers, to ramp up operations further during the remainder of 2026 and for the next several years. Idaho Power is in the process of discussing and negotiating terms, conditions, and pricing of potential service agreements with several additional large load customers. Idaho Power's 2025 IRP assumed a forecasted annual growth in retail MWh sales of 8.3 percent and a forecasted annual growth in peak-hour demand of 5.1 percent over the upcoming 5-year period. For more information on the 2025 IRP, refer to "Resource Planning" in Item 1 - "Business" of the 2025 Annual Report. Customer growth has contributed to increases in peak loads experienced in recent years. For example, Idaho Power's highest all-time winter peak demand of 2,719 MW occurred on January 16, 2024, and on July 22, 2024, Idaho Power reached a new all-time summer peak demand of 3,793 MW. Idaho Power believes that existing and sustained growth in customers, load, and demand for electricity, the obligation to maintain a safe and reliable system, along with changes in the regional transmission markets that have constrained the availability of transmission outside Idaho Power’s service area to import energy during peak load periods, require Idaho Power to increase its investment in capacity resources, transmission, and distribution infrastructure. For more information on Idaho Power's system investments and resource procurements, see "Liquidity and Capital Resources" in this MD&A. Idaho Power has begun preparation of its 2027 IRP and expects to prepare an updated load forecast during 2026 as the basis for the 2027 IRP, which Idaho Power expects to file in the summer of 2027. •Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters of each year, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the condensed 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 variability is addressed through the Idaho and Oregon power cost adjustment mechanisms, which mitigate in large part the impact on earnings. For 2026, as of the 44 Table of Contents date of this report, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 6.5 million MWh, compared with actual generation of 7.0 million MWh in 2025 and a 20-year average annual total of approximately 7.3 million MWh. •Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies significantly on natural gas and coal to fuel its generation facilities, long-term PPAs (including PURPA agreements), and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, generation resource maintenance outages, wholesale energy market prices, transmission availability, and the outcome of Idaho Power's hedging programs. 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. •Wildfire Mitigation Efforts: In recent years, the western United States has experienced severe wildfires. A variety of factors have contributed to this trend including increased wildland-urban interfaces, historical land management practices, climate change, and overall wildland and forest conditions. Idaho Power is taking a proactive approach to wildfire risk in its service area and transmission corridors. Several years ago, Idaho Power adopted a WMP that outlines actions Idaho Power is taking or is working to implement to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires, and Idaho Power has refined that WMP over time. Idaho Power's approach to wildfire mitigation includes identifying areas subject to elevated risk; system hardening programs, vegetation management, and field personnel practices to mitigate wildfire risk; incorporating current and forecasted weather and field conditions into operational practices; public safety power shutoff protocols; and evaluating the performance and effectiveness of its approach through metrics and monitoring. Idaho Power has regulatory authorization in both Idaho and Oregon to defer, for potential future amortization, certain actual incremental O&M expenses necessary to implement the WMP. The WMP regulatory deferrals are described in more detail in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report and the condensed consolidated financial statements included in this report. In October 2025, Idaho Power filed a new WMP with the IPUC in accordance with Idaho's new Wildfire Standard of Care Act, and in April 2026, the IPUC issued an order approving the WMP. In December 2025, Idaho Power filed its 2026-2028 WMP with the OPUC, and in June 2026, the OPUC issued an order approving the WMP. See "Other Matters - Idaho Wildfire Standard of Care Act" included in the 2025 Annual Report, for additional details. 45 Table of Contents RESULTS OF OPERATIONS This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three months and six months ended June 30, 2026. In this analysis, the results for the three months and six months ended June 30, 2026, are compared with the same periods in 2025. The table below presents Idaho Power’s energy sales and supply (in thousands of MWh). Three months ended June 30, Six months ended June 30, 2026 2025 2026 2025 Retail energy sales 4,227 4,099 7,852 7,822 Wholesale energy sales 127 598 219 1,037 Energy sales bundled with renewable energy credits 30 75 80 615 Total energy sales 4,384 4,772 8,151 9,474 Hydropower generation 1,594 2,144 3,154 4,268 Jointly-owned thermal generation(1) 489 462 914 1,136 Natural gas and other generation 611 753 1,386 1,527 Total system generation 2,694 3,359 5,454 6,931 Purchased power 1,888 1,732 3,190 3,208 Line losses (198) (319) (493) (665) Total energy supply 4,384 4,772 8,151 9,474 (1) "Jointly-owned thermal generation" consists of generation from steam plants that include coal-fired units as well as natural gas-fired units that were converted from coal. Weather-related information for Boise, Idaho, is presented in the table below. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service area, the greater Boise area has the majority of Idaho Power's customers and is included for illustrative purposes. Three months ended June 30, Six months ended June 30, 2026 2025 Normal (2) 2026 2025 Normal (2) Heating degree-days(1) 531 566 685 2,563 2,982 3,087 Cooling degree-days(1) 200 281 188 201 281 188 Precipitation (inches) 4.7 1.4 3.4 7.3 6.5 7.2 (1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and cooling. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day. (2) Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The normal amounts are the sum of the monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration. Sales Volume and Generation: Total energy sales volumes decreased 8 percent and 14 percent for the second quarter and first six months of 2026, respectively, compared with the same periods in 2025. The decrease in total energy sales volumes was primarily due to lower wholesale energy sales and lower energy sales bundled with renewable energy credits, offset partially by the increase in retail sales volumes. Retail sales volumes increased 3 percent for the second quarter of 2026 compared with the second quarter in 2025, primarily due to customer growth as the number of Idaho Power's customers grew by 2.3 percent over the prior twelve months. Retail sales volumes were relatively consistent in the first six months of 2026, compared with the same period in 2025, as the customer growth was mostly offset by lower usage per customer from more moderate weather in the first few months of 2026. For more information on the changes in sales volumes, see the "Operating Revenues" section below in this MD&A. Total system generation decreased 20 percent for the second quarter of 2026, compared with the second quarter of 2025, due primarily to lower hydropower generation and natural gas generation, partially offset by an increase in jointly-owned thermal generation. Total system generation decreased 21 percent in the first six months of 2026 compared with the same period in 46 Table of Contents 2025, due to lower hydropower generation, jointly-owned thermal generation, and natural gas generation. For more information on the changes in generation, see the "Operating Expenses" section below in this MD&A. The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms." Operating Revenues Retail Revenues: The table below presents Idaho Power’s retail revenues (in thousands of dollars), MWh sales volumes (in thousands of MWh), and the number of retail customers. Three months ended June 30, Six months ended June 30, 2026 2025 2026 2025 Retail revenues: Residential (includes ($153), ($2,876), $16,484 and ($5,069), respectively, related to the FCA)(1) $ 168,764 $ 149,355 $ 372,360 $ 340,060 Commercial (includes ($10), ($36), $196, and ($80), respectively, related to the FCA)(1) 98,773 94,652 195,429 192,504 Industrial 76,081 64,840 145,684 133,446 Irrigation 97,306 92,370 99,247 93,482 Deferred revenue related to HCC relicensing AFUDC(2) (8,521) (1,930) (17,635) (3,993) Total retail revenues $ 432,403 $ 399,287 $ 795,085 $ 755,499 Volume of retail sales (MWh) Residential 1,274 1,270 2,834 2,972 Commercial 1,035 1,036 2,088 2,111 Industrial 968 898 1,954 1,832 Irrigation 950 895 976 907 Total retail MWh sales 4,227 4,099 7,852 7,822 Number of retail customers at period end Residential 567,106 553,665 Commercial 81,704 80,363 Industrial 151 148 Irrigation 22,699 22,597 Total customers 671,660 656,773 (1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers. (2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process in its Idaho jurisdiction, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Effective October 1, 2025, Idaho Power began collecting $38.5 million annually. Prior to October 1, 2025, Idaho Power collected $8.8 million annually. For more information refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. Amounts collected in the Idaho jurisdiction are recognized as deferred revenue until the license is issued and the accumulated license costs approved for recovery are placed in service. Changes in rates, changes in customer demand, customer growth, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. The primary influences on customer demand for electricity are weather, economic conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while moderate temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted, providing for higher rates during summer peak load periods, and residential customer rates are tiered, providing for higher rates based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings. Retail revenues increased $33.1 million and $39.6 million during the second quarter and first six months of 2026, respectively, compared with the same periods in 2025. The factors affecting retail revenues during the periods are discussed below. •Rates: Customer rates, excluding revenues related to large contract customers, and power cost adjustment mechanisms, increased retail revenues by $27.5 million and $44.0 million, respectively, for the three months and six months ended 47 Table of Contents June 30, 2026, compared with the same periods in 2025. This was due primarily to an overall increase in Idaho base rates, effective January 1, 2026, from the outcome of the 2025 Settlement Stipulation. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which decreased revenues by $13.1 million and $30.9 million in the second quarter and first six months of 2026, respectively, compared with the same periods of 2025. The amount collected from customers in rates under the power cost adjustment mechanisms has relatively little effect on operating income as a corresponding amount is recorded as expense in the same period it is collected through rates. •Customers: Customer growth of 2.3 percent during the twelve months ended June 30, 2026, increased retail revenues, excluding large contract customers, by $6.3 million and $11.5 million in the second quarter and first six months of 2026, respectively, compared with the same periods of 2025. •Usage: Usage (on a per customer basis), excluding large contract customers, was relatively consistent in the second quarter of 2026, compared with the second quarter of 2025, as a 2 percent decrease in usage per residential customer was offset by an increase in usage per customer for irrigation customers and changes in customer mix. Lower usage per customer decreased retail revenues by $18.6 million in the first six months of 2026, compared with the same period of 2025, primarily due to weather variations. Usage per residential and commercial customers decreased most significantly, as more moderate temperatures in the first half of 2026 compared with the first half of 2025 led these customers to use less energy for heating and cooling purposes. These decreases were partially offset by increases in usage per irrigation and industrial customers, as distribution of rainfall in May and June of 2026 compared with the same months of 2025 led irrigation customers to use more energy for operating irrigation pumps. •FCA Mechanism: A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $2.7 million and $21.8 million in the second quarter and first six months of 2026, respectively, compared with the same periods of 2025. •Large Contract Customers: Retail revenues from large contract customers increased $9.7 million and $11.8 million during the second quarter and first six months of 2026, respectively, compared with the same periods of 2025. The increases were primarily due to an increase in usage per large contract customer, the overall increase in Idaho base rates effective January 1, 2026, and the addition of one new large contract effective June 1, 2026. 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 (in thousands of dollars or MWh, except for revenue per MWh amounts). Three months ended June 30, Six months ended June 30, 2026 2025 2026 2025 Wholesale energy revenues $ 3,559 $ 15,376 $ 8,371 $ 34,924 Wholesale MWh sold 127 598 219 1,037 Wholesale energy revenues per MWh $ 28.02 $ 25.71 $ 38.22 $ 33.68 In the second quarter and first six months of 2026, wholesale energy revenues decreased $11.8 million and $26.6 million, respectively, compared with the same periods of 2025, due primarily to a decrease in wholesale energy volumes sold, partially due to milder winter and spring weather resulting in lower demand in the regional energy market. Lower prices in the energy imbalance market led to less trading activity, which also contributed to the decrease in wholesale energy volumes sold. The financial impacts of fluctuations in wholesale energy sales are largely mitigated by Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in this section of the MD&A under "Power Cost Adjustment Mechanisms." 48 Table of Contents Operating Expenses Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes (in thousands of dollars or MWh, except for per MWh amounts). Three months ended June 30, Six months ended June 30, 2026 2025 2026 2025 Purchased power expense $ 90,455 $ 88,777 $ 155,536 $ 162,887 MWh purchased 1,888 1,732 3,190 3,208 Average cost per MWh $ 47.91 $ 51.26 $ 48.76 $ 50.78 Purchased power expense increased $1.7 million, or 2 percent, in the second quarter of 2026 compared with the second quarter of 2025, due to a 9 percent increase in MWh purchased to meet load, offset partially by lower market prices. Purchased power expense decreased $7.4 million, or 5 percent, in the first six months of 2026, compared with the same period of 2025, due to lower wholesale energy market prices in the region. Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation (in thousands of dollars or MWh, except for per MWh amounts). Three months ended June 30, Six months ended June 30, 2026 2025 2026 2025 Fuel Expense Jointly-owned thermal(1) $ 14,690 $ 16,815 $ 31,755 $ 47,732 Natural gas(2) 13,633 18,030 60,297 56,514 Total fuel expense $ 28,323 $ 34,845 $ 92,052 $ 104,246 MWh generated Jointly-owned thermal(1) 489 462 914 1,136 Natural gas(2) 611 753 1,386 1,527 Total MWh generated 1,100 1,215 2,300 2,663 Average cost per MWh - Jointly-owned thermal $ 30.04 $ 36.40 $ 34.74 $ 42.02 Average cost per MWh - Natural gas $ 22.31 $ 23.94 $ 43.50 $ 37.01 Weighted average, all sources $ 25.75 $ 28.68 $ 40.02 $ 39.15 (1) "Jointly-owned thermal" consists of expenses and generation from steam plants that include coal-fired units as well as natural gas-fired units that were converted from coal. (2) Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant. The majority of the fuel for Idaho Power’s jointly-owned thermal plants is purchased through long-term contracts, including coal purchases from BCC, a one-third owned investment of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies the majority of the coal used by the Jim Bridger plant and BCC does not have significant sales to third parties. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods. Fuel expense decreased $6.5 million, or 19 percent, and $12.2 million, or 12 percent, in the second quarter and first six months of 2026, respectively, compared with the same periods of 2025. The decrease in fuel expense in the second quarter of 2026 compared with the second quarter of 2025 was primarily due to a 10 percent decrease in the total average cost per MWh from all sources and a 19 percent decrease in natural gas generation, partially offset by a 6 percent increase in jointly-owned thermal generation. The decrease in fuel expense in the first six months of 2026 compared with the same period of 2025 was primarily due to a 14 percent decrease in total MWh generated from jointly-owned thermal and natural gas facilities, partially offset by a 2 percent increase in the total average cost per MWh from all sources. 49 Table of Contents 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. For the second quarters and first six months of 2026 and 2025, losses on financial gas hedges of $1.1 million and $0.5 million, and $27.6 million and $12.7 million, respectively, increased natural gas fuel expense. Most of these realized hedging losses are passed on to customers through the power cost adjustment mechanisms described below. Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Variability of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the variability of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases, export credit mechanisms, capital lease payments associated with battery energy storage systems, and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred or accrued during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Because of the power cost adjustment mechanisms, the primary financial impact of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year. The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms (in thousands of dollars). Three months ended June 30, Six months ended June 30, 2026 2025 2026 2025 Idaho power supply cost accrual $ 24,598 $ 19,493 $ 26,954 $ 48,937 Oregon power supply cost accrual (deferral) — 863 — (1,794) Amortization of prior year authorized balances (15,706) 8,221 (27,355) 29,119 Total power cost adjustment (income statement) $ 8,892 $ 28,577 $ (401) $ 76,262 The power supply accruals (deferrals) represent the portion of the power supply cost fluctuations accrued (deferred) under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. During the second quarter and first six months of 2026, lower purchased power and fuel costs led to lower actual power supply costs compared with the forecasted amount, which resulted in an accrual of power supply costs by the mechanism. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior PCA year (the balancing adjustment component of the power cost adjustment mechanism). Other O&M Expenses: Other O&M expenses increased $11.7 million and $24.8 million in the second quarter and first six months of 2026, respectively, compared with the same periods of 2025. This increase was primarily the result of previously deferred costs related to the conversion of generating units at the Jim Bridger plant from coal to natural gas, much of which is recovered in customer rates and reflected in revenues pursuant to the 2025 Settlement Stipulation. The amortization of previously deferred wildfire mitigation program expenses, which are also recovered in customer rates and reflected in revenues for both the Idaho and Oregon jurisdictions, also contributed to the increases from the second quarter and first six months of 2025. Income Taxes IDACORP's and Idaho Power's income tax expense increased $33.8 million and $35.2 million, respectively, for the six months ended June 30, 2026, when compared with the same period in 2025, primarily due to decreased ADITC amortization from the regulatory mechanism described in Note 3 – “Regulatory Matters” to the condensed consolidated financial statements included in this report, and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. Higher pre-tax income also contributed to the increase in income tax expense in the first six months of 2026, compared with the same period in 2025. For information relating to IDACORP's and Idaho Power's computation of income tax expense, see Note 2 - "Income Taxes" to the condensed consolidated financial statements included in this report. 50 Table of Contents LIQUIDITY AND CAPITAL RESOURCES Overview 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 files for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators. IDACORP may issue debt securities or common stock, and Idaho Power may issue first mortgage bonds or other debt securities to fund its business. Idaho Power also periodically evaluates whether partial or full early redemption of one or more outstanding series of first mortgage bonds is desirable and, in some cases, may refinance existing indebtedness with new indebtedness. As of July 24, 2026, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included the following: •their respective $100 million and $400 million revolving credit facilities; •their issuance of commercial paper, with program sizes of $100 million and $300 million, respectively. Idaho Power's commercial paper program may be increased up to the $400 million capacity of its credit facility; •IDACORP's shelf registration statement filed with the SEC on February 21, 2025, which may be used for the issuance of debt securities and common stock; •IDACORP's executed FSAs under its 2024 ATM, which may be physically settled with common stock in exchange for net proceeds, which as of July 24, 2026, would have been approximately $154 million; •IDACORP's executed FSAs under its 2026 ATM, which may be physically settled with common stock in exchange for net proceeds, which as of July 24, 2026, would have been approximately $262 million; •IDACORP's FSAs, executed outside of its ATMs, which may be physically settled with common stock in exchange for net proceeds, which as of July 24, 2026, would have been approximately $299 million; and •Idaho Power's shelf registration statement filed with the SEC on February 21, 2025, which may be used for the issuance of first mortgage bonds and other debt securities; $1.5 billion is available for issuance pursuant to state regulatory authority. IDACORP uses original issuances of shares for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan. Effective July 1, 2026, IDACORP began using original issuances for share purchases within the Idaho Power Company Employee Savings Plan. IDACORP may discontinue using original issuances of shares for these plans at any time. In February 2026, Idaho Power issued $350 million in first mortgage bonds. In July 2026, Idaho Power repaid $116 million in aggregate principal amount of maturing pollution control revenue bonds. For more detailed information about Idaho Power's long-term debt transactions, see Note 5 - "Long-Term Debt" to the condensed consolidated financial statements included in this report. In March 2026, IDACORP executed FSAs under its 2024 ATM with various counterparties at an aggregate gross sales price of $155 million. In addition, IDACORP settled FSAs under its 2024 ATM, resulting in cash proceeds of $52 million. In May 2026, IDACORP executed FSAs under its 2026 ATM with various counterparties at an aggregate gross sales price of $149 million. In addition, IDACORP partially settled an FSA executed outside of its ATMs, resulting in cash proceeds of $75 million. In June 2026, IDACORP executed an additional FSA under its 2026 ATM with a counterparty at an aggregate gross sales price of $113 million. In July 2026, IDACORP settled FSAs executed outside of its ATMs, resulting in cash proceeds of $187 million. For more detailed information about IDACORP's equity transactions, see the discussion below in this MD&A and Note 6 - "Common Stock," to the condensed consolidated financial statements included in this report. Based on planned capital expenditures and other O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during at least the next twelve months and thereafter for the foreseeable future with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing credit facilities, access to commercial paper, short-term and long-term debt markets, and equity issuances. 51 Table of Contents 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 June 30, 2026, IDACORP's and Idaho Power's capital structure ratios, with no impact to equity from unsettled FSAs, were as follows: IDACORP Idaho Power Debt 50% 51% Equity 50% 49% IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits. At June 30, 2026, IDACORP and Idaho Power believed they were in compliance with all credit facility and long-term debt covenants. Further, IDACORP and Idaho Power do not anticipate they will be in violation or breach of their respective debt covenants during 2026. Operating Cash Flows IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, income taxes, and benefit plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level currently allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers. IDACORP’s and Idaho Power’s operating cash inflows for the six months ended June 30, 2026, were $179 million and $169 million, respectively, a decrease in cash flows from operations of $122 million for IDACORP and $129 million for Idaho Power, when compared with the same period in 2025. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from the operating cash flows from Idaho Power. Significant items that affected the companies' operating cash flows in the first six months of 2026 when compared with the same period in 2025 were as follows: •a $15 million and $17 million increase in IDACORP and Idaho Power net income, respectively; •changes in regulatory assets and liabilities, mostly related to the relative amounts of costs deferred and collected under the PCA and FCA mechanisms, decreased IDACORP and Idaho Power operating cash flows by $87 million; •changes in deferred taxes and taxes accrued and receivable combined to increase operating cash flows for IDACORP and Idaho Power by $28 million and $65 million, respectively; and •changes in working capital balances due primarily to timing, including fluctuations as follows: ◦the timing of collections of accounts receivable and unbilled receivables decreased operating cash flows for IDACORP and Idaho Power by $67 million and $68 million, respectively; ◦the changes in prepayments decreased operating cash flow by $20 million for IDACORP and Idaho Power, which was primarily due to the timing of energy trading transactions, IT contracts, and insurance prepayments; and ◦the changes in accounts and wages payable increased operating cash flows for IDACORP by $8 million and decreased operating cash flows for Idaho Power by $37 million. The difference in the changes between IDACORP and Idaho Power relates primarily to the timing of intercompany tax payments from Idaho Power to IDACORP. Investing Cash Flows Investing activities consist primarily of capital expenditures related to new construction of, and improvements to, Idaho Power’s power supply, transmission, and distribution facilities. IDACORP’s and Idaho Power’s net investing cash outflows for the six months ended June 30, 2026, were $679 million and $673 million, respectively, increasing cash outflow by $206 million for IDACORP and by $209 million for Idaho Power when compared with the same period in 2025. Investing cash outflows for 2026 and 2025 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth and resource needs, aging plant and equipment, and environmental and regulatory compliance requirements. Investing cash outflows were partially offset in 2026 and 2025 by reimbursements from a B2H project joint funding partner. 52 Table of Contents Financing Cash Flows Financing activities primarily provide supplemental cash for both day-to-day operations and capital requirements, as needed. IDACORP's and Idaho Power's net financing cash inflows for the six months ended June 30, 2026, were $368 million and $435 million, respectively, an increase of $90 million and $157 million for IDACORP and Idaho Power, respectively, when compared with the same period in 2025. IDACORP and Idaho Power financing cash inflows for 2026 were primarily related to Idaho Power's net proceeds from issuance of first mortgage bonds, IDACORP's issuance of common stock, and Idaho Power's receipt of a capital contribution from IDACORP, partially offset by dividend payments. IDACORP and Idaho Power financing cash inflows for 2025 were primarily related to Idaho Power's net proceeds from issuance of first mortgage bonds, partially offset by dividend payments. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, dividends, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, payment of dividends, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. Financing Programs and Available Liquidity IDACORP Equity Programs: IDACORP's ATMs include the 2024 ATM and the 2026 ATM, which were established in May 2024 and May 2026, respectively. At June 30, 2026, IDACORP's cumulative aggregate gross sales price of executed and outstanding FSAs under its ATMs was $418 million. Also at June 30, 2026, IDACORP had $337 million of remaining capacity under its 2026 ATM. Upon effectiveness of the 2026 ATM, the 2024 ATM terminated with respect to new issuances. If IDACORP had elected to physically settle the FSAs under its ATMs as of July 24, 2026, by delivering shares of common stock, aggregate cash proceeds would have been approximately $416 million. IDACORP may elect to settle the outstanding FSAs under its ATMs at any time through their respective maturity dates, which extend through December 3, 2027. IDACORP's equity programs also include FSAs executed by IDACORP in May 2025 outside of its ATMs. Subsequent to June 30, 2026, and through the date of this report, IDACORP partially settled FSAs under this program on July 13, 2026, resulting in cash proceeds of $187 million. If IDACORP had elected to physically settle the remaining FSAs outside of its ATMs as of July 24, 2026, by delivering shares of common stock, aggregate cash proceeds would have been approximately $299 million. IDACORP may elect to settle the remaining FSAs at any time through their maturity date of November 9, 2026. Actual cash proceeds, if any, for settlement of the FSAs will depend on the method and timing IDACORP elects for settlement. For more detailed information about IDACORP's equity transactions, see Note 6 - "Common Stock" to the condensed 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 WPSC. In June and July 2026, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.5 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. At June 30, 2026, $1.5 billion was available for debt issuance under the IPUC and OPUC orders and $150 million remained available for debt issuance under the prior WPSC order, which subsequently increased to $1.5 billion in July 2026 when the WPSC issued its order. For more detailed information about Idaho Power's First Mortgage Bonds, see Note 5 - "Long-Term Debt" to the condensed consolidated financial statements included in this report. Available Short-Term Borrowing Liquidity The table below outlines available short-term borrowing liquidity as of the dates specified (in thousands of dollars). June 30, 2026 December 31, 2025 IDACORP(1) Idaho Power IDACORP(1) Idaho Power Revolving credit facility $ 100,000 $ 400,000 $ 100,000 $ 400,000 Commercial paper outstanding — — — — Net balance available $ 100,000 $ 400,000 $ 100,000 $ 400,000 (1) Holding company only. 53 Table of Contents On July 24, 2026, IDACORP and Idaho Power had no loans outstanding under their respective revolving credit facilities and had no commercial paper outstanding. Impact of Credit Ratings on Liquidity and Collateral Obligations IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depend in part on their respective credit ratings. The following table outlines the ratings of IDACORP's and Idaho Power’s securities, and the ratings outlook, by Moody's Investors Service and Standard & Poor’s Ratings Services as of the date of this report: Moody's Standard & Poor's IDACORP Idaho Power IDACORP Idaho Power Rating Outlook Stable Stable Stable Stable Issuer Rating/Corporate Baa3 Baa2 BBB BBB First Mortgage Bonds None A3 Senior Secured Debt None A3 None A- Commercial Paper/Short-Term P-3 P-2 A-2 A-2 Credit ratings 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 March 2026, Moody's rating for IDACORP was downgraded to Baa3 for long-term issuer rating and P-3 short-term commercial paper rating with a revised outlook of stable. At that time, Moody's rating for Idaho Power was downgraded to Baa2 for long-term issuer rating, A3 for first mortgage bonds, and A3 for senior secured debt with a revised outlook of stable. Moody's credit ratings of Baa3 and above are widely considered to be investment grade, or prime, ratings. The security ratings above reflect the views of Moody's or Standard & Poor's, as applicable. An explanation of the significance of these ratings may be obtained from the applicable rating agency. There have been no changes to IDACORP's or Idaho Power's ratings by Standard & Poor’s from those included in the 2025 Annual Report. Such ratings are not a recommendation to buy, sell, or hold securities. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties, which are discussed further in Part I - Item 3 "Quantitative and Qualitative Disclosures About Market Risk" included in this report. Capital Requirements Idaho Power's cash capital expenditures, excluding AFUDC, were $786 million during the six months ended June 30, 2026. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2026 (including amounts incurred to-date) through 2030 (in billions of dollars). The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings. Actual expenditures and their timing could differ substantially from the estimates in the table due to factors such as 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. 2026 2027 2028-2030 Expected capital expenditures (excluding AFUDC), in billions of dollars $1.3 - $1.5 $1.4 - $1.6 $3.6 - $4.1 Major Infrastructure Projects: Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of developments in certain of those projects since the discussion of these matters included in Part II, Item 7 - MD&A - "Capital Requirements" in the 2025 Annual Report. The discussion below should be read in conjunction with that report. Resource Additions to Address Projected Energy and Capacity Deficits: Idaho Power's existing and sustained growth in customers, load, and demand for electricity, along with transmission constraints, has created the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs in recent years and continuing over the next several years. In addition to resources already placed in service through 2025, Idaho Power has undertaken the following efforts to help meet resource needs in 2026 and beyond: 54 Table of Contents •placed in service 250 MW of company-owned battery storage assets in June 2026 with expected useful lives of approximately 20 years; •entered into 20-year agreements to purchase the storage capacity from two 100-MW battery storage facilities; •entered into an energy and capacity market purchase agreement with an energy marketer, giving Idaho Power the right to acquire 200 MW on a daily basis during summer months beginning in 2026 for a term of at least five years; •entered into five PPAs for a combined 825 MW output of planned third-party solar facilities. Idaho Power plans to sell the output of two of these solar PPAs totaling 445 MW exclusively to a large industrial customer pursuant to an agreement under Idaho Power’s Clean Energy Your Way program; •received IPUC approval for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant, for which construction commenced in May 2026; and •submitted an application to the IPUC for a CPCN for two natural gas-fueled power plants of 222 MW and 430 MW. The capital requirements table above includes capital expenditures of more than $1.7 billion from 2026 through 2030 for resource additions to address projected energy and capacity deficits in those years and beyond. Included in this amount are estimates of costs of resource additions for which Idaho Power has received CPCNs or has requested a CPCN for the resource. Idaho Power continues to evaluate resource needs and outstanding RFPs. Actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures, depending on factors such as RFP results, the timing of project in-service dates, estimated load and resource balances and customer growth, the nature and quantity of resources owned versus acquired under PPAs or similar agreements, and the outcome of regulatory proceedings. B2H Transmission Line: The B2H line, a 300-mile, high-voltage transmission project under construction between the Longhorn substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, is expected to provide transmission service to meet future resource needs. Idaho Power began construction in June 2025 and, based on the anticipated construction schedule as of the date of this report, expects the in-service date for the transmission line will be in late 2027. Idaho Power's ownership interest in the project is approximately 45 percent, while PacifiCorp's ownership interest in the project is approximately 55 percent. Idaho Power has spent approximately $918 million, including Idaho Power's AFUDC, on the B2H project through June 30, 2026. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $467 million in reimbursement as of June 30, 2026, from project co-participants for their share of costs and continues to receive reimbursement as costs are incurred. PacifiCorp is obligated to reimburse Idaho Power for its share of any future project expenditures incurred by Idaho Power under the terms of the joint funding agreement. Idaho Power and PacifiCorp operate under a construction funding agreement filed with the FERC. The permitting phase of the B2H project was subject to federal review and approval by various federal agencies. Federal agency records of decision have been received and all lawsuits challenging the federal rights-of-way have been resolved. In the separate State of Oregon permitting process, Oregon's Energy Facility Siting Council approved Idaho Power's site certificate in 2022 followed by a final order and two amendments to the site certificate, both contested but upheld in subsequent judicial proceedings. In 2023, the IPUC, OPUC, and WPSC granted Idaho Power and PacifiCorp their respective CPCNs related to the construction of the B2H project. In June 2025, three parties filed complaints with the OPUC seeking reconsideration of the CPCN granted for B2H, but in November 2025, the OPUC upheld the B2H CPCN. Those parties filed three complaints in the Baker County and Union County Circuit Courts challenging the OPUC decision. All three complaints have been voluntarily dismissed. In addition, in September 2025, two parties filed complaints in Morrow County Circuit Court alleging that the Oregon Department of Energy and the Oregon Energy Facility Siting Council improperly processed modifications of the Fire Protection and Suppression Plan. The court granted Idaho Power's and the Oregon Department of Energy's motion to dismiss the complaints in a letter order in April 2026. Petitioners in the case have filed a notice of intent to appeal the Morrow County Circuit Court's decision. In July 2026, Malheur Mining Company, Ltd. filed a complaint in federal district court, Pendleton division, against Idaho Power and the BLM asserting their mineral rights are being infringed upon by the B2H project and requesting various forms of relief, including damages and injunctive relief. The case remains pending. Total cost estimates for the project are between $1.5 billion and $1.7 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $415 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining material procurement and construction of the project. GWW Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the GWW project, a high-voltage transmission line project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho. Idaho Power and PacifiCorp are parties to a joint funding agreement for permitting of the project. Idaho Power has expended approximately $109 million, including Idaho Power's AFUDC, for its share of the project through June 30, 2026. 55 Table of Contents The permitting phase of the GWW project was subject to review and approval of the BLM. The BLM has published its records of decision for all segments of the transmission line. In 2020 and 2024, PacifiCorp completed construction and commissioned segments of its portion of the project in Wyoming. In March 2023, PacifiCorp initiated the pre-construction phase of approximately 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho. Idaho Power has an ownership interest in four segments within this area, totaling approximately 330 miles of new line. Current permitting and pre-construction activities are focused on Segment E-8, the segment of line between the Hemingway substation and the Midpoint substation near Jerome, Idaho. In April 2026, Idaho Power and PacifiCorp filed a joint request that the IPUC grant both companies a CPCN for this segment of the line. Idaho Power is the majority owner of the approximately 133-mile segment and, as of the date of this report, Idaho Power estimates the total cost for its share of this segment and the associated substation work to be between $900 million and $1.1 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $790 million of Idaho Power's share of estimated costs (excluding AFUDC) for the remaining permitting and construction phases of the project based on Idaho Power's assumption that it may commence construction of this segment during that time period. Idaho Power expects the in-service date for a portion of this segment will be 2028 or later and the entire segment to be completed in 2030 or later. Idaho Power and PacifiCorp continue to coordinate the timing of next steps of the remaining co-owned segments to best meet customer and system needs, including potentially modifying the ownership structure of a few segments of the project. SWIP-N Transmission Line: In February 2025, Idaho Power entered into a commitment to become a partial owner of SWIP-N, a 285-mile high-voltage transmission line under construction between the Robinson Summit Substation near Ely, Nevada, and the Midpoint Substation near Jerome, Idaho. Upon the project being placed into service, the applicable agreements provide that Idaho Power will purchase an approximate 11 percent ownership interest in the project, entitling Idaho Power to approximately 11 percent of the total capacity of the SWIP-N line. In addition, Idaho Power entered into a capacity entitlement agreement entitling Idaho Power to approximately 11 percent of additional capacity on the SWIP-N line over a 40-year term commencing upon the project being placed in service. Idaho Power is obligated for approximately 11 percent of the total costs to develop and construct the project. The capital requirements table above includes Idaho Power's share of the costs to develop and construct the project. The project agreements do not require Idaho Power to incur any costs to purchase its ownership interest or begin paying for capacity under the capacity entitlement agreement until the line is in service. Idaho Power has an option to purchase the ownership interest associated with such capacity entitlement upon expiration of the 40-year term. In December 2025, the IPUC issued its order approving a CPCN for the project. SWIP-N has received various required governmental approvals, including from the FERC and the Public Utilities Commission of Nevada, while certain other approvals and permits remain in process. Construction of the project commenced in June 2026, and Idaho Power expects construction to be completed in 2028. Defined Benefit Pension Plan Contributions Idaho Power has no minimum contribution to its defined benefit pension plan required in 2026, and during the six months ended June 30, 2026, Idaho Power made no contributions. Idaho Power may contribute up to $30 million in 2026 in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions, as well as to mitigate the cost of being in an underfunded position. The primary impact of pension contributions is on the timing of cash flows, as the timing of cost recovery lags behind contributions. Contractual Obligations IDACORP’s and Idaho Power’s contractual cash obligations have not materially changed during the six months ended June 30, 2026, except as disclosed in Note 5 – “Long-Term Debt” and Note 8 – “Commitments” to the condensed consolidated financial statements included in this report. Dividends The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is generally dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. 56 Table of Contents For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 - “Common Stock” to the condensed consolidated financial statements included in this report. Off-Balance Sheet Arrangements IDACORP's and Idaho Power's off-balance sheet arrangements have not changed materially from those reported in the MD&A in the 2025 Annual Report. REGULATORY MATTERS Introduction Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, OPUC, and FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, OPUC, and WPSC as to the issuance of debt and equity securities. As a public utility under the Federal Power Act, Idaho Power has been granted the authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability, among other items. Idaho Power develops its regulatory filings taking into consideration short-term and long-term needs for rate relief and several other factors that can affect the structure and timing of those filings. These factors include in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates, as well as other factors. Idaho Power's most recent general rate case in Idaho was filed in 2025 and resolved by the 2025 Settlement Stipulation, which the IPUC approved in December 2025 for rates that went into effect for Idaho-jurisdiction customers on January 1, 2026. Previously, in 2024, Idaho Power filed a limited-issue rate case in Idaho (2024 Idaho Limited-Issue Rate Case), which the IPUC resolved through its order issued in December 2024 for rates that went into effect for Idaho-jurisdiction customers on January 1, 2025. In 2023, Idaho Power's general rate case in Idaho was resolved by the IPUC's approval of the 2023 Settlement Stipulation in December 2023 for rates that went into effect for Idaho-jurisdiction customers on January 1, 2024. Idaho Power's most recently concluded general rate case in Oregon was resolved by the OPUC's approval of settlement stipulations in September 2024 for rates that went into effect for Oregon-jurisdiction customers on October 15, 2024. Refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report for additional information relating to the 2025 Settlement Stipulation, 2024 Idaho Limited-Issue Rate Case, 2023 Idaho general rate case, and Oregon general rate case. Between general rate cases, Idaho Power relies upon customer growth, an FCA mechanism in Idaho, power cost adjustment mechanisms, limited-issue rate cases, WMP cost deferrals, project-specific cases, tariff riders, and other mechanisms to mitigate the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. The outcomes of significant proceedings are described in part in this report and further in the 2025 Annual Report. In addition to the discussion below, which includes notable regulatory developments since the discussion of these matters in the 2025 Annual Report, refer to Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report for additional information relating to Idaho Power's regulatory matters and recent regulatory filings and orders. 57 Table of Contents Notable Retail Rate or Revenue Changes During 2026, Idaho Power received orders authorizing the rate or revenue changes summarized in the table below. Description Status Estimated Impact(1) Notes PCA - Idaho New PCA rate became effective June 1, 2026 $51.3 million PCA increase for the period from June 1, 2026 to May 31, 2027 The income statement impact of revenue changes associated with the PCA mechanism is largely offset by associated increases and decreases in actual power supply costs and amortization of deferred power supply costs. The rate increase is primarily attributable to a decrease in forecast hydroelectric generation for the April 2026 to March 2027 forecast period. FCA - Idaho New FCA rate became effective June 1, 2026 $5.1 million FCA increase for the period from June 1, 2026 to May 31, 2027 The FCA is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by partially separating (or decoupling) the recovery of fixed costs from the volumetric kilowatt-hour charge and instead linking it to a set amount per customer. APCU - Oregon New APCU rate became effective June 1, 2026 $0.7 million APCU increase for the period from June 1, 2026 to May 31, 2027 The rate increase reflects a decrease in expected net power supply expense for the March forecast combined with an increase in normalized net power supply expense for the October update. PCAM - Oregon New PCAM rate became effective June 1, 2026 $1.9 million PCAM increase for the period from June 1, 2026 to May 31, 2027 The Oregon power cost adjustment mechanism (PCAM) allows Idaho Power to recover or refund differences between actual net power supply costs and those included in rates, subject to applicable deadbands and an earnings test. The PCAM also includes the amortization of certain authorized deferrals. (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. Idaho Earnings Support and Sharing from Idaho Settlement Stipulations The 2025 Settlement Stipulation, 2023 Settlement Stipulation, and 2018 Settlement Stipulation are each described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2025 Annual Report. IDACORP and Idaho Power believe that the terms allowing additional amortization of ADITC, subject to an annual cap of $55 million, in the settlement stipulations provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulations in effect. Based on its estimate of full-year 2026 Idaho ROE, for the three months and six months ended June 30, 2026, Idaho Power recorded zero and $6.3 million, respectively, in additional ADITC amortization under the settlement stipulations. Change in Deferred (Accrued) Net Power Supply Costs and the Power Cost Adjustment Mechanisms Deferred (accrued) power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred (accrued) power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions address the variability of power supply costs and provide for annual adjustments to the rates charged to retail customers. The power cost adjustment mechanisms and associated financial impacts are described further in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. With the exception of power supply expenses incurred under PURPA, expenses under export credit mechanisms, capital lease payments associated with battery energy storage systems, and certain demand response program costs that are passed through to customers substantially in full, the PCA mechanism allows Idaho Power to pass through to customers 95 percent of the differences in actual net power supply expenses as compared with base net power supply expenses, whether positive or negative. Thus, the primary financial statement impact of power supply cost deferrals or accruals is that the timing of when cash is paid out for power supply expenses differs from when those costs are recovered from customers, impacting operating cash flows from year to year. 58 Table of Contents The following table summarizes the change in accrued net power supply costs (in millions of dollars). Idaho Oregon Total Balance at December 31, 2025 $ (41.0) $ (1.4) $ (42.4) Current period net power supply costs accrued (27.0) — (27.0) Prior amounts refunded through rates 27.3 0.1 27.4 Renewable energy credit sales (35.9) (1.4) (37.3) Interest and other (4.6) (0.1) (4.7) Balance at June 30, 2026 $ (81.2) $ (2.8) $ (84.0) Open Access Transmission Tariff Draft Posting Idaho Power uses a formula rate for transmission service provided under its OATT, which provides that transmission rates will be updated annually based primarily on financial and operational data that Idaho Power files with the FERC. The existing OATT rate in effect from October 1, 2025 to September 30, 2026, is $34.13 per kilowatt-year (kW-year) based on a net annual transmission revenue requirement of $148.3 million. In May 2026, Idaho Power publicly posted its 2026 draft transmission rate, reflecting a transmission rate of $35.40 per kW-year, to be effective for the period from October 1, 2026 to September 30, 2027. A kW-year is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's 2026 draft rate was based on a net annual transmission revenue requirement of $162.6 million. Integrated Resource Plan and Resource Procurement Filings Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2025, which identified the need for resources to meet projected capacity deficits in the near-term. The OPUC and IPUC acknowledged the 2025 IRP in December 2025 and February 2026, respectively. In March 2026, Idaho Power filed an application with the IPUC for a CPCN for the South Hills Power Plant, a 222 MW natural gas-fueled facility to meet an identified capacity deficit in 2029, and a CPCN for the Peregrine Power Plant, a 430 MW natural gas-fueled facility to meet an identified capacity deficit in 2030, as well as confirmation and approval by the IPUC of AFUDC accrued for each of the projects prior to the issuance of a CPCN. As of the date of this report, the case remains pending. In April 2026, Idaho Power and PacifiCorp filed a joint application with the IPUC to grant a CPCN to each of Idaho Power and PacifiCorp for Segment E-8 of GWW, an approximately 133-mile section of GWW jointly owned by Idaho Power and PacifiCorp that will run from the Midpoint substation near Jerome, Idaho, to the Hemingway substation near Boise, Idaho. As of the date of this report, the case remains pending. In June 2026, Idaho Power filed an application with the IPUC for an order approving the 20-year PPA with Bluebird Solar Project LLC supplying up to 200 MW of output to Idaho Power and the 20-year energy storage system tolling agreement for 100 MW of dispatchable energy storage capacity. Both are expected to be in-service by June 2028. As of the date of this report, the case remains pending. Large Contract Customer Rate Proceedings In May 2026, the IPUC approved, with modifications, a large contract for electric service for Micron Idaho Semiconductor Manufacturing (Triton) LLC, a subsidiary of Micron Technology, Inc. (Micron), for electric service for Micron's new memory manufacturing fabrication complex located in Boise, Idaho. The contract anticipates a significant increase in load on Idaho Power's system that will ramp over a number of years beginning in 2026. In June 2026, Idaho Power filed an application with the IPUC for approval of a large contract for electric service for Chobani, LLC, at the Chobani food production facility located in Twin Falls, Idaho. As of the date of this report, the IPUC's decision is pending. Oregon Sale Regulatory Applications In May 2026, Idaho Power and OTEC jointly filed an application with the OPUC to approve the Oregon Sale and its related territory allocation agreement. In June 2026, Idaho Power filed an application with the IPUC to approve the Oregon Sale and its related transition framework and agreement for supply of power and energy. In July 2026, Idaho Power filed an application 59 Table of Contents with the FERC under Section 203 of the Federal Power Act to approve Idaho Power's sale of certain transmission assets to OTEC as part of the Oregon Sale. As of the date of this report, each of the cases remains pending. Relicensing of Hydropower Projects HCC Relicensing: In connection with Idaho Power's major efforts to relicense the HCC, Idaho Power's largest hydropower complex, as described in more detail in the 2025 Annual Report in Part II, Item 7 - MD&A – "Liquidity and Capital Resources" and "Regulatory Matters," in 2020, Idaho Power submitted to the FERC its supplement to the final license application, incorporating the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications. The supplement included feedback on proposed modifications of the 2007 final EIS for the HCC, as well as an updated cost analysis of the HCC and a request that the FERC issue a 50-year license and initiate a supplemental NEPA process at the FERC. In 2022, the FERC issued a notice of intent to prepare a supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the U.S. Fish and Wildlife Service (USFWS) and the National Marine Fisheries Service (NMFS) under section 7 of the ESA. The FERC issued the draft supplemental EIS in January 2026. As part of issuing the draft supplemental EIS, the FERC requested, and USFWS and NMFS initiated, formal consultation under section 7 of the ESA. The FERC's most recently issued schedule for the supplemental EIS has a target date of September 2026 for issuance of the final supplemental EIS. Relicensing costs of $557 million (including AFUDC) for the HCC were included in construction work in progress at June 30, 2026. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $38.5 million of AFUDC annually relating to relicensing of the HCC project. Collecting these amounts currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of June 30, 2026, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $307 million. As of the date of this report, Idaho Power believes issuance of a new HCC license by the FERC will be in 2027 or thereafter. Idaho Power is unable to predict the exact timing that the FERC will issue a new license or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with a new license. Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $35 million to $45 million until issuance of the license. Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial. In December 2025, as established by a previous IPUC order, Idaho Power filed an application with the IPUC requesting a determination, and in July 2026, the IPUC issued an order with its determination, that Idaho Power's expenditures from January 1, 2016 through year-end 2025 on relicensing of the HCC were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding. American Falls Relicensing: In February 2023, Idaho Power filed its final relicensing application with the FERC to relicense the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a nameplate generating capacity of 92.3 MW and FERC authorized installed capacity of 67.5 MW. Idaho Power owns the generation facility but not the structural dam or reservoir, which are owned by the U.S. Bureau of Reclamation. In September 2024, the Idaho Department of Environmental Quality issued a final CWA Section 401 water quality certification. The FERC released its environmental assessment in accordance with NEPA in January 2025. Idaho Power's previous license at American Falls expired in February 2025 and was renewed automatically at that time and again in February 2026 for one year periods on the same terms and conditions as its prior license. The annual license is effective until February 28, 2027, and will continue with annual renewals automatically until the FERC issues a new license for the American Falls facility. As of the date of this report, Idaho Power anticipates the FERC will issue a new license for this facility in 2026. 60 Table of Contents ENVIRONMENTAL MATTERS Overview Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act, the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's co-owned coal and natural gas-fired power plants and its three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's hydropower projects are also subject to a number of water discharge standards and other environmental requirements. Compliance with current and future environmental laws and regulations may: •increase the operating costs of generating plants; •increase the construction costs and lead time for new facilities; •require the modification of existing generating plants, which could result in additional costs; •require the curtailment, fuel-switching, or shut-down of existing generating plants; •reduce the output from current generating facilities; or •require the acquisition of alternative sources of energy or storage technology, increased transmission wheeling, or construction of additional generating facilities, which could result in higher costs. Part I, Item 1 - "Business - Utility Operations - Environmental Regulation and Costs" in the 2025 Annual Report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2026 to 2028. 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 2028, though they could be substantial. A summary of notable environmental matters (including conditions and events associated with climate change) impacting, or expected to potentially impact, IDACORP and Idaho Power is included in Part II, Item 7 - MD&A - "Environmental Matters" and MD&A - "Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs" in the 2025 Annual Report. Recent developments in certain environmental matters relevant to Idaho Power are described below. EPA Regulatory Actions In March 2025, the EPA announced a set of proposed regulatory actions relating to environmental laws and regulations, many of which may impact Idaho Power if they are implemented. The proposed regulatory actions relate to the following laws and regulations, among others: the EPA's 2009 endangerment finding regarding six greenhouse gases; the Clean Air Act Section 111 rulemaking for new and existing generation units (also known as the Clean Power Plan 2.0); the Mercury and Air Toxics Standards (MATS Rule); the Greenhouse Gas Reporting Program; effluent limitations guidelines and standards for the Steam Electric Power Generating Industry; the National Ambient Air Quality Standards for Particulate Matter (PM2.5); the Regional Haze Program; the “Good Neighbor Plan” and related State Implementation Plans; the coal ash program; and the definition of "Waters of the United States," which impacts applicability of the CWA to certain wetlands and water bodies. As described in the 2025 Annual Report, the EPA has published proposed rules for several of the items mentioned in its March 2025 announcement. Except for the final rules described below, each of the proposed rules described in the 2025 Annual Report or below is subject to public comment and remains pending as of the date of this report. Idaho Power will continue to actively monitor EPA's proposals and any other pending or potential environmental regulations related to environmental matters that may have an impact on its future operations. Given uncertainties regarding the outcome and timing for these EPA proposals, Idaho Power is unable to estimate the impact on Idaho Power of any such proposals. National Environmental Policy Act Matters In June 2026, the EPA published a proposed rule that amends its procedures for implementing NEPA. For actions where the EPA is the NEPA lead agency, the proposed changes would create hard deadlines and page limits aimed at faster reviews, narrow the scope of analysis to reasonably foreseeable effects, expand the use of categorical exclusions, and allow sponsors 61 Table of Contents (such as Idaho Power) to prepare NEPA documents themselves and pay fees to accelerate review timelines. If adopted as proposed, the rule could reduce the time required to develop future Idaho Power generation and transmission projects. Clean Air Act Matters Greenhouse Gas Endangerment Finding: In February 2026, the EPA finalized a rule rescinding the EPA's 2009 greenhouse gas endangerment finding. Idaho Power does not expect any near-term impact on its plans or operations as a result of the rescission of the endangerment finding but will continue to monitor any potential effects. Mercury and Air Toxic Standards: In February 2026, the EPA finalized the repeal of certain amendments to the MATS Rule, including the revised filterable particulate matter (fPM) emission standard; the revised fPM emission standard compliance demonstration requirements; and the revised mercury emission standard for lignite-fired electric utility steam generating units. Idaho Power does not expect any near-term impact on its plans or operations as a result of the amendments to the MATS Rule but will continue to monitor any potential effects. Revisions to New Source Review: In May 2026, the EPA proposed revisions to the new source review (NSR) air permitting regulations to allow construction of non-emitting components or structures before issuance of an NSR air permit for a new major stationary source or major modification of an existing major stationary source. If adopted as proposed and subsequently implemented by the Idaho Department of Environmental Quality, the rule could reduce the time required for Idaho Power to bring new natural gas-fueled generation resources online. Endangered Species Act Matters In July 2026, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service finalized a rule that rescinded the definition of "harm" under the ESA in their respective regulations. The rescission of the definition of harm may have the effect of reducing the applicability of the ESA for some Idaho Power projects, however, as of the date of this report, Idaho Power is unable to estimate the impact on Idaho Power of the rule. Resource Conservation and Recovery Act Matters In April 2026, the EPA published proposed rules to amend several provisions of the federal regulations governing the disposal of coal ash, also known as coal combustion residuals or CCR. The proposed rules are subject to public comment and remain pending as of the date of this report. If adopted as proposed, the proposed rules could simplify certain CCR requirements applicable to Idaho Power's jointly-owned facilities. However, given uncertainties regarding the proposed rule, Idaho Power is unable to estimate the impact on Idaho Power of the proposed rules. Land Use Matters In May 2026, the current presidential administration issued an executive order to rescind two prior executive orders that impact off-road vehicle use on federally managed lands. While the order may ultimately result in changes to Idaho Power’s access to federally managed lands, any impact is uncertain until the applicable federal agencies have issued and finalized rules and regulations to implement the order. In June 2026, a final rule issued by the BLM took effect, which rescinded the Conservation and Landscape Health Rule, also known as the "public lands rule," which gave authority to the BLM to consider conservation and habitat health alongside other aspects of its multiple-use mandate in making land use decisions. Idaho Power does not expect any near-term impact on its plans or operations as a result of this rule but will continue to monitor any potential effects. Snake River Minimum Streamflow at Swan Falls In June 2026, Idaho Power sent a letter to Idaho Governor Little acknowledging drought conditions impacting the historical Swan Falls Agreement regarding Idaho Power's water rights and the risk that the streamflow in the Snake River that the State is contractually required to maintain could drop below the minimum required level at Swan Falls. Idaho Power indicated its willingness to accept water released from storage reservoirs above Swan Falls for any shortfalls that occur during summer 2026 and requested that the State and water users work collaboratively with Idaho Power to develop a mitigation plan by March 1, 2027. In response, Governor Little asked the Idaho Water Resource Board to support the proposed interim approach and also directed the Water Resource Board to work to develop a long-term mitigation plan to ensure the State meets its minimum streamflow obligations. Reduced Snake River streamflows at Swan Falls will generally reduce the amount of water available to Idaho Power for hydropower production. 62 Table of Contents OTHER MATTERS Critical Accounting Policies and Estimates IDACORP's and Idaho Power's discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires IDACORP and Idaho Power to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and Idaho Power evaluate these estimates, including those estimates related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled receivables, and the allowance for uncollectible accounts. These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate. IDACORP’s and Idaho Power’s critical accounting policies are reviewed by the audit committees of the boards of directors. These policies have not changed materially from the discussion of those policies included under "Critical Accounting Policies and Estimates" in the 2025 Annual Report. Recently Issued Accounting Pronouncements For discussion of new and recently adopted accounting pronouncements, see Note 1 - "Summary of Significant Accounting Policies" to the condensed consolidated financial statements included in this report.