Idacorp Inc.

04/30/2026 | Press release | Distributed by Public on 04/30/2026 05:55

Quarterly Report for Quarter Ending March 31, 2026 (Form 10-Q)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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 March 31, 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 achieved notable milestones for several key projects, underscoring significant progress towards addressing peak capacity and energy needs in 2027 and beyond:
◦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.
◦In March, the IPUC approved 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.
◦In March, Idaho Power filed a CPCN request with the IPUC for a 222 MW natural gas-fueled facility, with an expected in-service date in 2029 and a 430 MW natural gas-fueled facility, with an expected in-service date in 2030. As of the date of this report, both requests are pending IPUC approval.
◦In April, Idaho Power, jointly with co-owner PacifiCorp, filed a CPCN request for Segment E-8 for the GWW transmission line, which would create up to 2,000 MW of additional transmission capacity and the ability to interconnect new generation resources across Idaho.
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 and shares, except earnings per share amounts):
Three months ended
March 31,
2026 2025
Idaho Power net income $ 66,658 $ 58,127
Net income attributable to IDACORP, Inc. $ 67,981 $ 59,647
Weighted average outstanding shares - diluted 56,289 54,126
IDACORP, Inc. earnings per diluted share $ 1.21 $ 1.10
The table below provides a reconciliation of net income attributable to IDACORP for the three months ended March 31, 2026, from the same period in 2025 (items are in millions of dollars and are before related income tax impact unless otherwise noted):
Three months ended
Net income attributable to IDACORP, Inc. - March 31, 2025 $ 59.6
Increase (decrease) in Idaho Power net income:
Retail revenues per MWh, net of power cost adjustment mechanisms
18.0
Customer growth, net of associated power supply costs and power cost adjustment mechanisms 5.0
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms (10.7)
Idaho fixed cost adjustment (FCA) revenues 19.1
Other O&M expenses (13.1)
Depreciation and amortization expense (5.7)
Other changes in operating revenues and expenses, net
13.6
Increase in Idaho Power operating income 26.2
Non-operating expense, net (4.1)
Additional ADITC amortization (13.0)
Income tax expense, excluding additional ADITC amortization (0.6)
Total increase in Idaho Power net income 8.5
Other IDACORP changes (net of tax)
(0.1)
Net income attributable to IDACORP, Inc. - March 31, 2026 $ 68.0
Net Income - First Quarter 2026
IDACORP's net income increased $8.4 million for the first quarter of 2026 compared with the first quarter of 2025, due primarily to higher net income at Idaho Power.
A net increase in retail revenues per MWh, net of power cost adjustment mechanisms, increased operating income by $18.0 million in the first quarter of 2026 compared with the first 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.
Customer growth increased operating income by $5.0 million in the first quarter of 2026 compared with the first quarter of 2025, as the number of Idaho Power customers grew by approximately 15,000, or 2.3 percent, during the twelve months ended March 31, 2026. Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms, decreased operating income by $10.7 million in the first quarter of 2026 compared with the first quarter of 2025. Usage per residential and commercial customers decreased most significantly, as more moderate temperatures in the first quarter of 2026 compared with the first quarter of 2025 led these customers to use less energy for heating purposes. These decreases were partially offset by increases in usage per irrigation and industrial customers, as lower precipitation in the first quarter of 2026 compared with the first quarter of 2025 led irrigation customers to use more energy for operating irrigation pumps, and a large
load industrial customer increased energy use as it ramped up operation of its facility. An increase in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $19.1 million.
Other O&M expenses in the first quarter of 2026 were $13.1 million higher than the first quarter of 2025. This increase was primarily the result of increased wildfire mitigation program expenses and the amortization 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.
Depreciation and amortization expense increased $5.7 million in the first quarter of 2026 compared with the first quarter of 2025, due primarily to an increase in plant-in-service. Additionally, the start of operations at a leased battery storage facility in the second quarter of 2025 contributed modestly to the increase through the amortization of a related right-of-use asset.
Other changes in operating revenues and expenses, net, increased operating income by $13.6 million in the first quarter of 2026 compared with the first 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 $4.1 million in the first quarter of 2026 compared with the first 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. Interest expense recorded on a new finance lease also contributed to the increase compared with the first quarter of 2025. This increase was partially offset by an increase in AFUDC in the first quarter of 2026 compared with the first quarter of 2025, as the average construction work in progress balance was higher.
The increase in income tax expense for the first quarter of 2026, compared with the first quarter of 2025, was primarily due to a decrease in additional ADITC amortization under the Idaho regulatory settlement stipulation. Based on Idaho Power's current expectations of full-year 2026 financial results, Idaho Power recorded $6.3 million of additional ADITC amortization during the first quarter of 2026, compared with $19.3 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 B2H, GWW, and SWIP-N projects. To help meet future peak 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'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 March 31, 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 first quarter of 2026, with an increase in industrial loads over the prior year's first quarter driven by the ramp-up in electric service by a new large load customer. Idaho Power expects this customer, 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 peak 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 date of this report, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 7.0 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. See "Other Matters - Idaho Wildfire Standard of Care Act" for additional details.
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 ended March 31, 2026. In this analysis, the results for the three months ended March 31, 2026, are compared with the same period in 2025.
The table below presents Idaho Power's energy sales and supply (in thousands of MWh).
Three months ended
March 31,
2026 2025
Retail energy sales 3,625 3,723
Wholesale energy sales 92 439
Energy sales bundled with renewable energy credits 49 541
Total energy sales 3,766 4,703
Hydropower generation 1,560 2,124
Jointly-owned thermal generation(1)
425 674
Natural gas and other generation 775 774
Total system generation 2,760 3,572
Purchased power 1,301 1,477
Line losses (295) (346)
Total energy supply 3,766 4,703
(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
March 31,
2026 2025
Normal (2)
Heating degree-days(1)
2,032 2,416 2,402
Cooling degree-days(1)
1 - -
Precipitation (inches) 2.7 5.1 3.7
(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: Retail sales volumes decreased 3 percent in the first quarter of 2026 compared with the same period in 2025, primarily due to more moderate temperatures, which reduced the amount of energy per customer used for heating. The decrease in usage per customer was partially offset by customer growth as the number of Idaho Power's customers grew by 2.3 percent over the prior twelve months. For more information on the changes in sales volume, see the "Operating Revenues" section below in this MD&A.
Total system generation decreased 23 percent for the first quarter of 2026 compared with the first quarter of 2025, due primarily to lower hydropower generation and jointly-owned thermal 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
March 31,
2026 2025
Retail revenues:
Residential (includes $16,637 and $(2,193), respectively, related to the FCA)(1)
$ 203,597 $ 190,705
Commercial (includes $206 and $(43), respectively, related to the FCA)(1)
96,655 97,852
Industrial 69,603 68,607
Irrigation 1,942 1,113
Deferred revenue related to HCC relicensing AFUDC(2)
(9,114) (2,064)
Total retail revenues $ 362,683 $ 356,213
Volume of retail sales (MWh)
Residential 1,560 1,702
Commercial 1,052 1,075
Industrial 987 934
Irrigation 26 12
Total retail MWh sales 3,625 3,723
Number of retail customers at period end
Residential 563,660 550,207
Commercial 81,129 79,823
Industrial 148 148
Irrigation 22,677 22,457
Total customers 667,614 652,635
(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 $6.5 million during the first quarter of 2026, compared with the same period in 2025. The factors affecting retail revenues during the periods are discussed below.
•Rates: Customer rates, excluding revenues related to power cost adjustment mechanisms, increased retail revenues by $18.0 million for the three months ended March 31, 2026, compared with the same period in 2025, 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 $20.6 million in the first quarter of 2026 compared with the same period 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 March 31, 2026, increased retail revenues by $7.5 million in the first quarter of 2026 compared with the same period of 2025.
•Usage: Lower usage (on a per customer basis), in some customer classes, decreased retail revenues by $17.5 million in the first quarter 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 quarter of 2026 compared with the first quarter of 2025 led these customers to use less energy for heating purposes. These decreases were partially offset by increases in usage per irrigation and industrial customers, as lower precipitation in the first quarter of 2026 compared with the first quarter of 2025 led irrigation customers to use more energy for operating irrigation pumps, and a large load industrial customer increased energy use as it ramped up operation of its facility.
•FCA Mechanism: A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $19.1 million.
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 and MWh, except for revenue per MWh amounts).
Three months ended
March 31,
2026 2025
Wholesale energy revenues $ 4,812 $ 19,548
Wholesale MWh sold 92 439
Wholesale energy revenues per MWh $ 52.30 $ 44.53
In the first quarter of 2026, wholesale energy revenues decreased $14.7 million compared with the same period of 2025, due primarily to a decrease in wholesale energy volumes sold, partially due to milder winter 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."
Operating Expenses
Purchased Power: The table below presents Idaho Power's purchased power expenses and volumes (in thousands of dollars and MWh, except for per MWh amounts).
Three months ended
March 31,
2026 2025
Purchased power expense $ 65,081 $ 74,109
MWh purchased 1,301 1,477
Average cost per MWh $ 50.02 $ 50.18
Purchased power expense decreased $9.0 million during the first quarter of 2026 compared with the same period of 2025, primarily due to a 12 percent decrease in MWh purchased.
Fuel Expense: The table below presents Idaho Power's fuel expenses and thermal generation (in thousands of dollars and MWh, except for per MWh amounts).
Three months ended
March 31,
2026 2025
Fuel Expense
Jointly-owned thermal(1)
$ 17,065 $ 30,917
Natural gas(2)
46,664 38,484
Total fuel expense $ 63,729 $ 69,401
MWh generated
Jointly-owned thermal(1)
425 674
Natural gas(2)
775 774
Total MWh generated 1,200 1,448
Average cost per MWh - Jointly-owned thermal $ 40.15 $ 45.87
Average cost per MWh - Natural gas $ 60.21 $ 49.72
Weighted average, all sources $ 53.11 $ 47.93
(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 $5.7 million, or 8 percent, in the first quarter of 2026 compared with the same period of 2025, primarily due to a 37 percent decrease in jointly-owned thermal generation, partially offset by an 11 percent increase in the total average cost per MWh from all sources.
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 first quarters of 2026 and 2025, losses on financial gas hedges of $26.5 million and $12.2 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, a battery storage lease, 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
March 31,
2026 2025
Idaho power supply cost accrual $ 2,356 $ 29,443
Oregon power supply cost deferral - (2,657)
Amortization of prior year authorized balances (11,649) 20,899
Total power cost adjustment (income statement) $ (9,293) $ 47,685
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 first quarter 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 in the first quarter of 2026 were $13.1 million higher than the first quarter of 2025. This increase was primarily driven by increases in wildfire mitigation program expenses and the amortization of previously deferred costs related to the conversion from coal to natural gas at the Jim Bridger plant, both of which are now being collected in base rates.
Income Taxes
IDACORP's and Idaho Power's income tax expense increased $12.9 million and $13.6 million, respectively, for the three months ended March 31, 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. 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.
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 April 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 ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of April 24, 2026, would have been approximately $154 million;
•IDACORP's FSAs, independent of the ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of April 24, 2026, would have been approximately $561 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; $150 million remains available for issuance pursuant to state regulatory authority.
IDACORP uses original issuances of shares for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and also intends to potentially use original issuances for share purchases within the Idaho Power Company Employee Savings Plan beginning in the second quarter of 2026. 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. 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 ATM offering program with various counterparties at an aggregate gross sales price of $155 million. For more detailed information about IDACORP's equity transactions, see below in this MD&A and Note 6 - "Common Stock" to the condensed consolidated financial statements included in this report.
The proceeds from these issuances of common stock and first mortgage bonds are expected to be used for general corporate purposes, including funding Idaho Power's capital projects.
Based on planned capital expenditures and other O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during at least the next twelve months and thereafter for the foreseeable future with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing credit facilities, access to commercial paper, short-term and long-term debt markets, and equity issuances.
IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent equity. Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of March 31, 2026, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, with no impact to equity from unsettled FSAs, were as follows:
IDACORP Idaho Power
Debt 54% 53%
Equity 46% 47%
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 March 31, 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 three months ended March 31, 2026, were $76 million and $60 million, respectively, a decrease in cash flows from operations of $48 million for IDACORP and $51 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 three months of 2026 when compared with the same period in 2025 were as follows:
•an $8 million and $9 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 $76 million;
•changes in deferred taxes and taxes accrued and receivable combined to increase operating cash flows for IDACORP and Idaho Power by $15 million and $12 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 increased operating cash flows by $16 million for IDACORP and Idaho Power;
◦the changes in accounts and wages payable increased operating cash flows for IDACORP and Idaho Power by $3 million and $4 million, respectively; and
◦the changes in other assets and liabilities decreased operating cash flows by $15 million for IDACORP and Idaho Power. This decrease was primarily related to the timing of refundable transmission network upgrade deposits and accrued interest.
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 three months ended March 31, 2026, were $296 million and $291 million, respectively, increasing cash outflow by $113 million for IDACORP and by $114 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 peak 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.
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 three months ended March 31, 2026, were $343 million and $386 million, respectively, an increase of $18 million and $60 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: In March 2026, IDACORP executed FSAs under its ATM offering program with various counterparties, at an aggregate gross sales price of $155 million. At March 31, 2026, IDACORP's cumulative aggregate gross sales price of executed and outstanding FSAs under its ATM offering program was $155 million, and IDACORP had no remaining capacity under its ATM offering program. If IDACORP had elected to physically settle the FSAs under its ATM offering program as of April 24, 2026, by delivering shares of common stock, cash proceeds would have been approximately $154 million. IDACORP may elect to settle the outstanding FSAs under its ATM offering program at any time, up to their maturity date of March 31, 2027.
Pursuant to the FSAs executed independent of the ATM offering program by IDACORP in May 2025, if IDACORP had elected to physically settle these FSAs as of April 24, 2026, by delivering shares of common stock, the aggregate cash proceeds would
have been approximately $561 million. IDACORP may elect to settle these FSAs at any time, up to 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 February and March 2024, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. At March 31, 2026, $150 million remained available for debt issuance under the regulatory orders. For more detailed information about Idaho Power 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).
March 31, 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.
On April 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 $361 million during the three months ended March 31, 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 peak demand for electricity, along with transmission constraints, has created the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs 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 peak needs in 2026 and beyond:
•entered into contracts or plans to construct, own, and operate 250 MW of battery storage assets with expected useful lives of approximately 20 years;
•entered into a 20-year agreement to purchase the storage capacity from a 100 MW battery storage facility;
•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 four PPAs for a combined 625 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; 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 planned 300-mile, high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, is expected to provide transmission service to meet future resource needs. 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 $775 million, including Idaho Power's AFUDC, on the B2H project through March 31, 2026. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $408 million in reimbursement as of March 31, 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 have now filed three complaints in the Baker County and Union County Circuit Courts challenging the OPUC decision. These cases remain pending. 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 on April 19, 2026.
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 $97 million, including Idaho Power's AFUDC, for its share of the project through March 31, 2026.
The permitting phase of the GWW project was subject to review and approval of the Bureau of Land Management (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 the segment of line between the Hemingway substation and the Midpoint substation near Jerome, Idaho. On April 3, 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 130-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 this section of line or a portion of this segment will be 2028 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 planned 285-mile high-voltage transmission line 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 expects construction of the project to commence in 2026 and to be completed in 2028 or thereafter. Idaho Power is responsible 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.
Defined Benefit Pension Plan Contributions
Idaho Power has no minimum contribution to its defined benefit pension plan required in 2026, and during the three months ended March 31, 2026, Idaho Power has 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 three months ended March 31, 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.
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 Open Access Transmission Tariff. 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.
Notable Pending Retail Rate or Revenue Changes
During 2025 and 2026, Idaho Power has filed applications requesting orders authorizing the rate or revenue changes summarized in the table below.
Description Status
Estimated Impact(1)
Notes
PCA - Idaho Filed April 15, 2026; Pending $51.6 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 Filed March 13, 2026; Pending $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 Filed October 31, 2025; Pending $1.5 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 Filed February 27, 2026; Pending $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, in the first quarter of 2026, Idaho Power recorded $6.3 million 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, a battery storage lease, 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.
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 (2.4) - (2.4)
Prior amounts refunded through rates 11.5 0.1 11.6
Renewable energy credit sales (35.8) (1.5) (37.3)
Interest and other (0.6) - (0.6)
Balance at March 31, 2026
$ (68.3) $ (2.8) $ (71.1)
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 September 2025, Idaho Power filed an application with the IPUC for an order (1) approving the 25-year PPA with Blacks Creek Energy Center, LLC supplying 80 MW of output to Idaho Power and (2) acknowledging that the resulting expenses associated with the PPA are prudently incurred for ratemaking purposes. In March 2026, the IPUC approved the PPA and deemed the resulting expenses associated with the PPA prudently incurred.
In September 2025, Idaho Power filed an application with the IPUC for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant to meet an identified capacity deficit in 2028, as well as confirmation and approval by the IPUC of accrued AFUDC in connection with the project prior to the issuance of the CPCN. In March 2026, the IPUC approved the application.
In February 2026, Idaho Power filed an application with the IPUC to approve an all-source RFP to procure resources for Idaho Power's anticipated energy and capacity needs as early as 2031 and into 2032. In April 2026, the IPUC approved the application with certain modifications from Idaho Power's initial application.
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.
On April 3, 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.
Large Customer Rate Proceedings
In December 2024, Idaho Power filed an application with the IPUC for approval of a special 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 special contract anticipates a
significant increase in load on Idaho Power's system that will ramp over a number of years beginning in 2026. As of the date of this report, the case 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 also requested that USFWS and NMFS initiate formal consultation under section 7 of the ESA, indicating that it considered the draft supplemental EIS its biological assessment. 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 $547 million (including AFUDC) for the HCC were included in construction work in progress at March 31, 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 March 31, 2026, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $294 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 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. As of the date of this report, the case remains pending.
American Falls Relicensing: In 2020, Idaho Power filed with the FERC a notice of intent to file an application 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. Idaho Power filed the final relicensing application with the FERC in February 2023. 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.
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.
Current and future environmental laws and regulations could significantly increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation or conversion to natural gas, as the cost of compliance makes coal plants uneconomical to operate. The decision to end coal-fired operations at Idaho Power's jointly-owned gas-fired generating plant in Valmy, Nevada was based in part on the economics of continuing coal-fired generation at the plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.
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 will 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. On April 13, 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. Each of the published proposed rules is subject to public comment and remains pending as of the date of this report.
In February 2026, the EPA finalized the following:
•a rule rescinding the EPA's 2009 greenhouse gas endangerment finding; and
•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 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. Idaho Power does not expect any near-term impact on its plans or operations as a result of the rescission of the endangerment finding and the amendments to the MATS Rule but will continue to monitor any potential effects.
OTHER MATTERS
Idaho's Wildfire Standard of Care Act
In April 2025, Idaho enacted the Wildfire Standard of Care Act (Idaho Code § 61-1801 through 1808), which became effective in July 2025. The Act requires Idaho electric public utilities to prepare WMPs annually to mitigate wildfire risk, submit the plans to the IPUC for review and approval, and implement the plans upon IPUC approval. An electric utility's WMP approved by the IPUC establishes the utility's duty to its shareholders and the public with respect to wildfire risk. Idaho Power filed its WMP with the IPUC in October 2025, and in April 2026, the IPUC approved the WMP.
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.
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