Idacorp Inc.
10/30/2025 | Press release | Distributed by Public on 10/30/2025 06:05
Quarterly Report for Quarter Ending September 30, 2025 (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 2024 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 2024 Annual Report, IDACORP's and Idaho Power's management included a summary of their business objectives for the companies for 2025 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 some of the discussion in this MD&A. Some notable developments that have occurred since that report include the following:
•Idaho Power continues to focus on timely recovery of costs and earning a reasonable return on investment. In October 2025, Idaho Power reached a settlement stipulation with the IPUC Staff and certain other parties in the Idaho general rate case it filed in May 2025, providing for $110.0 million in additional Idaho-jurisdiction annual revenues, among other items. The settlement stipulation is more fully described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. The IPUC's decision in this matter is pending.
•Idaho Power continues to experience and forecast positive customer growth in its service area. During the first nine months of 2025, Idaho Power's customer count grew by over 11,500 customers and for the twelve months ended September 30, 2025, the customer growth rate was 2.3 percent.
•In September 2025, IDACORP's board of directors approved an increase in the regular quarterly cash dividend on IDACORP's common stock from $0.86 per share to $0.88 per share, as a part of a 193 percent increase in quarterly dividends over the last fourteen years.
•To help meet growing capacity and energy needs in 2027 and beyond, Idaho Power entered into the following transactions in 2025, which as of the date of this report remain subject to regulatory approval:
◦an agreement to purchase the output of a 100 MW solar facility, coupled with a 100 MW battery energy storage agreement, with a scheduled online date of June 2027;
◦an agreement to acquire an ownership interest in 250 MW and for rights to an additional 250 MW of northbound capacity on SWIP-N, a planned 285-mile high-voltage transmission line; and
◦an agreement to purchase the output of an 80 MW solar facility, with a scheduled online date of June 2027.
•So far in 2025, several key projects achieved notable milestones, underscoring significant progress towards Idaho Power addressing peak capacity and energy needs in 2025 and beyond:
◦commenced construction on the B2H transmission line, with an expected in-service date of late 2027;
◦a 20-year agreement for Idaho Power to utilize storage capacity from a third-party 150 MW battery storage facility commenced, with the facility fully operational;
◦80 MW of company-owned battery storage facilities came on-line, with another 250 MW of company-owned battery storage commencing construction; and
◦Idaho Power filed a CPCN request with the IPUC for a 167 MW expansion of the existing Bennett Mountain natural gas generation facility, with an expected in-service date in 2028.
•In June 2025, Idaho Power filed with the Idaho and Oregon public utility commissions its 2025 IRP, its forecast of load and resources for the next 20 years, including the preferred portfolio of resources necessary to meet predicted demands.
•In September 2025, Idaho Power and the developer of the 600 MW Jackalope Wind project terminated the agreements for the project due to permitting delays and uncertainty around federal land use policies. Accordingly, Idaho Power filed a petition with the IPUC to withdraw the CPCN and approval of the PPA for the project that had previously been approved in June 2025. Idaho Power is pursuing alternative capacity and energy resources to meet the power generation deficit resulting from the termination of these agreements.
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 for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except earnings per share amounts):
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||
| Idaho Power net income | $ | 122,156 | $ | 111,089 | $ | 273,121 | $ | 245,779 | ||||||||||||||||||
| Net income attributable to IDACORP, Inc. | $ | 124,437 | $ | 113,605 | $ | 279,865 | $ | 251,298 | ||||||||||||||||||
| Weighted average outstanding shares - diluted | 55,055 | 53,485 | 54,522 | 52,179 | ||||||||||||||||||||||
| IDACORP, Inc. earnings per diluted share | $ | 2.26 | $ | 2.12 | $ | 5.13 | $ | 4.82 | ||||||||||||||||||
The table below provides a reconciliation of net income attributable to IDACORP for the three months and nine months ended September 30, 2025, from the same periods in 2024 (items are in millions and are before related income tax impact unless otherwise noted):
| Three months ended | Nine months ended | |||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. - September 30, 2024 | $ | 113.6 | $ | 251.3 | ||||||||||||||||||||||
|
Increase (decrease) in Idaho Power net income:
|
||||||||||||||||||||||||||
|
Retail revenues per MWh, net of power cost adjustment mechanisms
|
17.6 | 37.2 | ||||||||||||||||||||||||
| Customer growth, net of associated power supply costs and power cost adjustment mechanisms | 7.8 | 19.6 | ||||||||||||||||||||||||
| Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms | (5.7) | (0.8) | ||||||||||||||||||||||||
| Other O&M expenses | (4.2) | (22.5) | ||||||||||||||||||||||||
| Depreciation and amortization expense | (8.1) | (20.3) | ||||||||||||||||||||||||
|
Other changes in operating revenues and expenses, net
|
4.3 | 1.1 | ||||||||||||||||||||||||
| Increase in Idaho Power operating income | 11.7 | 14.3 | ||||||||||||||||||||||||
| Non-operating expense, net | (9.8) | (19.0) | ||||||||||||||||||||||||
| Additional ADITC amortization | - | 16.5 | ||||||||||||||||||||||||
| Income tax expense, excluding additional ADITC amortization | 9.1 | 15.5 | ||||||||||||||||||||||||
| Total increase in Idaho Power net income | 11.0 | 27.3 | ||||||||||||||||||||||||
|
Other IDACORP changes (net of tax)
|
(0.2) | 1.3 | ||||||||||||||||||||||||
| Net income attributable to IDACORP, Inc. - September 30, 2025 | $ | 124.4 | $ | 279.9 | ||||||||||||||||||||||
Net Income - Third Quarter 2025
IDACORP's net income increased $10.8 million for the third quarter of 2025 compared with the third quarter of 2024, 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 $17.6 million in the third quarter of 2025 compared with the third quarter of 2024. This benefit was due primarily to an overall
increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. For more information on the 2024 Idaho Limited-Issue Rate Case, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2024 Annual Report.
Customer growth increased operating income by $7.8 million in the third quarter of 2025 compared with the third quarter of 2024, as the number of Idaho Power customers grew by approximately 15,000, or 2.3 percent, during the twelve months ended September 30, 2025. Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms, decreased operating income by $5.7 million in the third quarter of 2025 compared with the third quarter of 2024. Irrigation usage per customer decreased most significantly, as higher precipitation in the third quarter of 2025 compared with the third quarter of 2024 led irrigation customers to use less energy for operating irrigation pumps.
Other O&M expenses in the third quarter of 2025 were $4.2 million higher than the third quarter of 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and an increase in wildfire mitigation program and related insurance expenses.
Depreciation and amortization expense increased $8.1 million in the third quarter of 2025 compared with the third quarter of 2024, 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 $4.3 million in the third quarter of 2025 compared with the third quarter of 2024, due primarily to a decrease in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms.
Non-operating expense, net, increased $9.8 million in the third quarter of 2025 compared with the third quarter of 2024. Higher long-term debt balances and an increase in transmission customer deposits, on which Idaho Power must pay interest to the customer, led to an increase in interest expense. Interest on a new finance lease also contributed to the increase compared with the third quarter of 2024. This increase was partially offset by an increase in AFUDC in the third quarter of 2025 compared with the third quarter of 2024, as the average construction work in progress balance was higher.
The decrease in income tax expense for the third quarter of 2025, compared with the third quarter of 2024, was primarily due to income tax return adjustments for state taxes and plant-related flow-through items.
Net Income - Year-To-Date 2025
IDACORP's net income increased $28.6 million for the first nine months of 2025 compared with the first nine months of 2024, due primarily to higher net income at Idaho Power.
The net increase in retail revenues per MWh, net of power cost adjustment mechanisms, increased operating income by $37.2 million in the first nine months of 2025 compared with the first nine months of 2024. This benefit was due primarily to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case.
Customer growth increased operating income by $19.6 million in the first nine months of 2025 compared with the first nine months of 2024. Overall, usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms, was relatively flat in the first nine months of 2025 compared with the first nine months of 2024.
Total other O&M expenses in the first nine months of 2025 were $22.5 million higher than the first nine months of 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and an increase in wildfire mitigation program and related insurance expenses, as well as higher variable employee compensation based on the expected achievement level of performance-based metrics.
Depreciation and amortization expense increased $20.3 million for the first nine months of 2025 compared with the first nine months of 2024, 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 $1.1 million in the first nine months of 2025 compared with the first nine months of 2024, due primarily to a decrease in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms, which increased operating
income compared with the first nine months of 2024. This was partially offset by the timing of recording and adjusting of regulatory accruals and deferrals during the first nine months of 2024 that did not reoccur in 2025.
Non-operating expense, net, increased $19.0 million in the first nine months of 2025 compared with the first nine months of 2024. Higher long-term debt balances and an increase in transmission customer deposits, on which Idaho Power must pay interest to the customer, led to an increase in interest expense. Interest on a new finance lease also contributed to the increase compared with the first nine months of 2024. This increase was partially offset by an increase in AFUDC in the first nine months of 2025 compared with the first nine months of 2024, as the average construction work in progress balance was higher.
The decrease in income tax expense for the first nine months of 2025, compared with the first nine months of 2024, was primarily due to income tax return adjustments for state taxes and plant-related flow-through items as well as a $16.5 million increase in additional ADITC amortization. Based on Idaho Power's current expectations of full-year 2025 financial results, Idaho Power recorded $39.0 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during the first nine months of 2025, compared with $22.5 million of additional ADITC amortization during the same period in 2024.
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.
To address the regulatory lag in recovery of costs primarily associated with Idaho Power's current and anticipated significant infrastructure investments, in May 2025 Idaho Power filed a general rate case in Idaho. In October 2025, Idaho Power, the Staff of the IPUC, and several of the intervening parties filed a settlement stipulation with the IPUC related to the 2025 Idaho general rate case filing. The settlement stipulation is subject to approval by the IPUC. The general rate case filing and the settlement stipulation are described more fully in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.
•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. 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 is pursuing timely inclusion of completed capital projects into rate base as part of the 2025 general rate case filing and intends to continue to do so in future general rate cases or other appropriate regulatory proceedings.
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 September 30, 2025, 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.
Idaho Power filed its 2025 IRP, its 20-year forecast of load and power supply resource options, with the IPUC and OPUC in June 2025. Included in the below table are the load forecast assumptions the company used in the 2025 IRP and, for comparison purposes, the analogous average annual growth rates Idaho Power used in the prior two IRPs.
| 5-Year Forecasted Annual Growth Rate | 20-Year Forecasted Annual Growth Rate | |||||||||||||||||||||||||
|
Retail Sales (Billed MWh) |
Annual Peak (Peak Demand) |
Retail Sales (Billed MWh) |
Annual Peak (Peak Demand) |
|||||||||||||||||||||||
| 2025 IRP | 8.3% | 5.1% | 2.7% | 1.9% | ||||||||||||||||||||||
| 2023 IRP | 5.5% | 3.7% | 2.1% | 1.8% | ||||||||||||||||||||||
| 2021 IRP | 2.6% | 2.1% | 1.4% | 1.4% | ||||||||||||||||||||||
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. This includes the B2H, GWW, and SWIP-N transmission projects, along with other capacity, energy, and transmission resource procurements, described in "Liquidity and Capital Resources" in this MD&A.
•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 2025, Idaho Power expects generation from its hydropower resources to be in the range of 6.5 million to 7.0 million MWh, compared with actual generation of 7.2 million MWh in 2024 and a 30-year average annual total of approximately 7.7 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.
•Regulatory and Environmental Compliance Costs; Coal Plant Retirements: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Moreover, environmental laws and regulations may increase the cost of constructing new facilities, may increase the cost of operating generation plants, may require that Idaho Power install additional pollution control devices at existing generating plants, may result in penalties for non-compliance, even where inadvertent, or may require that Idaho Power curtail or cease operating certain generation plants. Idaho Power expects to spend significant amounts on environmental compliance and controls for the foreseeable future. Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its North Valmy plant, ceasing participation in coal-fired operations at one unit in 2019 and planning to cease coal-fired operations at the remaining unit by year-end 2025. Idaho Power's jointly-owned coal plant in Boardman, Oregon, ceased operations in October 2020. In 2022, the IPUC approved Idaho Power's request to allow the coal-related assets at the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. Idaho Power's 2025 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of the two units at the North Valmy plant in 2026 and the remaining two units at the Jim Bridger plant in 2030. Units 1 and 2 at the Jim Bridger plant were converted to natural gas in the second quarter of 2024. In June 2024, Idaho Power executed an agreement with its co-owner to facilitate the planned conversion of the two units at the North Valmy plant from coal to natural gas by mid-2026.
•Water Management and Relicensing of Hydropower Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal licenses for the HCC, its largest hydropower generation source, and for American Falls, its second largest hydropower capacity resource. Given the number of parties involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. As of the date of this report, Idaho Power cannot determine the ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls hydropower facilities.
•Wildfire Mitigation Efforts: In recent years, the western United States has experienced an increasing number of wildfires of unprecedented severity. 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 health. Idaho Power is taking a proactive approach to wildfire risk in its service area and transmission corridors. Idaho Power has developed and 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. 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 2024 Annual Report and the condensed consolidated financial statements included in this report. In July 2025, the Idaho Wildfire Standard of Care Act became effective. In October 2025, Idaho Power filed a new WMP with the IPUC in accordance with the Act. As of the date of this report, the IPUC's decision is pending. See "Other Matters - Idaho Wildfire Standard of Care Act" for additional detail.
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 nine months ended September 30, 2025. In this analysis, the results for the three months and nine months ended September 30, 2025, are compared with the same periods in 2024.
The table below presents Idaho Power's energy sales and supply (in thousands of MWh) for the three months and nine months ended September 30, 2025 and 2024.
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||
| Retail energy sales | 4,854 | 4,854 | 12,677 | 12,355 | ||||||||||||||||||||||
| Wholesale energy sales | 193 | 126 | 1,230 | 1,355 | ||||||||||||||||||||||
| Energy sales bundled with renewable energy credits | 26 | - | 641 | 959 | ||||||||||||||||||||||
| Total energy sales | 5,073 | 4,980 | 14,548 | 14,669 | ||||||||||||||||||||||
| Hydropower generation | 1,483 | 1,598 | 5,751 | 6,008 | ||||||||||||||||||||||
|
Steam generation(1)
|
1,046 | 1,080 | 2,183 | 1,896 | ||||||||||||||||||||||
| Natural gas and other generation | 1,276 | 1,261 | 2,802 | 2,822 | ||||||||||||||||||||||
| Total system generation | 3,805 | 3,939 | 10,736 | 10,726 | ||||||||||||||||||||||
| Purchased power | 1,641 | 1,375 | 4,849 | 4,902 | ||||||||||||||||||||||
| Line losses | (373) | (334) | (1,037) | (959) | ||||||||||||||||||||||
| Total energy supply | 5,073 | 4,980 | 14,548 | 14,669 | ||||||||||||||||||||||
(1) "Steam generation" is composed of generation from steam plants that are fueled by only coal or by both coal and natural gas.
Weather-related information for Boise, Idaho, for the three months and nine months ended September 30, 2025 and 2024, 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 September 30, |
Nine months ended September 30, |
|||||||||||||||||||||||||||||||||||||
| 2025 | 2024 |
Normal (2)
|
2025 | 2024 |
Normal (2)
|
|||||||||||||||||||||||||||||||||
|
Heating degree-days(1)
|
7 | 47 | 94 | 2,989 | 2,951 | 3,181 | ||||||||||||||||||||||||||||||||
|
Cooling degree-days(1)
|
967 | 1,147 | 847 | 1,248 | 1,419 | 1,035 | ||||||||||||||||||||||||||||||||
| Precipitation (inches) | 1.7 | 0.3 | 0.8 | 8.1 | 11.2 | 8.0 | ||||||||||||||||||||||||||||||||
(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 were flat in the third quarter of 2025 compared with the same period in 2024. This was primarily due to growth in the number of Idaho Power customers, which was mostly offset by a decrease in usage per customer in all customer classes. Greater precipitation and moderate temperatures in Idaho Power's service area during the third quarter of 2025, compared with the third quarter of 2024, led irrigation customers to operate irrigation pumps less. Residential and commercial customers also used less energy per customer for cooling purposes compared to the same period in 2024, contributing to the lower volumes. Retail sales volumes increased 3 percent in the first nine months of 2025 compared with the same period in 2024, primarily due to 2.3 percent growth in the number of Idaho Power customers 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 3 percent for the third quarter of 2025 compared with the third quarter of 2024, due primarily to lower hydropower generation and steam generation, offset partially by an increase in natural gas generation. Total
system generation increased slightly in the first nine months of 2025 compared with the same period in 2024, which consists of an increase in steam generation, partially offset by decreased hydropower 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) and MWh sales volumes (in thousands) for the three months and nine months ended September 30, 2025 and 2024, and the number of customers as of September 30, 2025 and 2024.
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||
| Retail revenues: | ||||||||||||||||||||||||||
|
Residential (includes $(4,125), $(6,193), $(9,194), and $(8,982), respectively, related to the FCA)(1)
|
$ | 195,445 | $ | 195,291 | $ | 535,505 | $ | 525,353 | ||||||||||||||||||
|
Commercial (includes $(70), $(66), $(150), and $(158), respectively, related to the FCA)(1)
|
111,510 | 112,323 | 304,014 | 303,031 | ||||||||||||||||||||||
| Industrial | 72,079 | 71,908 | 205,526 | 203,990 | ||||||||||||||||||||||
| Irrigation | 101,690 | 109,861 | 195,172 | 191,671 | ||||||||||||||||||||||
|
Deferred revenue related to HCC relicensing AFUDC(2)
|
(2,854) | (2,881) | (6,848) | (6,913) | ||||||||||||||||||||||
| Total retail revenues | $ | 477,870 | $ | 486,502 | $ | 1,233,369 | $ | 1,217,132 | ||||||||||||||||||
| Volume of retail sales (MWh) | ||||||||||||||||||||||||||
| Residential | 1,621 | 1,596 | 4,593 | 4,451 | ||||||||||||||||||||||
| Commercial | 1,191 | 1,182 | 3,302 | 3,262 | ||||||||||||||||||||||
| Industrial | 984 | 954 | 2,817 | 2,744 | ||||||||||||||||||||||
| Irrigation | 1,058 | 1,122 | 1,965 | 1,898 | ||||||||||||||||||||||
| Total retail MWh sales | 4,854 | 4,854 | 12,677 | 12,355 | ||||||||||||||||||||||
| Number of retail customers at period end | ||||||||||||||||||||||||||
| Residential | 557,065 | 543,520 | ||||||||||||||||||||||||
| Commercial | 80,707 | 79,328 | ||||||||||||||||||||||||
| Industrial | 150 | 145 | ||||||||||||||||||||||||
| Irrigation | 22,620 | 22,549 | ||||||||||||||||||||||||
| Total customers | 660,542 | 645,542 | ||||||||||||||||||||||||
(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, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Effective October 1, 2025, this amount will increase by $29.7 million annually; refer to Note 3 - "Regulatory Matters."
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 decreased $8.6 million during the third quarter of 2025, compared with the same period in 2024. Retail revenues increased $16.2 million during the first nine months of 2025, compared with the same period in 2024. 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 $17.6 million and $37.2 million, respectively, for the three months and nine months ended September 30, 2025, compared with the same periods in 2024, due primarily to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which decreased revenues by $27.7 million and $51.2 million, in the third quarter and first nine months of 2025, respectively, compared with the same periods of 2024. 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 September 30, 2025, increased retail revenues by $12.4 million and $30.4 million in the third quarter and first nine months of 2025, respectively, compared with the same periods of 2024.
•Usage: Lower usage (on a per customer basis), in all customer classes decreased retail revenues by $12.9 million in the third quarter of 2025 compared with the same period of 2024, primarily due to weather variations that caused lower usage per customer. Greater precipitation and more moderate temperatures in Idaho Power's service area during the third quarter of 2025 led agricultural irrigation customers to use less energy per customer to operate irrigation pumps and residential and commercial customers to use less energy per customer for cooling purposes compared with the same period in 2024. During the first nine months of 2025, usage in all customer classes was relatively flat, compared with the same period of 2024.
•FCA Mechanism: A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $2.1 million in the third quarter of 2025 compared with the same period in 2024. Conversely, an increase in the deferral of residential and small commercial customer revenues through the FCA mechanism negatively affected retail revenues by $0.2 million during the first nine months of 2025 compared with the same period in 2024.
Wholesale Energy Sales:Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the energy imbalance market in the western United States, and do not include derivative transactions. The table below presents Idaho Power's wholesale energy sales for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except for revenue per MWh amounts).
|
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Wholesale energy revenues | $ | 10,520 | $ | 6,946 | $ | 45,443 | $ | 65,759 | |||||||||||||||
| Wholesale MWh sold | 193 | 126 | 1,230 | 1,355 | |||||||||||||||||||
| Wholesale energy revenues per MWh | $ | 54.51 | $ | 55.13 | $ | 36.95 | $ | 48.53 | |||||||||||||||
In the third quarter of 2025, wholesale energy revenues increased $3.6 million compared with the same period of 2024, due primarily to an increase in wholesale energy volumes sold. Wholesale energy revenues decreased $20.3 million in the first nine months of 2025, due primarily to lower wholesale market prices compared with 2024. Wholesale energy prices were lower during the third quarter and first nine months of 2025 compared with 2024 as more moderate winter and summer weather resulted in lower power prices in the wholesale markets in the region. 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 for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except for per MWh amounts).
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||
| Purchased power expense | $ | 121,276 | $ | 114,578 | $ | 284,163 | $ | 321,860 | ||||||||||||||||||
| MWh purchased | 1,641 | 1,375 | 4,849 | 4,902 | ||||||||||||||||||||||
| Average cost per MWh | $ | 73.90 | $ | 83.33 | $ | 58.60 | $ | 65.66 | ||||||||||||||||||
Purchased power expense increased $6.7 million, or 6 percent, during the third quarter of 2025 compared with the third quarter of 2024, primarily due to a 19 percent increase in MWh purchased to help meet customer demand. Purchased power expense decreased $37.7 million, or 12 percent, during the first nine months of 2025, compared with the same period of 2024, primarily due to lower wholesale energy market prices in the region.
Fuel Expense:The table below presents Idaho Power's fuel expenses and thermal generation for the three months and nine months ended September 30, 2025 and 2024 (in thousands, except for per MWh amounts).
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||
| Fuel Expense | ||||||||||||||||||||||||||
|
Steam(1)
|
$ | 37,350 | $ | 33,145 | $ | 85,082 | $ | 74,554 | ||||||||||||||||||
|
Natural gas(2)
|
37,642 | 40,326 | 94,156 | 113,857 | ||||||||||||||||||||||
| Total fuel expense | $ | 74,992 | $ | 73,471 | $ | 179,238 | $ | 188,411 | ||||||||||||||||||
| MWh generated | ||||||||||||||||||||||||||
|
Steam(1)
|
1,046 | 1,080 | 2,183 | 1,896 | ||||||||||||||||||||||
|
Natural gas(2)
|
1,276 | 1,261 | 2,802 | 2,822 | ||||||||||||||||||||||
| Total MWh generated | 2,322 | 2,341 | 4,985 | 4,718 | ||||||||||||||||||||||
| Average cost per MWh - Steam | $ | 35.71 | $ | 30.69 | $ | 38.97 | $ | 39.32 | ||||||||||||||||||
| Average cost per MWh - Natural gas | $ | 29.50 | $ | 31.98 | $ | 33.60 | $ | 40.35 | ||||||||||||||||||
| Weighted average, all sources | $ | 32.30 | $ | 31.38 | $ | 35.96 | $ | 39.93 | ||||||||||||||||||
(1) "Steam" is composed of expenses and generation from steam plants that are fueled by only coal or by both coal and natural gas.
(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 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 increased $1.5 million, or 2 percent, in the third quarter of 2025, but decreased $9.2 million, or 5 percent, in the first nine months of 2025 compared with the same periods of 2024. The increase in fuel expense in the third quarter of 2025 compared with the third quarter of 2024 was primarily due to a 3 percent increase in the total average cost per MWh from all sources and partially offset by a 1 percent decrease in MWh generated from steam and natural gas generation. The decrease in fuel expense in the first nine months of 2025 compared with the same period of 2024, was primarily due to a 10 percent decrease in the total average cost per MWh from all sources and partially offset by a 6 percent increase in MWh generated from steam and natural gas generation to serve load compared with the same period in 2024.
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 third quarters of 2025 and 2024, and the first nine months of 2025 and 2024, losses on
financial gas hedges of $9.1 million and $18.4 million, and $21.9 million and $43.4 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, battery storage leases, 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 for the three months and nine months ended September 30, 2025 and 2024 (in thousands).
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||
| Idaho power supply cost (deferral) accrual | $ | (2,002) | $ | (6,759) | $ | 46,935 | $ | 26,761 | ||||||||||||||||||
| Oregon power supply cost (deferral) accrual | (523) | 118 | (2,317) | 2,471 | ||||||||||||||||||||||
| Amortization of prior year authorized balances | (15,770) | 27,420 | 13,349 | 73,065 | ||||||||||||||||||||||
| Total power cost adjustment (income statement) | $ | (18,295) | $ | 20,779 | $ | 57,967 | $ | 102,297 | ||||||||||||||||||
The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. During the third quarter of 2025, higher purchased power and fuel costs led to higher actual power supply costs compared with the forecasted amount, which resulted in a deferral of power supply costs by the mechanism. During the first nine months of 2025, purchased power 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 $4.2 million and $22.5 million in the third quarter and first nine months of 2025, respectively, compared with the same periods of 2024. These increases were primarily driven by inflationary pressures on labor-related costs, professional services, an increase in wildfire mitigation program and related insurance expenses, as well as higher variable employee compensation based on the expected achievement level of performance-based metrics.
Income Taxes
IDACORP's and Idaho Power's income tax expense decreased $30.3 million and $32.0 million, respectively, for the nine months ended September 30, 2025, when compared with the same period in 2024, primarily due to income tax return adjustments for state taxes and plant-related flow-through items, and increased 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 2024 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.
As of October 24, 2025, 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, including a remaining aggregate gross sales price of up to $155 million in shares of IDACORP common stock available for issuance through its ATM offering program;
•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 October 24, 2025, would have been approximately $144 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 October 24, 2025, would have been approximately $562 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; $500 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 use original issuances for share purchases within the Idaho Power Company Employee Savings Plan beginning in the fourth quarter of 2025. IDACORP may discontinue using original issuances of shares for these plans at any time.
During 2025, IDACORP executed FSAs under its ATM offering program with various counterparties at an aggregate gross sales price of $52 million. Additionally, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties at an aggregate gross sales price of $575 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.
Further, during 2025, Idaho Power issued $400 million in first mortgage bonds and repaid approximately $20 million in maturing variable rate 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.
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.
IDACORP and Idaho Power monitor capital markets with a view toward favorable debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue first mortgage bonds or other debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. IDACORP may also elect to issue common stock, from time to time, under its ATM offering program, depending on market conditions and capital needs. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness.
Based on planned capital expenditures and 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 September 30, 2025, 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 | 52% | 54% | ||||||||||||
| Equity | 48% | 46% | ||||||||||||
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 September 30, 2025, 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 2025.
Operating Cash Flows
IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, income taxes, and plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level currently allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.
IDACORP's and Idaho Power's operating cash inflows for the nine months ended September 30, 2025, were $464 million and $465 million, respectively, an increase in cash flows from operations of $6 million for IDACORP and a decrease of $5 million for Idaho Power, when compared with the same period in 2024. 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 nine months of 2025 when compared with the same period in 2024 were as follows:
•a $28 million and $27 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 $32 million;
•changes in deferred taxes and taxes accrued and receivable combined to decrease operating cash flows for IDACORP and Idaho Power by $18 million and $8 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 by $31 million for IDACORP and $33 million for Idaho Power;
◦the changes in prepayments increased operating cash flow by $4 million for IDACORP and Idaho Power, which was primarily due to the timing of insurance prepayments;
◦the changes in materials, supplies, and fuel stock increased operating cash flows by $67 million for IDACORP and Idaho Power, which was due to the timing of purchases and consumption of materials and supplies inventory at Idaho Power and coal at Idaho Power's jointly-owned coal-fired generating plants;
◦the changes in accounts and wages payable decreased operating cash flows by $17 million for Idaho Power, which was primarily due to intercompany tax payments; and
◦the changes in other assets and liabilities decreased operating cash flows by $27 million for IDACORP and Idaho Power. This decrease was primarily related to the timing of refundable transmission network upgrade deposits and a power purchase agreement security deposit.
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 nine months ended September 30, 2025, were $731 million and $717 million, respectively, decreasing cash outflow by $26 million for IDACORP and by $37 million for Idaho Power when compared with the same period in 2024. Investing cash outflows for 2025 and 2024 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 2025 and 2024 by reimbursements from a B2H project joint permitting participant relating to a portion of the permitting expenditures.
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 nine months ended September 30, 2025, were $231 million and $230 million, respectively, a decrease of $168 million and $138 million for IDACORP and Idaho Power, respectively, when compared with the same period in 2024. IDACORP and Idaho Power financing cash inflows for 2025 were primarily related to Idaho Power's net proceeds from the issuance of first mortgage bonds, partially offset by the repayment of variable rate bonds and dividend payments. IDACORP and Idaho Power financing cash inflows for 2024 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. 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 2025, IDACORP executed FSAs under its ATM offering program with various counterparties, at an aggregate gross sales price of $52 million. IDACORP did not execute any FSAs or otherwise issue shares under the ATM offering program after March 2025. At September 30, 2025, IDACORP's cumulative aggregate gross sales price of executed and outstanding FSAs under its ATM offering program was $145 million, and $155 million in shares of IDACORP's common stock remained available for issuance. If IDACORP had elected to physically settle the FSAs under its ATM offering program as of October 24, 2025, by delivering shares of common stock, cash proceeds would have been approximately $144 million. IDACORP may settle the FSAs under its ATM offering program at any time, up to their respective maturity dates, of approximately one year following execution.
In May 2025, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties at an aggregate gross sales price of $575 million. If IDACORP had elected to physically settle these FSAs as of October 24, 2025, by delivering shares of common stock, cash proceeds would have been approximately $562 million. IDACORP may 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 September 30, 2025, $500 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).
| September 30, 2025 | December 31, 2024 | |||||||||||||||||||||||||
|
IDACORP(2)
|
Idaho Power |
IDACORP(2)
|
Idaho Power | |||||||||||||||||||||||
| Revolving credit facility | $ | 100,000 | $ | 400,000 | $ | 100,000 | $ | 400,000 | ||||||||||||||||||
| Commercial paper outstanding | - | - | - | - | ||||||||||||||||||||||
|
Identified for other use(1)
|
- | - | - | (19,885) | ||||||||||||||||||||||
| Net balance available | $ | 100,000 | $ | 400,000 | $ | 100,000 | $ | 380,115 | ||||||||||||||||||
(1) American Falls bonds that Idaho Power could have been required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds had been unable to sell the bonds to third parties. The American Falls bonds were repaid in full on February 3, 2025.
(2) Holding company only.
On October 24, 2025, IDACORP and Idaho Power had no loans outstanding under their 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. There have been no changes to IDACORP's or Idaho Power's ratings by Standard & Poor's Ratings Services or Moody's Investors Service from those included in the 2024 Annual Report. However, any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.
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 $799 million during the nine months ended September 30, 2025. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2025 (including amounts incurred to-date) through 2029 (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. Given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table. The timing and amount of actual constructed projects and capital expenditures could be affected by Idaho Power's ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, permitting, legal processes, regulatory determinations, inflationary pressures, macroeconomic conditions, tariffs, or other issues, including those described below.
| 2025 | 2026 | 2027-2029 | ||||||||||||||||||
| Expected capital expenditures (excluding AFUDC), in billions of dollars | $1.00-$1.10 | $1.25-$1.35 | $3.10-$3.60 | |||||||||||||||||
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 2024 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 over the next several years. To help meet peak needs in 2025 and beyond, Idaho Power:
•entered into contracts or plans to purchase, own, and operate 330 MW of battery storage assets with expected useful lives of approximately 20 years;
•entered into two 20-year agreements to purchase the storage capacity from battery storage facilities totaling 250 MW;
•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 the combined 825 MW output of planned third-party solar facilities. Idaho Power plans to sell the output of three of these solar PPAs totaling 645 MW exclusively to a large industrial customer pursuant to an agreement under Idaho Power's Clean Energy Your Way program; and
•submitted an application to the IPUC for a CPCN for an expansion of generating capacity at the existing Bennett Mountain power plant of up to 167 MW of natural gas-fueled generation in 2028.
The capital requirements table above includes capital expenditures of more than $730 million from 2025 through 2029 for resource additions to address projected energy and capacity deficits in those years and beyond. 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, will 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 transmission line will be in service by late 2027.
As more fully described in the 2024 Annual Report, Idaho Power's ownership interest in the project is approximately 45 percent. Idaho Power has spent approximately $578 million, including Idaho Power's AFUDC, on the B2H project through September 30, 2025. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $300 million in reimbursement as of September 30, 2025, 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.
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, two parties filed complaints with the OPUC seeking reconsideration of the CPCN granted for B2H. OPUC's case to address these complaints is in its initial stages and remains pending as of the date of this report.
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 $500 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining material procurement and construction of the project. Actual construction costs could differ from Idaho Power's estimates based upon Idaho Power's or its contractors' ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, tariffs, macroeconomic conditions, or other issues.
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. In 2012, Idaho Power and PacifiCorp entered into a joint funding agreement for permitting of the project.
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 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho. Current permitting and pre-construction activities are focused on Segment 8, the section of line between the Hemingway substation and the Midpoint substation near Jerome, Idaho. Idaho Power's ownership interest in Segment 8 is 99 percent. Idaho Power expects the in-service date for this section of line or a portion of this section will be no earlier than 2028. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs including potentially modifying the ownership structure of a few segments of the project.
Idaho Power has expended approximately $84 million, including Idaho Power's AFUDC, for its share of the project through September 30, 2025. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and Segment 8 construction) to be between $900 million and $1.1 billion, including Idaho Power's AFUDC. The estimated cost range is based on assumptions about Idaho Power participation levels in the construction of certain project segments, and any changes in those assumptions or in Idaho Power's actual participation could affect future estimates and actual project costs. The capital requirements table above includes approximately $615 million of Idaho Power's share of estimated
costs (excluding AFUDC), based on Idaho Power's current estimate that it may commence construction of applicable segments during that time period. Actual construction costs could differ from Idaho Power's estimates based upon the ability of Idaho Power, PacifiCorp, or their respective contractors to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, tariffs, macroeconomic conditions, or other issues.
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 take approximately two years to complete. 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.
Jackalope Wind Project: In October 2024, Idaho Power entered into agreements with a counterparty and certain of its affiliates to develop the Jackalope Wind Project, which consisted of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying a capacity of approximately 300 MW of generation to Idaho Power's system from a wind-powered generation facility located in Sweetwater County, Wyoming, and (ii) a co-located wind turbine generator power plant to be owned by Idaho Power, providing a capacity of 300 MW of generation. In September 2025, due to permitting delays and uncertainty around federal land use policies, Idaho Power, the counterparty, and the applicable affiliates of the counterparty terminated the agreements for the Project.
Defined Benefit Pension Plan Contributions
Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2025, and during the nine months ended September 30, 2025, Idaho Power contributed $20 million 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 nine months ended September 30, 2025, 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 2024 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, the OPUC, and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities. As a public utility under the Federal Power Act, Idaho Power has 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 (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.
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. In 2024, Idaho Power filed a limited-issue rate case in Idaho, the 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 May 2025, Idaho Power filed a general rate case in Idaho, requesting rates to be effective on or after January 1, 2026. The 2025 Settlement Stipulation was filed for that rate case on October 24, 2025. Refer to Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report for additional information regarding the Idaho general rate case filing and the 2025 Settlement Stipulation. 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 2024 Annual Report for additional information relating to the 2023 Idaho general rate case, 2024 Idaho Limited-Issue Rate Case, and Oregon general rate case.
Between general rate cases, Idaho Power relies upon customer growth, an FCA mechanism, power cost adjustment mechanisms, tariff riders, limited-issue rate proceedings, 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 2024 Annual Report. In addition to the discussion below, which includes notable regulatory developments since the discussion of these matters in the 2024 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 Retail Rate or Revenue Changes
During 2025, 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, 2025 | $94.8 million PCA decrease for the period from June 1, 2025 to May 31, 2026 | 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 decrease primarily reflects a decrease in the balancing adjustment, which is due primarily to the completed recovery of the 2023 balancing adjustment, which was recovered over two years. | |||||||||||||||||
| FCA - Idaho | New FCA rate became effective June 1, 2025 | $39.8 million FCA decrease for the period from June 1, 2025 to May 31, 2026 | 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, 2025 | $1.8 million APCU decrease for the period from June 1, 2025 to May 31, 2026 | The rate decrease reflects a decrease in expected net power supply expense for the March 2025 APCU forecast combined with an increase in normalized net power supply expense for the October 2024 APCU. | |||||||||||||||||
| HCC - Idaho | New rates became effective October 1, 2025 | $29.7 million increase, effective October 1, 2025 | The requested adjustment increases cash collection of AFUDC associated with relicensing of the HCC project. | |||||||||||||||||
(1) The annual amount collected in rates is typically not recovered on a straight-line basis (i.e., 1/12th per month), and is instead recovered in proportion to retail sales volumes.
Idaho Earnings Support and Sharing from Idaho Settlement Stipulations
The 2018 Settlement Stipulation and the 2023 Settlement Stipulation are each described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the 2024 Annual Report. The 2023 Settlement Stipulation modified the 2018 Settlement Stipulation in part. IDACORP and Idaho Power believe that the terms allowing additional amortization of ADITC 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 2025 Idaho ROE, in the third quarter and first nine months of 2025, Idaho Power recorded $2.5 million and $39.0 million, respectively, in additional ADITC amortization under the settlement stipulations. If approved by the IPUC, the 2025 Settlement Stipulation would modify the Idaho earnings support and sharing components as described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.
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, battery storage leases, 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 deferred (accrued) net power supply costs during the nine months ended September 30, 2025 (in millions).
| Idaho | Oregon | Total | ||||||||||||||||||
| Balance at December 31, 2024 | $ | 18.5 | $ | (3.9) | $ | 14.6 | ||||||||||||||
| Current period net power supply costs (accrued) deferred | (50.4) | 2.3 | (48.1) | |||||||||||||||||
| Prior amounts (collected) refunded through rates | (14.1) | 0.8 | (13.3) | |||||||||||||||||
| Renewable energy credit sales | (28.2) | (1.2) | (29.4) | |||||||||||||||||
| Interest and other | (1.8) | 0.1 | (1.7) | |||||||||||||||||
|
Balance at September 30, 2025
|
$ | (76.0) | $ | (1.9) | $ | (77.9) | ||||||||||||||
Open Access Transmission Tariff 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. In September 2025, Idaho Power filed its 2025 final transmission rate with the FERC, reflecting a transmission rate of $34.16 per kilowatt-year (kW-year), to be effective for the period from October 1, 2025, to September 30, 2026. Idaho Power's final rate was based on a net annual transmission revenue requirement of $148.5 million. The OATT rate in effect from October 1, 2024, to September 30, 2025, was $31.55 per kW-year based on a net annual transmission revenue requirement of $137.9 million. A kW-year is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours.
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 significant resources to meet projected capacity deficits in the near-term.
In August 2024, the OPUC issued an order approving Idaho Power's final RFP to procure resources for its anticipated energy and capacity needs in 2028 and beyond. Idaho Power issued the RFP in August 2024 soliciting resources with a commercial operation date (COD) no later than April 1, 2028 (2028 bids), as well as bids with a COD after April 1, 2028. In March 2025, the OPUC acknowledged the final shortlist of 2028 bids, subject to certain conditions. In July 2025, Idaho Power filed a request for acknowledgement from the OPUC for the final shortlist of bids with a COD no later than June 1, 2029 (2029 bids). Bids from Idaho Power are included in the final shortlist of 2029 bids. In August 2025, the OPUC acknowledged the final shortlist of 2029 bids, subject to certain conditions.
In December 2024, Idaho Power filed an application with the IPUC for the Jackalope Wind Project, consisting of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying a capacity of 300 MW of generation to Idaho Power's system, and (ii) a wind turbine generator power plant to be owned by Idaho Power, providing a capacity of 300 MW of generation. In its application, Idaho Power requested that the IPUC approve the PPA and grant a CPCN for the wind turbine generator power plant. In June 2025, the IPUC approved the PPA and granted the CPCN. However, due to the termination of the agreements for the Jackalope Wind Project following a delay in the planned commercial operation date of the Project, in September 2025, Idaho Power filed a petition with the IPUC to withdraw the CPCN and approval of the PPA for the Project. As of the date of this report, the IPUC's decision is pending.
Also in December 2024, Idaho Power filed an application with the IPUC to grant a CPCN for Idaho Power to acquire and own two battery storage facilities with a total of 100 MW of operating capacity to address Idaho Power's identified capacity deficiency in 2026. In October 2025, the IPUC granted the CPCN.
In March 2025, Idaho Power filed an application with the IPUC to grant a CPCN for Idaho Power to acquire an ownership interest, including the rights to 250 MW of northbound capacity, in 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. In its application, Idaho Power also requested that the IPUC approve the company's utilization of an additional 250 MW of rights to northbound capacity on SWIP-N. As of the date of this report, the case remains pending.
In March 2025, Idaho Power filed an application with the IPUC for an order (1) approving the 20-year PPA with Crimson Orchard Solar LLC supplying 100 MW of output to Idaho Power, (2) approving the 20-year energy storage agreement (ESA) with Crimson Orchard Solar for 100 MW of dispatchable energy storage capacity, and (3) acknowledging the lease accounting necessary to facilitate the transaction and that the resulting expenses associated with both the PPA and the ESA are prudently
incurred for ratemaking purposes. In August 2025, Idaho Power also filed with the IPUC for approval of amendments to the PPA and ESA for Crimson Orchard Solar. As of the date of this report, the IPUC's decision is pending.
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. As of the date of this report, the case remains pending.
In September 2025, Idaho Power filed an application with the IPUC for a CPCN for the expansion of Idaho Power's existing Bennett Mountain power plant to include the addition of a natural gas-fueled facility providing up to 167 MW of generation to meet an identified capacity deficit in 2028, as well as confirmation and approval by the IPUC of Idaho Power's accrual of AFUDC in connection with the expansion. 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 2024 Annual Report in Part II, Item 7 - MD&A - "Liquidity and Capital Resources" and "Regulatory Matters," in July 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 environmental impact statement (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 June 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 and the National Marine Fisheries Service under section 7 of the ESA. In April 2025, the FERC issued an updated schedule for the supplemental EIS with target dates for issuance of the draft and final supplemental EIS of September 2025 and May 2026, respectively. As of the date of this report, the FERC has not issued the draft supplemental EIS.
Relicensing costs of $526 million (including AFUDC) for the HCC were included in construction work in progress at September 30, 2025. 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 September 30, 2025, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $269 million. As discussed above, in March 2025, Idaho Power filed an application with the IPUC to increase the annual cash collection of AFUDC associated with relicensing of the HCC project from $8.8 million to $38.5 million. In September 2025, the IPUC approved Idaho Power's proposed increase in annual cash collection to recover AFUDC associated with relicensing of the HCC project, effective October 1, 2025.
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 2018, the IPUC issued an order approving a settlement stipulation, in response to an earlier application by Idaho Power, recognizing that a total of $216.5 million in Idaho Power expenditures through year-end 2015 on relicensing of the HCC were prudently incurred, and therefore should be eligible for inclusion in customer rates at a later date.
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. Three parties commented on the environmental assessment, and Idaho Power has responded to those comments.
Idaho Power's previous license at American Falls expired in February 2025. In March 2025, the FERC issued Idaho Power an annual license on the same terms and conditions as its prior license. The annual license is effective until February 28, 2026, or 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 2025.
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-fired power plant, its co-owned coal- and gas-fired power plant, 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 cease operation of the Boardman power plant in 2020 was based in part on the significant cost of compliance with environmental laws and regulations. The decision to end participation in coal-fired operations at the North Valmy plant was also 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 2024 Annual Report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2025 to 2027. Given the uncertainty of future environmental regulations and technological advances, Idaho Power cannot make near-term estimates with certainty and is also unable to predict its environmental-related expenditures beyond 2027, 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 2024 Annual Report. Recent developments in certain environmental matters relevant to Idaho Power are described below.
EPA Proposed 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); 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.
In June 2025, the EPA published proposed rules to repeal greenhouse gas emissions standards for fossil fuel-fired power plants and to repeal certain amendments to the MATS, 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. In August 2025, the EPA proposed a rule to reconsider the EPA's 2009 greenhouse gas endangerment finding. The proposed rules are subject to public comment and remain pending as of the date of this report. The EPA has not yet taken official action on any of the other items mentioned in its March 2025 announcement. Idaho Power will continue to actively monitor these 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
NEPA is a federal law that requires federal agencies to consider the environmental impacts of their actions and decisions. NEPA applies to Idaho Power's transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions. The Council on Environmental Quality (CEQ) under previous Presidential Administrations had issued guidance to federal agencies in issuing their own regulations regarding the implementation of NEPA for projects under their jurisdiction. However, a CEQ interim final rule effective in April 2025 removed all CEQ NEPA implementing regulations.
In addition, the U.S. Supreme Court clarified in the Seven County Infrastructure Coalition v. Eagle County, Coloradocase in May 2025 that NEPA imposes no substantive environmental obligations or restrictions, but rather is a procedural statute that requires federal agencies to weigh environmental consequences as the agency reasonably sees fit under its governing statute and any relevant substantive environmental laws.
In July 2025, a number of federal agencies, including the Department of the Interior, the Department of Energy, the Army Corps of Engineers, and the Department of Transportation, issued interim final rules revising their procedures for implementing NEPA. These interim final rules were issued in response to the Supreme Court's Seven Countydecision, the removal of the CEQ's NEPA implementing regulations, and the current Presidential Administration's executive orders regarding the energy industry.
These actions may result in significant changes to the way federal environmental laws and regulations are enforced, but as of the date of this report, Idaho Power is unable to predict the ultimate impact of these actions on Idaho Power and its operations.
Endangered Species Act Matters
In April 2025, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service issued a proposed rule to rescind the definition of "harm" under the ESA in their respective regulations. If adopted, the proposed rescission of the definition of harm would likely have the effect of reducing the applicability of the ESA in some contexts. As of the date of this report, Idaho Power is unable to determine with any specificity the impact on Idaho Power of the proposed rule.
Invasive Species Management
Quagga mussels are an invasive species that were first detected in the Snake River system in 2023 in the mid-Snake River near Twin Falls, Idaho, in Idaho Power's service area. Quagga mussel infestations can clog and damage irrigation, hydropower, and water delivery facilities and increase the costs to maintain such facilities. The Idaho State Department of Agriculture (ISDA) treated the affected area in 2023 and 2024 with a copper-based, EPA-approved treatment. ISDA sampling in 2025 detected the continued presence of quagga mussels. As a result, the ISDA performed additional treatments in September and October 2025 in an effort to eradicate quagga mussels in the affected area. As of the date of this report, Idaho Power cannot predict the extent
to which the additional treatments will be successful in eradicating quagga mussels from the Snake River or the potential increase in other O&M expenses related to quagga mussel mitigation efforts. If a quagga mussel infestation occurs, it may result in increased other O&M costs for mitigation efforts and other adverse impacts for Idaho Power's operation of its hydropower facilities in any infested areas.
OTHER MATTERS
One Big Beautiful Bill Act
On July 4, 2025, the One Big Beautiful Bill Act (OBBB) was signed into law. Among its key provisions, the OBBB updates renewable energy tax incentives originally established under the Inflation Reduction Act of 2022, including the Clean Electricity Production Tax Credit and the Investment Tax Credit. Under the new law, solar and wind facilities that begin construction before July 4, 2026, will remain eligible for the credits, consistent with existing guidance on construction start dates. Projects that commence after this deadline must be placed in service by a specified date to qualify. For certain other eligible technologies, a gradual phase-out of the credits will begin in 2034, with no credits available for projects that begin construction after 2035. The OBBB also introduces new restrictions for facilities that receive material support from a prohibited foreign entity as well as other corporate-related income tax law changes. IDACORP and Idaho Power continue to evaluate the OBBB and, as of the date of this report, do not anticipate material impacts from the OBBB to projects for which Idaho Power has already executed agreements to own generation resources.
Executive Orders of the Current Presidential Administration
Beginning in January 2025, the Administration has released several executive orders that may impact Idaho Power. These executive orders include, but are not limited to, orders regarding tariffs, the electric grid, the coal industry, revocation of executive orders of prior Presidential Administrations, federal grantmaking, and other orders intended to regulate international trade, strengthen the U.S. energy industry, and/or promote deregulation, including with respect to environmental and energy-related regulations. The outcome of these executive orders and U.S. federal agencies' review of regulations covered by executive orders is generally difficult to predict. However, in some instances, federal grants which Idaho Power has been awarded have been delayed or withdrawn, and other federal grants to Idaho Power may experience similar treatment in the future.
In addition, the court system has become more active in reviewing Presidential and agency actions, resulting in even less certainty as to the outcome and durability of rules that are administratively implemented. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and constructing transmission lines, due to the reduction of potential environmental infrastructure upgrades or conversions or reduction or elimination of permitting requirements. More strict or robust regulations, or additional regulations, such as tariffs on supplies and materials that Idaho Power purchases, on the other hand, would likely increase Idaho Power's costs of operating and maintaining its facilities, and could impact Idaho Power's plans and construction activities related to its capital projects, which could lead to substantially higher costs and delays in construction.
Executive orders may be affected by Congressional action. Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level. Therefore, as of the date of this report, and except as specifically described in this MD&A, Idaho Power is uncertain whether and to what extent the executive orders, any future executive orders, and the implementation of these and any future executive orders could affect its business, results of operations, and financial condition. Idaho Power will continue to monitor actions associated with or resulting from executive orders and new or revised legislation or regulation.
Idaho 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 wildfire mitigation plans 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 wildfire mitigation plan approved by the IPUC establishes the utility's duty to its shareholders and the public with respect to wildfire risk. On September 30, 2025, the IPUC issued an order establishing a filing schedule permitting Idaho Power to file its WMP with the IPUC no earlier than October 1, 2025. Idaho Power filed its WMP with the IPUC on October 10, 2025. The Act provides up to six months for the IPUC to review and approve a WMP after it is filed. As of the date of this report, the IPUC's decision is pending.
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 2024 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.
Idacorp Inc. published this content on October 30, 2025, and is solely responsible for the information contained herein. Distributed via Edgar on October 30, 2025 at 12:06 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]