What changed in this filing

/stocks — the workspaceLOADING

Item 8. Financial Statements and Supplementary Data

2026-02-19 compared with 2025-02-20 · 371 added, 253 removed, 1698 unchanged (27% of the section changed)

38 unchanged sentences

Energy efficiency programs 30,480 27,580 31,948

Depreciation 223,410 195,341 170,077

Other electric utility operating expenses 8,798 38,550 37,325

Depreciation and amortization 251,072 223,410 195,341

Other electric utility operating expenses, net 31,408 8,798 38,550

Total electric utility expenses 1,454,192 1,494,782 1,449,515

5 unchanged sentences

Earnings of unconsolidated equity-method investments ( 4,922 ) ( 4,539 ) ( 12,426 )

Interest on long-term debt 139,196 116,216 87,259

Interest on long-term debt and finance leases 174,929 139,196 116,216

Other interest 29,473 24,454 20,253

3 unchanged sentences

Income Before Income Taxes 310,418 305,004 289,189

Income Tax Expense 15,053 27,296 37,844

Income Tax (Benefit) Expense ( 13,715 ) 15,053 27,296

Net Income 324,133 289,951 261,893

27 unchanged sentences

Consolidated Balance Sheets

(in thousands)

(thousands of dollars)

Current Assets:

5 unchanged sentences

Income taxes receivable 8,669 13,932

Accrued unbilled revenues 97,711 90,521

Accrued unbilled receivables 79,931 97,711

Materials and supplies (at average cost) 201,896 201,064

9 unchanged sentences

Construction work in progress 1,740,809 1,244,559

Finance lease right-of-use assets 219,612 —

Utility plant held for future use 19,781 13,211

10 unchanged sentences

Consolidated Balance Sheets

(in thousands)

(thousands of dollars)

Liabilities and Equity

13 unchanged sentences

Pension and other postretirement benefits 137,406 165,992

Finance lease liabilities 216,695 —

Other 229,830 181,804

32 unchanged sentences

Other non-cash adjustments to net income, net 8,547 10,443 8,414

Accounts receivable and unbilled revenues 31,434 ( 17,628 ) ( 81,545 )

Accounts receivable and unbilled receivables 9,688 31,434 ( 17,628 )

Prepayments ( 3,666 ) ( 8,931 ) ( 3,220 )

8 unchanged sentences

Investments in affordable housing and other real estate tax credit projects ( 16,494 ) ( 3,814 ) ( 2,533 )

Distributions from equity-method investments, return of investment — — 8,489

Purchase of equity securities ( 10,871 ) ( 11,642 ) ( 12,235 )

1 unchanged sentence

Proceeds from sale of investment securities 12,398 10,641 8,921

Purchases of short-term investments — — ( 25,000 )

Maturities of short-term investments — — 25,000

Other 16,406 14,570 2,153

4 unchanged sentences

Retirement of long-term debt ( 19,885 ) ( 49,800 ) ( 225,000 )

Payments on finance lease liabilities ( 3,762 ) — —

Dividends on common stock ( 188,482 ) ( 176,565 ) ( 163,545 )

3 unchanged sentences

Net cash provided by financing activities 273,919 364,680 472,772

Net increase (decrease) in cash and cash equivalents 41,436 149,852 ( 37,666 )

Net (decrease) increase in cash and cash equivalents ( 153,147 ) 41,436 149,852

Cash and cash equivalents at beginning of the year 368,865 327,429 177,577

1 unchanged sentence

Supplemental Disclosure of Cash Flow Information:

Cash paid for income taxes $ 25,200 $ 6,200 $ 45,885

Cash paid for interest (net of amount capitalized) $ 139,277 $ 109,067 $ 97,742

1 unchanged sentence

Additions to property, plant and equipment in accounts payable $ 222,340 $ 168,107 $ 185,400

Right-of-use asset obtained in exchange for finance lease liability $ 226,618 $ — $ —

The accompanying notes are an integral part of these statements.

43 unchanged sentences

Energy efficiency programs 30,480 27,580 31,948

Depreciation 223,410 195,341 170,077

Other operating expenses 8,798 38,550 37,325

Depreciation and amortization 251,072 223,410 195,341

Other operating expenses, net 31,408 8,798 38,550

Total operating expenses 1,454,192 1,494,782 1,449,515

3 unchanged sentences

Earnings of unconsolidated equity-method investments ( 2,984 ) ( 2,671 ) ( 10,540 )

Interest on long-term debt 139,196 116,216 87,259

Interest on long-term debt and finance leases 174,929 139,196 116,216

Other interest 29,035 24,105 19,913

3 unchanged sentences

Income Before Income Taxes 302,685 298,286 285,736

Income Tax Expense 17,681 28,926 39,908

Income Tax (Benefit) Expense ( 13,177 ) 17,681 28,926

Net Income $ 315,862 $ 280,605 $ 256,810

14 unchanged sentences

Consolidated Balance Sheets

(in thousands)

(thousands of dollars)

Current Assets:

5 unchanged sentences

Income taxes receivable 1,294 11,811

Accrued unbilled revenues 97,711 90,521

Accrued unbilled receivables 79,931 97,711

Materials and supplies (at average cost) 201,896 201,064

9 unchanged sentences

Construction work in progress 1,740,809 1,244,559

Finance lease right-of-use assets 219,612 —

Plant held for future use 19,781 13,211

10 unchanged sentences

Consolidated Balance Sheets

(in thousands)

(thousands of dollars)

Liabilities and Equity

14 unchanged sentences

Pension and other postretirement benefits 137,406 165,992

Finance lease liabilities 216,695 —

Other 224,375 167,775

29 unchanged sentences

Other non-cash adjustments to net income, net ( 3,941 ) ( 1,502 ) ( 1,143 )

Accounts receivable and unbilled revenues 32,702 ( 17,882 ) ( 81,163 )

Accounts receivable and unbilled receivables 9,466 32,702 ( 17,882 )

Prepayments ( 3,668 ) ( 8,927 ) ( 3,212 )

7 unchanged sentences

Payments received from transmission project joint funding partners 151,880 83,708 26,501

Distributions from equity-method investments, return of investment — — 8,489

Purchase of equity securities ( 8,452 ) ( 10,991 ) ( 11,233 )

7 unchanged sentences

Retirement of long-term debt ( 19,885 ) ( 49,800 ) ( 225,000 )

Payments on finance lease liabilities ( 3,762 ) — —

Dividends on common stock ( 187,806 ) ( 175,772 ) ( 101,790 )

6 unchanged sentences

Supplemental Disclosure of Cash Flow Information:

Cash paid to IDACORP related to income taxes $ 37,118 $ 51,815 $ 2,532

Cash paid for interest (net of amount capitalized) $ 138,839 $ 108,718 $ 97,402

1 unchanged sentence

Additions to utility plant in accounts payable $ 222,340 $ 168,107 $ 185,400

Right-of-use asset obtained in exchange for finance lease liability $ 226,618 $ — $ —

The accompanying notes are an integral part of these statements.

18 unchanged sentences

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power.

Idaho Power is an electric utility engaged in the generation, transmission, distribution, sales, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon.

Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon.

On February 13, 2026, Idaho Power signed an asset purchase agreement with OTEC for the sale of Idaho Power's electric distribution business and certain transmission assets in the state of Oregon.

Refer to Note 22 - "Sale of Oregon Assets" for additional information regarding the Oregon Sale.

Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the FERC.

29 unchanged sentences

operating revenues;

depreciation expense;

depreciation and amortization expense;

and income tax expense.

6 unchanged sentences

Management makes estimates and assumptions when preparing financial statements in conformity with GAAP.

These estimates and assumptions include, among others, those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and the allowance for uncollectible accounts.

These estimates and assumptions include, among others, those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled receivables, and the allowance for uncollectible accounts.

These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

29 unchanged sentences

Operating revenues are generally recorded when service is rendered or energy is delivered to customers.

Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end.

Idaho Power accrues estimated unbilled receivables for electric services delivered to customers but not yet billed at year-end.

Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement.

17 unchanged sentences

it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense.

The component of AFUDC attributable to borrowed funds is included as a reduction to total nonoperating expense, net.

Idaho Power’s weighted-average monthly AFUDC rate was 7.2 percent for 2024, and 7.4 percent for both 2023 and 2022.

AFUDC is included as a reduction to total nonoperating expense, net, on the consolidated statements of income.

Idaho Power’s weighted-average monthly AFUDC rate was 7.2 percent for both 2025 and 2024, and 7.4 percent for 2023.

IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements.

17 unchanged sentences

Recently Adopted Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures, which expands annual and interim disclosure requirements for reportable segments, primarily through enhanced disclosures about significant segment expenses.

This ASU is effective for annual periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024, with early adoption permitted.

IDACORP and Idaho Power adopted this ASU on January 1, 2024, for annual periods, and subsequently on January 1, 2025, for interim periods.

The amendments in this ASU have been applied retrospectively, as required.

See Note 17 - "Segment Information" for expanded disclosure required by this ASU.

There have been no other recently adopted accounting pronouncements that have had a material impact on IDACORP's or Idaho Power's consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740):

2 unchanged sentences

The amendments in this ASU are required to be applied prospectively and are allowed to be applied retrospectively.

IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on the notes to their respective consolidated financial statements.

In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses which requires disclosure of certain disaggregated income statement expense categories on an annual and interim basis.

IDACORP and Idaho Power adopted this ASU on January 1, 2025, for annual periods.

The amendments in this ASU have been applied retrospectively.

See Note 2 - "Income Taxes" for expanded disclosure required by this ASU.

There have been no other recently adopted accounting pronouncements that have had a material impact on IDACORP's or Idaho Power's consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic 220-40):

Disaggregation of Income Statement Expenses which requires disclosure of certain disaggregated income statement expense categories on an annual and interim basis.

This ASU is effective for annual periods beginning after December 15, 2026, and for interim periods beginning after December 15, 2027, with early adoption permitted.

1 unchanged sentence

IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on the notes to their respective consolidated financial statements.

In September 2025, the FASB issued ASU 2025-06, Intangibles (Subtopic 350-40):

Targeted Improvements to the Accounting for Internal-Use Software which amends certain aspects of the accounting for and disclosure of software costs.

This ASU is effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted.

The amendments in this ASU are required to be applied prospectively and may be applied either retrospectively or using a modified prospective transition method.

IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their respective consolidated financial statements.

There have been no other recent accounting pronouncements not yet adopted that are expected to have a material impact on IDACORP's or Idaho Power's consolidated financial statements.

A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:

IDACORP Idaho Power

Reconciliations between the statutory federal income tax rate and the effective tax rate for the years ended December 31 are presented below (in thousands of dollars, except percentages):

2025 2024 2023

(thousands of dollars)

Federal income tax expense at statutory rate $ 63,888 $ 60,583 $ 62,333 $ 62,640 $ 60,005 $ 61,903

Change in taxes resulting from:

Income before income taxes (1)

$ 309,757 $ 304,227 $ 288,491

US federal income tax expense at statutory rate 65,049 21.0 % 63,888 21.0 % 60,583 21.0 %

State income taxes, net of federal income tax effect (2)

12,480 4.0 % 14,420 4.7 % 13,675 4.7 %

Flow-through accounting and other effects of rate regulation:

AFUDC ( 20,727 ) ( 6.7 ) % ( 17,015 ) ( 5.6 ) % ( 13,279 ) ( 4.6 ) %

Capitalized interest 7,721 2.5 % 5,493 1.8 % 3,097 1.1 %

Investment tax credits ( 8,271 ) ( 5,451 ) ( 3,119 ) ( 8,271 ) ( 5,451 ) ( 3,119 )

ADITCs ( 29,831 ) — — ( 29,831 ) — —

Removal costs ( 5,707 ) ( 1.8 ) % ( 5,109 ) ( 1.7 ) % ( 6,312 ) ( 2.2 ) %

1 unchanged sentence

Capitalized repair costs ( 24,150 ) ( 7.8 ) % ( 19,320 ) ( 6.4 ) % ( 24,360 ) ( 8.4 ) %

State income taxes, net of federal benefit 20,463 15,802 18,139 20,500 16,081 18,352

Depreciation 22,001 7.1 % 18,705 6.1 % 18,041 6.3 %

1 unchanged sentence

Income tax return adjustments ( 8,046 ) ( 2.6 ) % 1,844 0.6 % ( 8,229 ) ( 2.9 ) %

Real estate-related tax credits ( 7,499 ) ( 6,869 ) ( 6,362 ) — — —

State related 324 0.1 % 6,043 2.0 % 2,127 0.7 %

Other, net ( 808 ) ( 0.3 ) % 776 0.3 % 1,874 0.6 %

Investment tax credits - federal ( 7,208 ) ( 2.3 ) % ( 4,480 ) ( 1.5 ) % ( 2,344 ) ( 0.8 ) %

Investment tax credits - Idaho — — % ( 3,791 ) ( 1.2 ) % ( 3,107 ) ( 1.1 ) %

Accumulated deferred investment tax credits - federal ( 7,017 ) ( 2.3 ) % ( 8,712 ) ( 2.9 ) % — — %

Accumulated deferred investment tax credits - Idaho ( 33,319 ) ( 10.8 ) % ( 21,119 ) ( 6.9 ) % — — %

Real estate-related tax credits - federal ( 7,790 ) ( 2.5 ) % ( 7,499 ) ( 2.5 ) % ( 6,869 ) ( 2.4 ) %

Nontaxable or nondeductible items ( 229 ) ( 0.1 ) % ( 516 ) ( 0.2 ) % 120 — %

Real estate-related investment distributions ( 670 ) ( 0.2 ) % ( 1,611 ) ( 0.5 ) % ( 507 ) ( 0.2 ) %

Real estate-related investment amortization 6,204 2.0 % 5,203 1.7 % 5,570 1.9 %

Total income tax (benefit) expense and effective tax rate $ ( 13,715 ) ( 4.4 ) % $ 15,053 4.9 % $ 27,296 9.5 %

(1) Net of adjustment for income attributable to noncontrolling interests.

(2) State taxes in Idaho made up the majority (greater than 50%) of the tax effect in this category.

2025 2024 2023

Income before income taxes $ 302,685 $ 298,286 $ 285,736

US federal income tax expense at statutory rate 63,564 21.0 % 62,640 21.0 % 60,005 21.0 %

State income taxes, net of federal income tax effect (1)

12,195 4.0 % 14,139 4.7 % 13,544 4.7 %

Flow-through accounting and other effects of rate regulation:

AFUDC ( 20,727 ) ( 6.8 ) % ( 17,015 ) ( 5.7 ) % ( 13,279 ) ( 4.6 ) %

Capitalized interest 7,721 2.6 % 5,493 1.8 % 3,097 1.1 %

Removal costs ( 5,707 ) ( 1.9 ) % ( 5,109 ) ( 1.7 ) % ( 6,312 ) ( 2.2 ) %

Capitalized overhead costs ( 2,100 ) ( 0.7 ) % ( 2,100 ) ( 0.7 ) % ( 2,100 ) ( 0.7 ) %

Capitalized repair costs ( 24,150 ) ( 8.0 ) % ( 19,320 ) ( 6.5 ) % ( 24,360 ) ( 8.5 ) %

Depreciation 22,001 7.3 % 18,705 6.3 % 18,041 6.3 %

Excess deferred income tax reversal ( 9,723 ) ( 3.2 ) % ( 10,047 ) ( 3.4 ) % ( 10,684 ) ( 3.7 ) %

Income tax return adjustments ( 8,581 ) ( 2.8 ) % 1,794 0.6 % ( 7,732 ) ( 2.7 ) %

State related 684 0.2 % 6,361 2.1 % 2,537 0.9 %

Other, net ( 577 ) ( 0.2 ) % 759 0.3 % 1,499 0.5 %

Total income tax expense $ 15,053 $ 27,296 $ 37,844 $ 17,681 $ 28,926 $ 39,908

Effective tax rate 4.9 % 9.5 % 12.7 % 5.9 % 10.1 % 13.5 %

The items comprising income tax expense are as follows:

Investment tax credits - federal ( 7,208 ) ( 2.4 ) % ( 4,480 ) ( 1.5 ) % ( 2,344 ) ( 0.8 ) %

Investment tax credits - Idaho — — % ( 3,791 ) ( 1.3 ) % ( 3,107 ) ( 1.1 ) %

Accumulated deferred investment tax credits - federal ( 7,017 ) ( 2.3 ) % ( 8,712 ) ( 2.9 ) % — — %

Accumulated deferred investment tax credits - Idaho ( 33,319 ) ( 11.0 ) % ( 21,119 ) ( 7.1 ) % — — %

Nontaxable or nondeductible items ( 233 ) ( 0.1 ) % ( 517 ) ( 0.2 ) % 121 — %

Total income tax (benefit) expense and effective tax rate $( 13,177 ) ( 4.4 ) % $ 17,681 5.9 % $ 28,926 10.1 %

(1) State taxes in Idaho made up the majority (greater than 50%) of the tax effect in this category.

The items comprising income tax expense for the years ended December 31 are presented below (in thousands of dollars):

IDACORP Idaho Power

2025 2024 2023 2025 2024 2023

(thousands of dollars)

Income taxes current:

11 unchanged sentences

Real estate-related investments at IFS 6,807 4,380 6,410 — — —

Total income tax expense $ 15,053 $ 27,296 $ 37,844 $ 17,681 $ 28,926 $ 39,908

The components of the net deferred tax liability are as follows:

Total income tax (benefit) expense $ ( 13,715 ) $ 15,053 $ 27,296 $ ( 13,177 ) $ 17,681 $ 28,926

The components of the net deferred tax liability as of December 31 are presented below (in thousands of dollars):

IDACORP Idaho Power

2025 2024 2025 2024

(thousands of dollars)

Deferred tax assets:

10 unchanged sentences

Regulatory assets 821,346 811,054 821,346 811,054

Power cost adjustment 2,747 29,742 2,747 29,742

Partnership investments 4,309 4,613 — —

Retirement benefits 65,214 75,716 65,214 75,716

Wildfire mitigation plan deferral 22,252 16,272 22,252 16,272

Other 22,641 24,727 22,027 23,588

4 unchanged sentences

See Note 1 - "Summary of Significant Accounting Policies" for further discussion of accounting policies related to income taxes.

Supplemental Disclosure of Cash Flow Information

Supplemental cash flow information related to cash paid for income taxes for the years ended December 31 are presented below (in thousands of dollars):

2025 2024 2023

Federal $ 18,000 $ 14,000 $ —

Idaho 5,600 10,300 5,300

Other 892 900 900

Total cash paid for income taxes $ 24,492 $ 25,200 $ 6,200

2025 2024 2023

Federal $ 18,382 $ 30,615 $ 34,604

Idaho 7,522 5,598 15,765

Other 841 905 1,446

Total cash paid to IDACORP related to income taxes $ 26,745 $ 37,118 $ 51,815

Tax Credit Carryforwards

As of December 31, 2024, IDACORP had $7.5 million of general business credit carryforwards for federal income tax purposes and $ 59.3 million of Idaho investment tax credit carryforward.

The general business credit carryforward period expires in 2044, and the Idaho investment tax credits expire from 2031 to 2038.

As of December 31, 2025, IDACORP had $ 70.9 million of Idaho investment tax credit carryforward which expires from 2034 to 2039.

Uncertain Tax Positions

2 unchanged sentences

IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - United States federal and the State of Idaho.

The open tax years for examination are 2023 and 2024 for federal and 2022 through 2024 for Idaho.

The open tax years for examination are 2023 through 2025 for federal and 2022 through 2025 for Idaho.

In May 2009, IDACORP formally entered the U.S.

2 unchanged sentences

IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power.

Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.

Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters affecting customer rates.

Regulatory Assets and Liabilities

The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record those expenses and revenues.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers

through future rates.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates.

Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense.

7 unchanged sentences

$ — $ 821,346 $ 821,346 $ 811,054

Unfunded postretirement benefits (3)

— 18,824 18,824 87,318

Pension expense deferrals (3)

245,508 1,832 247,340 252,197

Power supply costs (5)

Mark-to-market assets (4)

— 49,520 49,520 28,118

Unfunded postretirement benefits (5)

Power supply costs (6)

Fixed cost adjustment (6)

24 unchanged sentences

2026-2027 42,419 — 42,419 3,949

Unfunded postretirement benefits (5)

— 11,785 11,785 —

Tax reform accrual for future amortization (11)

6 unchanged sentences

(2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes."

(3) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 11 - "Benefit Plans."

(3) Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan.

2 unchanged sentences

Deferred costs are amortized into expense as the amounts are provided for in Idaho retail revenues.

(4) This item is discussed in more detail in Note 16 - "Derivative Financial Instruments."

(5) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 12 - "Benefit Plans."

(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."

1 unchanged sentence

(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes."

(8) In 2017, income tax reform reduced deferred income tax assets and liabilities.

(9) For depreciation-related temporary differences under the normalized tax accounting method, the resulting excess deferred taxes will flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the alternative method provided in the statute.

13 unchanged sentences

The latter component ensures that, over time, the actual collection or refund of net power supply costs matches the amounts authorized.

The PCA mechanism 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 exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers;

• a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales volume changes does not distort the results of the mechanism.

The Idaho-jurisdiction 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.

In May 2023, the IPUC approved recovery of an incremental $ 200.2 million of Idaho-jurisdiction PCA revenues, but directed Idaho Power to spread recovery of the $ 190.2 million deferral balance component of the PCA over a two-year period from June 1, 2023, to May 31, 2025.

The order deferred collection of $ 95.1 million of deferred PCA costs to the annual PCA collection period from June 1, 2024, to May 31, 2025.

In May 2024, the IPUC issued an order approving a $ 35.7 million net decrease in PCA revenues as compared to the prior collection period, effective for the PCA collection period from June 1, 2024, to May 31, 2025.

The net decrease in PCA revenues reflected forecasted improved hydropower generation during the April 2024 to March 2025 PCA deferral period.

The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:

The PCA mechanism 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 exceptions of expenses associated with PURPA power purchases, export credit mechanisms, a battery storage lease, and demand response incentive payments, which are allocated 100 percent to customers;

• a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales volume changes does not distort the results of the mechanism.

Beginning April 1, 2024, the difference between actual and base-level third-party transmission wheeling revenues are tracked and incorporated into the balancing component of the PCA, as authorized by the IPUC in March 2025.

In May 2025, the IPUC issued an order approving a $94.8 million net decrease in PCA revenues as compared with the prior collection period, effective for the PCA collection period from June 1, 2025, to May 31, 2026.

The net decrease in PCA revenues reflected a decrease in the balancing adjustment, which was due primarily to the completed recovery of the 2023 deferred PCA costs, which were recovered over a two-year period as ordered by the IPUC.

The 2025 Settlement Stipulation, described in more detail below, modified PCA collection effective January 1, 2026, to account for the new system base level NPSE of $468.8 million.

The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments from Idaho Power's annual PCA filings, which also include non-PCA-related rate adjustments as ordered by the IPUC:

Effective Date $ Change (millions) Notes

June 1, 2024 $ ( 35.7 ) The $35.7 million net decrease in PCA rates reflects forecasted improved hydropower generation during the April 2024 to March 2025 PCA deferral period.

June 1, 2023 $ 105.1 The $105.1 million increase in PCA rates reflects higher market energy and natural gas prices, combined with lower than-expected low-cost hydropower generation and limited coal supply.

The increased rate also reflects an expectation of continued elevated market energy prices and natural gas prices in the forecast period.

June 1, 2022 $ 94.9 The increase in PCA rates reflected a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with market energy prices and natural gas prices.

The rate also reflected $0.6 million of 2021 earnings shared with customers under the 2018 Settlement Stipulation described below.

June 1, 2025 $ ( 94.8 ) The $94.8 million net decrease in PCA rates 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.

June 1, 2024 $ ( 35.7 ) The $35.7 million net decrease in PCA rates reflected forecasted improved hydropower generation during the April 2024 to March 2025 PCA deferral period.

June 1, 2023 $ 105.1 The $105.1 million increase in PCA rates reflected higher market energy and natural gas prices, combined with lower than-expected low-cost hydropower generation and limited coal supply.

The increased rate also reflected an expectation of continued elevated market energy prices and natural gas prices in the forecast period.

Oregon Jurisdiction Power Cost Adjustment Mechanism:

Idaho Power’s power cost recovery mechanism in Oregon has two components:

an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM).

The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net

power supply costs for the upcoming water year.

an APCU and a power cost adjustment mechanism (PCAM).

The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the

upcoming water year.

The PCAM is a true-up filed annually in February.

The PCAM filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period.

Actual 2024 Oregon-jurisdiction power supply costs were less than the amount recovered through the APCU, resulting in a $ 2.9 million difference between revenue and cost.

In 2023, Oregon jurisdiction power supply costs were less than the amount recovered through the APCU, but because Idaho Power’s earnings in 2023 were below the threshold of plus or minus 100 basis points of its authorized return on year-end equity, the difference was not refunded to customers.

Idaho Power's annual June 1 APCU rate changes were a decrease of $ 6.9 million, an increase of $ 7.7 million, and an increase of $ 4.0 million in 2024, 2023, and 2022, respectively.

In May 2025, the OPUC approved a settlement stipulation between Idaho Power and intervening parties for its APCU in Oregon.

The settlement resulted in an overall rate decrease of $ 1.8 million in Oregon-jurisdictional rates effective June 1, 2025.

Idaho Power's 2024 and 2023 June 1 APCU rate changes were a decrease of $ 6.9 million, and an increase of $ 7.7 million, respectively.

Notable Idaho Base Rate Adjustments

Idaho base rates were most recently established through the 2024 Idaho Limited-Issue Rate Case, with rate changes effective January 1, 2025.

Previously, base rates were established in a general rate case in 2023, which was resolved by the 2023 Settlement Stipulation.

Idaho base rates were most recently established through a general rate case in 2025, which was resolved by the 2025 Settlement Stipulation, with rate changes effective January 1, 2026.

Previously, base rates were established in the 2024 Idaho Limited-Issue Rate Case and in a general rate case in 2023, which was resolved by the 2023 Settlement Stipulation.

2025 Idaho General Rate Case:

In May 2025, Idaho Power filed a general rate case with the IPUC.

The general rate case was resolved in December 2025, when the IPUC issued an order (the Order) approving the 2025 Settlement Stipulation, entered into by Idaho Power, the Staff of the IPUC, and several of the intervening parties.

The 2025 Settlement Stipulation contains the following significant terms, among other items:

• Idaho Power will implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by approximately $ 110.0 million, or 7.48 percent, effective January 1, 2026.

The approximate $ 110.0 million of additional annual revenue is inclusive of a PCA rate increase of $ 13.1 million;

• a 9.6 percent return on equity and a 7.41 percent authorized rate of return based on the filed cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $4.9 billion (which is largely based on the average of monthly average plant balances for January through December 2025);

• a base level NPSE of approximately $ 468.8 million, a decrease of $ 16.1 million from the currently approved base level NPSE;

• updates to the FCA mechanism rates to reflect approved fixed costs and Idaho Power’s proposed rate designs;

• continued deferral of certain wildfire mitigation related costs, including incremental vegetation management and insurance costs, as measured primarily from 2024 actual costs, through the earlier of Idaho Power's next general rate case or 2027;

• modifications to Idaho Power’s ADITC and revenue sharing mechanism:

(1) to include an additional amount of investment tax credits equal to the total of existing ADITCs not currently eligible for accelerated amortization under the mechanism and all investment tax credits generated through the end of calendar-year 2028;

(2) to establish an annual cap of $55 million on the amount of accelerated amortization of ADITCs for calendar year 2026 and thereafter;

(3) to re-affirm the existing minimum specified Idaho-jurisdiction return on year-end equity (Idaho ROE) of 9.12 percent for additional amortization of ADITCs;

(4) to re-affirm the existing 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers;

and (5) to continue to implement all revenue sharing through the PCA;

• agreement that Idaho Power’s share of capital expenditures at jointly-owned coal-fired plants through year-end 2024 are included for recovery in the stipulated revenue requirement.

At the time of the 2025 Settlement Stipulation, Staff of the IPUC had completed its prudence review of capital projects included in the test year rate base through July 2025.

The IPUC Staff will address the prudence of investments placed in service after July 2025 in Idaho Power’s next Idaho general rate case.

Neither the Order nor the 2025 Settlement Stipulation precludes Idaho Power from filing another general rate case in Idaho at any time in the future.

Under the modified ADITC and Revenue Sharing mechanism, if Idaho Power's annual Idaho ROE in any year exceeds 9.6 percent, the amount of earnings exceeding 9.6 percent will be allocated 80.0 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20.0 percent to Idaho Power.

In 2025, Idaho Power recorded amortization of $ 40.3 million of ADITC.

Accordingly, at December 31, 2025, $ 167.8 million of ADITC remained available for future use under the terms of the 2025 Settlement Stipulation, the 2023 Settlement Stipulation, and the 2018 Settlement Stipulation described below.

2024 Idaho Limited-Issue Rate Case:

Idaho Power filed the 2024 Idaho Limited-Issue Rate Case in May 2024, focused on revenue requirements for 2024 incremental plant additions and incremental ongoing labor costs.

On December 31, 2024, the IPUC issued its order (Order) in the 2024 Idaho Limited-Issue Rate Case, providing that Idaho Power implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $ 50.6 million, or 3.7 percent, effective January 1, 2025.

On December 31, 2024, the IPUC issued its order in the 2024 Idaho Limited-Issue Rate Case, providing that Idaho Power implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $ 50.6 million, or 3.7 percent, effective January 1,

The order was subsequently modified by an errata issued on January 21, 2025, which reduced the revenue increase called for under the order to $ 50.1 million.

The order did not adjust the overall rate of return approved in the 2023 Settlement Stipulation or make changes to Idaho regulatory mechanisms such as the PCA, FCA, and energy efficiency rider.

The Order also did not preclude Idaho Power from filing another rate case in Idaho at any time in the future.

2023 Idaho General Rate Case:

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• Modifications to the PCA including establishment of a new level of base net power supply expense of $ 484.9 million, which included the transfer of $ 168.3 million from then-current PCA rates to base rates;

• Modifications to the FCA mechanism to support Idaho Power’s rate designs and to reflect updated fixed costs;

• Continued deferral of incremental vegetation management and insurance costs, as measured from 2022 actual costs, through the earlier of Idaho Power’s next Idaho general rate case or 2025;

• An annual $ 18 million increase in collection of Idaho Power’s regulatory asset associated with its defined benefit pension plan contributions;

• Modifications to Idaho Power’s ADITC and revenue sharing mechanism beginning in 2024 to (1) include an additional amount of investment tax credits equal to the incremental investment tax credits generated from Idaho Power’s investment in 2023 battery storage projects;

(2) remove the existing $ 25 million annual cap on the amount of accelerated amortization of ADITCs;

(3) establish a minimum specified Idaho-jurisdiction return on year-end equity (Idaho ROE) of 9.12 percent for additional amortization of ADITCs;

(4) establish a 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers;

and (5) implement all revenue sharing through the PCA rather than a portion offsetting customer-funded pension obligations;

• Modifications to Idaho Power’s ADITC and revenue sharing mechanism beginning in 2024 to, among other items, (1) establish a minimum specified Idaho ROE of 9.12 percent for additional amortization of ADITCs;

and (2) establish a 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers;

• Agreement that Idaho Power’s capital expenditures through year-end 2022 were prudently incurred.

• Deferral and amortization of annual differences between certain periodic maintenance costs at Idaho Power’s natural gas-fired power plants;

• A residential price modernization plan and updated rate designs.

In 2024, Idaho Power recorded amortization of $ 29.8 million of ADITC.

Accordingly, at December 31, 2024, $ 77 million of ADITC remained available for future use under the terms of the 2023 Settlement Stipulation and the 2018 Settlement Stipulation described below.

May 2018 Idaho Tax Reform Settlement Stipulation:

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The 2018 Settlement Stipulation also provided for the indefinite extension, with modifications, of a previous 2014 settlement stipulation beyond its termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism that became effective January 1, 2020.

Idaho Power’s base rates and ADITC and revenue sharing mechanism were modified by the 2023 Settlement Stipulation, as described above.

Idaho Power’s base rates and ADITC and revenue sharing mechanism were modified by the 2025 Settlement Stipulation and the 2023 Settlement Stipulation, as described above.

North Valmy Base Rate Adjustment Settlement Stipulations:

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

Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and these settlement stipulations provide for Idaho Power to cease participation in coal-fired operations at unit 2 in 2025.

Idaho Power has settlement stipulations in place in Idaho and Oregon related to the end of its participation in coal-fired operations of both units of its jointly-owned North Valmy plant.

Idaho Power ceased participation in coal-fired operations at unit 1 in 2019, and coal-fired operations at unit 2 ceased at the end of 2025.

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

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

Jim Bridger Power Plant Rate Base Adjustment and Recovery and Non-Fuel O&M Expenses:

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

The Bridger Order allows for regulatory accounting entries and establishes balancing accounts (recorded as regulatory assets or liabilities on Idaho Power’s and IDACORP’s consolidated balance sheets) to track differences between amounts recovered in rates and actual incremental costs and benefits associated with Idaho Power’s plan at the time of the Bridger Order to cease its participation in coal-fired operations at the Jim Bridger plant by the end of 2028.

The incremental costs and benefits include the revenue requirement associated with the incremental Jim Bridger plant coal-related investments made from 2012 through the end of 2020, forecasted coal-related investments, and near-term decommissioning costs, offset by other O&M cost savings.

The Bridger Order deemed all coal-related investments at the Jim Bridger plant from 2012 through 2020 to be prudent for recovery.

In the Bridger Order, the IPUC reduced Idaho Power's requested rate increase from 2.1 percent in its amended filing to 1.5 percent, a reduction from a requested $ 27.1 million to $ 18.8 million annually.

The Bridger Order provides that any uncollected amount resulting from the reduction in the rate increase will be recorded in the balancing account for future recovery with no carrying charge.

The uncollected amounts tracked in this balancing account were included for recovery in the 2023 Settlement Stipulation.

The 2025 Settlement Stipulation made modifications to the Idaho North Valmy settlement stipulation, including updated coal-related investments through 2024 and investment forecasts through 2025.

On December 31, 2025, the accelerated depreciation associated with coal-related investments at the North Valmy plant was completed and the amounts removed from Oregon customer rates.

Jim Bridger Power Plant Rate Base Adjustment and Recovery:

In 2022, the IPUC authorized Idaho Power to (1) accelerate depreciation for the Jim Bridger plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (2) establish a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with its plan to cease participation in coal-fired operations at the Jim Bridger plant in 2028, and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Recovery Mechanism).

The 2025 Settlement Stipulation made modifications to the Bridger Recovery Mechanism, including updated coal-related investments through 2024, updated investment forecasts through 2028, and the inclusion of total other O&M expenses associated with operations of the Jim Bridger plant.

The Bridger Recovery Mechanism allows Idaho Power to earn a return on and recover through 2030 the net book value of coal-related assets at the Jim Bridger plant as of December 31, 2024, as well as forecasted coal-related investments.

Idaho Power anticipates making future filings with the IPUC that may result in periodic adjustments to rates to true up variances between revenue collections and actual revenue requirement amounts.

The Bridger Order allows Idaho Power to earn a return on and recover through 2030 the net book value of coal-related assets at the Jim Bridger plant as of December 31, 2020, as well as forecasted coal-related investments.

In September 2024, the IPUC issued an order authorizing Idaho Power to include all non-fuel O&M expenses associated with operations of the Jim Bridger plant in the balancing account previously established to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, which resulted in a $ 11.3 million deferral of costs in 2024 to a regulatory asset account for future recovery.

Other Notable Idaho Regulatory Matters

Recovery of Incremental AFUDC Associated with HCC:

In March 2025, Idaho Power filed an application with the IPUC requesting an order authorizing an increase of $ 29.7 million in the annual cash collection of incremental financing costs, or AFUDC, associated with relicensing of the HCC project.

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.

Other Notable Idaho Regulatory Matters Affecting Customer Rates

Fixed Cost Adjustment:

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The IPUC has discretion to cap the annual increase in the FCA recovery at 3 percent of base revenue, with any excess deferred for collection in a subsequent year.

In May 2024, the IPUC issued an order approving a $ 11.7 million increase in recovery from the FCA from $ 25.1 million to $ 36.8 million for the 2023 FCA deferral, with new rates effective for the period from June 1, 2024, to May 31, 2025.

Beginning with the 2024 FCA deferral, the 2023 Settlement Stipulation updates the authorized fixed-cost recovery amount per customer and modifies parts of the FCA mechanism to support Idaho Power's proposed rate designs, as noted above.

The following table summarizes FCA amounts approved for collection in the prior three FCA years:

In May 2025, the IPUC issued an order approving a $ 39.8 million decrease in recovery from the FCA from $ 36.8 million to negative $ 3.1 million for the 2024 FCA deferral, reflecting a refund to residential and small commercial customers of the 2024 FCA deferral balance of $ 3.1 million, with new rates effective for the period from June 1, 2025 to May 31, 2026.

Beginning with the 2026 FCA deferral, the 2025 Settlement Stipulation updated the authorized fixed-cost recovery amount per customer and per unit of energy within the FCA mechanism to support Idaho Power's proposed rate designs, as noted above.

The following table summarizes FCA amounts approved for (refund) or collection in the prior three FCA years:

FCA Year Period Rates in Effect Annual Amount

(in millions)

(in millions of dollars)

2024 June 1, 2025 to May 31, 2026 $( 3.1 )

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Wildfire Mitigation Cost Recovery:

In June 2021 and March 2023, the IPUC issued orders authorizing Idaho Power to defer for future amortization incremental O&M and depreciation expense for certain capital investments necessary to implement Idaho Power's WMP.

As a result of the 2023 Settlement Stipulation, in 2024, Idaho Power recovered and amortized $ 3.8 million of its WMP deferral balance through 2022 of $ 26.7 million.

In September 2025, the IPUC granted Idaho Power's request to defer for future recovery an estimated $22.2 million of newly identified incremental O&M costs expected to be incurred in 2025 associated with expanded wildfire mitigation efforts.

The IPUC also authorized the continued deferral of incremental insurance costs above the 2022 base established in the 2023 Settlement Stipulation.

The 2025 Settlement Stipulation authorized Idaho Power to defer incremental O&M and insurance costs above the 2024 base through the earlier of the next general rate case or 2027.

As of December 31, 2025, Idaho Power’s deferral balance of Idaho-jurisdiction costs related to the WMP was $ 88.2 million, of which $ 73.9 million is approved to be amortized and collected in Idaho rates.

In January 2024, the OPUC authorized Idaho Power to defer the Oregon jurisdictional share of costs associated with the WMP for the 12-month period beginning December 29, 2022, and ending on December 28, 2023, resulting in an Oregon-jurisdiction deferral balance of approximately $ 750 thousand.

On February 13, 2025, Idaho Power filed an application with the IPUC for review of the Company's current WMP and request for an order authorizing the Company to defer through calendar year 2025, or until the Company's next general rate case goes into effect, newly identified costs associated with expanded wildfire mitigation efforts.

Notable Oregon Regulatory Matters

Hells Canyon Complex Relicensing Costs:

In December 2025, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures from January 1, 2016 through year-end 2025 on relicensing of the HCC, including approximately $305 million incurred from January 1, 2016 through September 30, 2025, were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding.

As of the date of this report, the case remains pending.

Notable Oregon Regulatory Matters Affecting Customer Rates

Oregon Base Rate Changes:

Oregon base rates were most recently established in a general rate case that Idaho Power filed with the OPUC in December 2023.

Oregon base rates were most recently established in a general rate case that Idaho Power filed with the OPUC in December 2023 and a separate case approved by the OPUC in December 2025 described below.

In September 2024, the OPUC issued an order approving the 2024 Oregon Settlement Stipulations, which are settlement stipulations among Idaho Power and intervening parties settling the general rate case.

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• A 9.5 percent Oregon-jurisdiction return on year-end equity and a 7.302 percent Oregon-jurisdiction authorized rate of return based on a 5.104 percent cost of debt and capital structure of 50 percent debt and 50 percent equity, applied to an Oregon-jurisdictional rate base of approximately $ 188.9 million.

The $188.9 million of rate base excludes rate base associated with Idaho Power's jointly-owned North Valmy coal facilities, the costs of which are recovered under the separate rate mechanism noted below.

Rate changes from the 2024 Oregon Settlement Stipulations became effective on October 15, 2024.

The 2024 Oregon Settlement Stipulations do not preclude Idaho Power from filing another general rate case or other limited issue proceeding in Oregon at any time in the future.

In December 2025, the OPUC issued an order approving a decrease in Oregon rates reflecting three offsetting adjustments:

a decrease in rates of $ 1.2 million due to the removal of coal-related costs at the North Valmy plant, a decrease in rates of $ 0.1 million to return an outstanding regulatory liability related to the former Boardman plant, and an increase in rates of $ 0.7 million to recover the amortization of deferred 2023 wildfire mitigation costs.

The combined result was an overall rate decrease of $ 0.6 million or 0.9 percent, effective January 1, 2026.

Wildfire Mitigation Cost Recovery:

In December 2025, Idaho Power filed its 2026-2028 WMP with the OPUC along with an application requesting authorization to defer for future recovery an estimated $3.1 million of newly identified incremental costs expected to be incurred in 2026 associated with expanded wildfire mitigation efforts.

As of the date of this report, the case remains pending.

As of December 31, 2025, Idaho Power’s deferral balance of Oregon-jurisdiction costs related to the WMP was $ 3.5 million, of which $ 0.7 million is approved to be amortized and collected in Oregon rates.

Federal Regulatory Matters - Open Access Transmission Tariff Rates

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Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $ 148.5 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.

The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands):

The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands of dollars):

Year Ended December 31,

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Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing, and uncertainty, if any, of revenues being recognized.

The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands):

The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands of dollars):

Year Ended December 31,

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(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 electric plant in service.

Idaho Power is collecting $ 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.

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

Effective October 1, 2025, Idaho Power began collecting $ 38.5 million annually.

Prior to October 1, 2025, Idaho Power collected $ 8.8 million annually.

For more information refer to Note 3 - "Regulatory Matters." Amounts collected in the Idaho jurisdiction are recognized as deferred revenue until the license is issued and the accumulated license costs approved for recovery are placed in service.

Retail Revenues:

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Idaho Power’s energy sales to residential customers typically peak during the summer cooling season and winter heating season.

Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures.

Extreme temperatures increase sales to residential customers who use electricity for cooling and

heating, compared with normal temperatures.

Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases.

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Wholesale Energy Sales:

As a public utility under the FPA, Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff.

As a public utility under the FPA, Idaho Power has been granted the authority to charge market-based rates for wholesale energy sales under its FERC tariff.

Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred to the counterparty.

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Transmission Wheeling-Related Revenues:

As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT.

As a public utility under the FPA, Idaho Power has been granted the authority to provide cost-based wholesale and retail access transmission services under its OATT.

Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system.

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Alternative Revenue Programs and Other Revenues

While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of an additional regulatory mechanism, the FCA mechanism, which may increase or decrease tariff-based customer rates.

The FCA mechanism is described in Note 3 - "Regulatory Matters." The FCA mechanism revenues include only the initial recognition of FCA revenues when they meet the regulator-specified conditions for recognition.

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For more information on settled electricity swaps, see Note 16 - "Derivative Financial Instruments."

The table below presents the FCA mechanism revenues and derivative revenues (in thousands):

The table below presents the FCA mechanism revenues and derivative revenues (in thousands of dollars):

Year Ended December 31,

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5.20 % Series due 2034

300,000 300,000

5.30 % Series due 2035

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350,000 350,000

5.70 % Series due 2055

Total first mortgage bonds 3,345,000 2,945,000

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1.70 % Series due 2026 (1)

116,300 116,300

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Long-Term Debt Issuances, Maturities, and Redemptions

On March 13, 2025, Idaho Power issued $ 400 million in aggregate principal amount of 5.70 % first mortgage bonds, secured medium-term notes, Series O, maturing on March 15, 2055.

On February 3, 2025, Idaho Power repaid $ 19.9 million in aggregate principal amount of maturing variable rate American Falls Bonds.

On December 2, 2024, Idaho Power repaid $ 49.8 million in aggregate principal amount of maturing 1.45 % Humboldt County Pollution Control Revenue Bonds.

On August 12, 2024, under the shelf registration statement with the SEC, Idaho Power issued $ 300 million in aggregate principal amount of 5.20 % first mortgage bonds, secured medium-term notes, Series M, maturing on August 15, 2034.

On September 11, 2023, under the shelf registration statement with the SEC, Idaho Power issued $ 350 million in aggregate principal amount of 5.80 % first mortgage bonds, secured medium-term notes, Series M, maturing on April 1, 2054.

On April 1, 2023, Idaho Power repaid $ 75 million in aggregate principal amount of maturing 2.50 % first mortgage bonds due 2023, Series I.

On March 14, 2023, under the shelf registration statement with the SEC, Idaho Power issued $ 400 million in aggregate principal amount of 5.50 % first mortgage bonds, secured medium-term notes, Series M, maturing on March 15, 2053.

On March 8, 2023, pursuant to the Bond Purchase Agreement defined below, Idaho Power issued $ 60 million in aggregate principal amount of 5.06 % first mortgage bonds, secured medium-term notes, Series N, maturing on March 8, 2043;

and $ 62 million in aggregate principal amount of 5.20 % first mortgage bonds, secured medium-term notes, Series N, maturing on March 8, 2053.

On December 22, 2022, Idaho Power entered into a Bond Purchase Agreement with certain institutional purchasers relating to the sale by Idaho Power of $ 170 million of first mortgage bonds, secured medium-term notes, Series N (Series N Notes), as described in more detail below.

On August 12, 2024, Idaho Power issued $ 300 million in aggregate principal amount of 5.20 % first mortgage bonds, secured medium-term notes, Series M, maturing on August 15, 2034.

Idaho Power First Mortgage Bonds

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At December 31, 2025, $ 500 million remained available for debt issuance under the regulatory orders.

In May 2022, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds.

In February 2025, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture).

Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

In June 2022, Idaho Power entered into a selling agency agreement with six banks named in the agreement in connection with the potential issuance and sale from time to time of up to $1.2 billion aggregate principal amount of first mortgage bonds, secured medium term notes, Series M (Series M Notes), under Idaho Power’s Indenture.

Also in June 2022, Idaho Power entered into the Fiftieth Supplemental Indenture, dated effective as of June 30, 2022, to the Indenture (Fiftieth Supplemental Indenture).

The Fiftieth Supplemental Indenture provides for, among other items, the issuance of up to $1.2 billion in aggregate principal amount of Series M Notes pursuant to the Indenture.

In October 2022, Idaho Power entered into the Fifty-first Supplemental Indenture to increase the limit of the amount of first mortgage bonds at any one time outstanding to $ 3.5 billion as provided in the Indenture.

In February 2025, Idaho Power entered into a selling agency agreement with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $ 2.1 billion aggregate principal amount of first mortgage bonds, secured medium-term notes, Series O (Series O Notes), under the Indenture.

Also in February 2025, Idaho Power entered into the Fifty-third Supplemental Indenture, dated effective as of February 26, 2025, to the Indenture (Fifty-third Supplemental Indenture).

The Fifty-third Supplemental Indenture provides for, among other items, the issuance of up to $2.1 billion in aggregate principal amount of Series O Notes pursuant to the Indenture and increased the limit of the amount of first mortgage bonds at any one time outstanding to $ 5.5 billion as provided in the Indenture.

The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture.

The Indenture requires that Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose

Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

In December 2022, Idaho Power entered into the Bond Purcha se Agreement with certain institutional purchasers, relating to the sale by Idaho Power of $ 170 million in aggregate principal amount of Series N Notes.

Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated effective as of December 30, 2022, to the Indenture (Fifty-second Supplemental Indenture).

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

The Series N Notes consist of:

• $ 23 million in aggregate principal amount of Idaho Power’s 4.99% first mortgage bonds due 2032, Series N Notes, Tranche 1 (Tranche 1 Bonds);

• $ 25 million in aggregate principal amount of Idaho Power’s 5.06% first mortgage bonds due 2042, Series N Notes, Tranche 2 (Tranche 2 Bonds);

• $ 60 million in aggregate principal amount of Idaho Power’s 5.06% first mortgage bonds due 2043, Series N Notes, Tranche 3 (Tranche 3 Bonds);

• $ 62 million in aggregate principal amount of Idaho Power’s 5.20% first mortgage bonds due 2053, Series N Notes, Tranche 4 (Tranche 4 Bonds).

The Tranche 1 Bonds and Tranche 2 Bonds were issued on December 22, 2022, and the Tranche 3 Bonds and Tranche 4 Bonds were issued on March 8, 2023, each under the Indenture.

The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction.

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Idaho Power may, however, anticipate or make up these expenditures or appropriations within the 5 years that immediately follow or precede a particular year.

As of December 31, 2024, the maximum amount of additional first mortgage bonds Idaho Power could issue was approximately $ 439 million.

Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture.

As of December 31, 2024, Idaho Power could issue approximately $ 2.1 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

The Indenture limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture.

As of December 31, 2025, the maximum amount of additional first mortgage bonds Idaho Power could issue under this test was approximately $ 2.3 billion.

The Indenture also imposes a fixed cap of $ 5.5 billion on the aggregate amount of first mortgage bonds that may be outstanding under the Indenture, which cap may be amended under certain conditions.

As of December 31, 2025, Idaho Power could issue approximately $ 2.0 billion of additional first mortgage bonds based on that aggregate cap.

IDACORP Common Stock

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2025 2024 2023 December 31, 2025

Balance at beginning of year 50,615,237 50,561,892 50,516,479

Balance at January 1 53,962,300 50,615,237 50,561,892

Dividend reinvestment and stock purchase plan 49,569 63,084 — 2,729,049

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Continuous equity program (inactive) — — — 3,000,000

Balance at end of year 53,962,300 50,615,237 50,561,892

(1) At December 31, 2024, IDACORP had reserved shares of its common stock through the ATM offering program, up to an aggregate gross sales price of $ 300 million.

Balance at December 31 54,859,131 53,962,300 50,615,237

(1) During 2024, IDACORP reserved shares of its common stock through the ATM offering program, up to an aggregate gross sales price of $ 300 million.

At December 31, 2025, $ 155.5 million in shares of IDACORP’s common stock remained reserved.

For more details, see "At-the-Market Offering Program" below in this Note 6.

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On May 20, 2024, IDACORP entered into an Equity Distribution Agreement (EDA) pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $ 300 million of shares of its common stock through an ATM offering program, which includes the ability to enter into FSAs.

In 2024, IDACORP did not issue common stock pursuant to the EDA.

In 2024, IDACORP executed FSAs under its ATM offering program with various counterparties who borrowed and sold 801,914 shares of IDACORP’s common stock at an aggregate gross sales price of $ 92.4 million.

At December 31, 2025, $ 155.5 million in shares of IDACORP’s common stock remained available for issuance through its ATM offering program.

At December 31, 2024, IDACORP could have settled the FSAs with physical delivery of 801,914 shares of common stock to the counterparty in exchange for cash of $ 91.6 million.

IDACORP executed FSAs under its ATM offering program with various counterparties who borrowed and sold 452,256 shares in 2025 and 801,914 shares in 2024 of IDACORP’s common stock at an aggregate gross sales price of $ 52.2 million in 2025 and $ 92.4 million in 2024.

This included approximately $ 0.7 million in 2025 and $ 1.2 million in 2024 in commissions and fees payable by IDACORP to the counterparties upon settlement.

At December 31, 2025, IDACORP had the following FSAs outstanding under its ATM offering program (in thousands of dollars, except for shares and forward price amounts):

Maturity Shares Net Proceeds Available Forward Price

Maturity Date Shares Net Proceeds Available Forward Price

March 31, 2026 198,086 $ 22,789 $ 115.05

March 31, 2026 254,170 28,970 113.98

Total / Weighted Average Forward Price 452,256 $ 51,759 $ 114.45

The FSAs will be physically settled with common shares issued by IDACORP, unless IDACORP elects to settle the agreements in net cash or net shares, subject to certain conditions.

On a settlement date or dates, if IDACORP elects to physically settle the FSAs, IDACORP will issue shares of common stock to the various counterparties at the then-applicable forward sale price and receive issuance proceeds at that time.

At December 31, 2025, IDACORP could have settled all its outstanding FSAs under the ATM offering program with physical delivery of 452,256 shares of common stock to the counterparties in exchange for cash of $ 51.8 million.

At December 31, 2025, IDACORP could have settled the FSAs with net delivery to various counterparties of approximately $ 7.2 million of cash or approximately 54,968 shares of common stock, if IDACORP had elected to net cash or net share settle, respectively.

The FSAs have been classified as an equity transaction because they are indexed to IDACORP’s common stock and the other requirements necessary for equity classification are met.

As a result of the equity classification, no gain or loss will be recognized within earnings due to subsequent changes in the fair value of the FSAs.

During 2025, IDACORP settled the following FSAs under its ATM offering program (in thousands of dollars, except for settlement shares and forward settlement price amounts):

Settlement Date Settlement Shares Net Cash Proceeds (1)

Forward Settlement Price

November 12, 2025 500,000 $ 56,924 $ 113.85

December 19, 2025 301,914 34,793 115.24

Total 801,914 $ 91,581 $ 114.20

Total / Weighted Average Forward Settlement Price 801,914 $ 91,717 $ 114.37

(1) Settlement of the FSAs are reflected in IDACORP’s equity.

Equity Forward Sale Agreements (2025 Series):

On May 8, 2025, IDACORP announced a registered public offering of 4,504,505 shares of its common stock at a public offering price of $ 111.00 per share, for an aggregate amount of $ 500.0 million.

In conjunction with this offering, underwriters exercised an option to purchase 675,675 additional shares for an additional aggregate amount of $ 75.0 million.

The 5,180,180 shares were sold by IDACORP to the underwriters under FSAs, which provide for settlement on a settlement date or dates to be specified at IDACORP’s discretion, but which is expected to occur on or prior to November 9, 2026.

The forward sale price was initially $ 107.67 per share and is subject to certain adjustments in accordance with the terms of the FSAs through the date or dates of settlement.

The FSAs will be physically settled with common shares issued by IDACORP, unless IDACORP elects to settle the agreements in net cash or net shares, subject to certain conditions.

On a settlement date or dates, if IDACORP elects to physically settle the

FSAs, IDACORP will issue shares of common stock to the various counterparties at the then-applicable forward sale price and receive issuance proceeds at that time.

At December 31, 2024, IDACORP could have settled the FSAs with net receipt from various counterparties of approximately $ 1.2 million of cash or approximately 11,270 shares of common stock, if IDACORP had elected to net cash or net share settle, respectively.

At December 31, 2025, IDACORP could have settled the FSAs with physical delivery of 5,180,180 shares of common stock to the counterparties in exchange for cash of $ 560.9 million.

The FSAs could have also been settled at December 31, 2025, with delivery of approximately $ 113.8 million of cash or approximately 874,426 shares of common stock to the counterparties, if IDACORP had elected to net cash or net share settle, respectively.

The FSAs have been classified as an equity transaction because they are indexed to IDACORP’s common stock and the other requirements necessary for equity classification are met.

As a result of the equity classification, no gain or loss will be recognized within earnings due to subsequent changes in the fair value of the FSAs.

Equity Forward Sale Agreements:

Equity Forward Sale Agreements (2023 Series):

On November 7, 2023, IDACORP announced a registered public offering of 2,801,724 shares of its common stock at a public offering price of $ 92.80 per share, for an issuance amount of $ 260.0 million.

In conjunction with this offering, IDACORP granted the underwriters an option to purchase up to 420,258 additional shares, which was subsequently exercised in full on November 8, 2023, for an additional issuance amount of $ 39.0 million.

The 3,221,982 shares were sold by the counterparty to the underwriters under FSAs.

3,221,982 shares were sold by the counterparty to the underwriters under FSAs.

The forward sale price was initially $ 90.016 per share and was subject to certain adjustments in accordance with the terms of the FSAs through the date of settlement.

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Share dilution occurs when the average market price of IDACORP’s stock during the reporting period is higher than the then-applicable forward sale price as of the end of the reporting period.

As of December 31, 2024 and 2023, approximately 47,000 and 34,000 incremental shares, respectively, were included in the calculation of diluted EPS related to the securities under the FSAs.

As of December 31, 2025, 2024, and 2023, approximately 490,000 , 47,000 , and 34,000 incremental shares, respectively, were included in the calculation of diluted earnings per share related to the securities under the FSAs.

See Note 8 - "Earnings Per Share" for additional information concerning IDACORP's diluted earnings per share.

Idaho Power Common Stock

During 2024, IDACORP contributed $ 200 million of additional capital to Idaho Power.

No additional shares of Idaho Power common stock were issued.

During 2025 and 2024, IDACORP contributed $ 195 million and $ 200 million, respectively, of additional capital to Idaho Power.

During 2025 and 2024, no additional shares of Idaho Power common stock were issued.

Restrictions on Dividends

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A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter.

At December 31, 2024, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively.

At December 31, 2025, the leverage ratios for IDACORP and Idaho Power were 52 percent.

Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $ 1.5 billion and $ 1.3 billion, respectively, at December 31, 2025.

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The total fair value of shares vested was $ 7.4 million in 2025, $ 8.5 million in 2024, and $ 7.5 million in 2023.

At December 31, 2024, IDACORP had $ 9.7 million of total unrecognized compensation cost related to nonvested share-based compensation, nearly all of which was Idaho Power's share.

At December 31, 2025, IDACORP had $ 11.5 million of total unrecognized compensation cost related to nonvested share-based compensation, all of which was Idaho Power's share.

These costs are expected to be recognized over a weighted-average period of 1.7 years.

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EARNINGS PER SHARE

The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2024, 2023, and 2022 (in thousands, except for per share amounts):

Year Ended December 31,

The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31 (in thousands of dollars and shares, except for per share amounts):

2025 2024 2023

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Diluted earnings per share $ 5.90 $ 5.50 $ 5.14

(1) The effect of dilutive securities amount includes approximately 47 thousand and 34 thousand incremental shares related to FSAs as of December 31, 2024 and 2023, respectively.

(1) Includes the effect of dilutive securities related to FSAs.

See Note 6 - "Common Stock" for additional information concerning IDACORP's FSAs.

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2026 2027 2028 2029 2030 Thereafter

Cogeneration, power production, and battery storage $ 340,395 $ 372,123 $ 407,819 $ 455,245 $ 447,778 $ 5,040,605

Cogeneration, power production, battery storage, and transmission rights $ 350,046 $ 383,878 $ 427,829 $ 428,270 $ 425,584 $ 3,710,029

Fuel 191,035 159,806 96,773 45,314 46,063 498,929

As of December 31, 2024, Idaho Power had power purchase obligations with respect to 1,524 MW nameplate capacity of online PURPA and non-PURPA projects, with an additional 1,048 MW nameplate capacity of projects that are scheduled to be online through 2027.

As of December 31, 2025, Idaho Power had power purchase obligations with respect to 1,724 MW nameplate capacity of online PURPA and non-PURPA projects, with an additional 625 MW nameplate capacity of projects that are scheduled to be online in 2026 and 2027.

The agreements for these projects have original contract terms ranging from one to 35 years.

Idaho Power's purchased power expense associated with long-term agreements (including PURPA) was approximately $ 306 million in 2025, $ 294 million in 2024, and $ 258 million in 2023.

In February 2025, Idaho Power entered into a 100 MW solar facility PPA and agreement to purchase the storage capacity from a 100 MW battery storage facility;

both with a scheduled online date of April 2027 and 20 -year terms.

Also, in February 2025, Idaho Power entered into agreements providing ownership of 250 MW and rights to 250 MW of transmission capacity on the

SWIP-N in Nevada, with an expected online date in late 2027 or in 2028.

The agreements collectively increased Idaho Power's contractual obligations by $ 1.1 billion over their respective terms.

Subsequent to December 31, 2025, through the date of this report, Idaho Power entered into an energy and capacity market purchase agreement with an energy marketer that provides Idaho Power the right to acquire 100 MW on a daily basis during the winter months, subject to regulatory approval, which increased Idaho Power's contractual obligations by approximately $ 14.4 million over an approximate 3 -year term commencing in November 2028.

Idaho Power also has the following long-term commitments (in thousands of dollars):

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As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.

(2) As of December 31, 2024, Idaho Power had a remaining $ 904 million commitment related to contracts to acquire and own capacity and generation resources with in-service dates in 2026 and 2027.

(2) As of December 31, 2025, Idaho Power had a remaining $ 481 million commitment related to contracts to acquire and own transmission and generation resources with in-service dates in 2028 and 2030.

At IDACORP, long-term purchase commitments of $ 21.4 million are mostly comprised of other long-term liabilities at Ida-West and IFS.

At December 31, 2025, IDACORP had a commitment to invest an additional $ 2.8 million into a private market investment fund, which is expected to occur over the next few years.

IDACORP’s expense for operating leases was not material for the years ended 2024, 2023, and 2022.

Acquisition of Additional Interest in B2H Transmission Project

In March 2023, Idaho Power executed a purchase, sale, and security agreement with the BPA to transfer BPA's 24 percent interest in the B2H transmission line project to Idaho Power, bringing Idaho Power's interest in the project to approximately 45 percent.

Pursuant to the agreement, Idaho Power has a commitment to provide long-term transmission service to BPA.

The agreement also required BPA to make a $ 10 million security payment to Idaho Power.

On Idaho Power's consolidated balance sheet, the agreement increased construction work in progress by $ 31.4 million for the acquired permitting interest, cash and cash equivalents by $ 10.0 million for the additional security payment, and other non-current liabilities by $ 41.4 million for Idaho Power's obligation to pay for the permitting interest and to return the security deposit to BPA.

Payments to BPA for the permitting interest are expected to be made over a 15 -year period beginning 10 years after energization of the transmission line project, while the security deposit is due to be returned to BPA upon energization.

Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third portion.

Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest.

This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $ 50.1 million at December 31, 2025, representing IERCo's one-third share of BCC's total reclamation obligation of $ 150.2 million.

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BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs.

To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant.

To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales to the Jim Bridger plant.

Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

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Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments.

Idaho Power determines if an arrangement is a lease and its classification at the lease commencement date.

All leases must be recognized as a lease right-of-use (ROU) asset and a lease liability on the balance sheet of the lessee.

The ROU asset represents the right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make lease payments.

Idaho Power has elected the practical expedient to not separate non-lease components from lease components and instead account for both as a single lease component.

Lease ROU assets and lease liabilities are estimated and recognized at the lease commencement date based on the net present value of fixed lease payments over the lease term.

Variable lease payments are expensed as incurred.

If the lease does not provide an implicit rate, Idaho Power uses its collateralized incremental borrowing rate based on the information available at the commencement date to determine the present value of fixed lease payments.

The implicit rate is used when it is readily determinable.

Idaho Power recovers 100 percent of the Idaho-jurisdiction portion of lease payments on all existing arrangements classified as finance leases through the PCA, and recovers the Oregon-jurisdiction portion of lease payments through the APCU.

Idaho Power recognizes lease expenses consistent with regulatory cost recovery, so lease expenses in excess of amounts recovered through the PCA and APCU are deferred as a regulatory asset.

IDACORP does not record leases with a term of 12 months or less in the consolidated balance sheets.

Total short-term lease expense was not material for the years ended 2025, 2024, and 2023.

Finance Leases

Finance leases are included in finance lease ROU assets, other current liabilities, and finance lease liabilities recognized on the consolidated balance sheets upon the lease commencement date.

Amortization of the lease ROU asset is included in depreciation and amortization, and the interest expense associated with the finance lease liabilities is included in interest on long-term debt and finance leases on the consolidated statements of income.

Variable lease payments are not recognized on the consolidated balance sheets and are recorded as incurred in other O&M expense on the consolidated statements of income and

in operating activities in the consolidated statements of cash flows.

Idaho Power’s finance lease ROU assets and liabilities relate to the lease discussed below.

On April 26, 2023, Idaho Power executed an Energy Storage Agreement with Kuna BESS LLC to utilize the storage capacity of a 150 MW battery storage facility over a 20-year term.

The term began May 19, 2025, and has been classified as a finance lease.

The following table provides a summary of the components of total lease cost included in the consolidated statements of income for the year ended December 31 (in thousands of dollars):

Finance lease cost:

Amortization of ROU asset (Depreciation and amortization) $ 3,762

Interest on lease liabilities (Interest on long-term debt and finance leases) (1)

Total finance lease cost 12,348

Variable lease cost (Other O&M) 973

Total lease cost $ 13,321

(1) Included in operating activities in the consolidated statements of cash flows as cash paid for amounts included in the measurement of lease liabilities.

The following table presents the classification of certain lease amounts included in the consolidated balance sheets as of December 31 (in thousands of dollars):

Finance leases:

Other current liabilities $ 6,161

The following table presents the weighted-average remaining lease term and weighted-average discount rate as of December 31:

Finance leases:

Weighted average remaining lease term 19.38 years

Weighted average discount rate 6.17 %

The following table presents the maturities of future fixed lease payments and a reconciliation of undiscounted cash flows to lease liabilities recognized on the consolidated balance sheets as of December 31, 2025 (in thousands of dollars):

Finance Leases

2026 $ 19,751

Thereafter 283,907

Total future fixed lease payments 382,662

amounts representing interest ( 159,806 )

Total present value of lease liabilities 222,856

CONTINGENCIES

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Interest cost 56,151 52,181 5,640 5,332

Actuarial (gain) loss ( 65,972 ) 41,539 ( 3,321 ) 6,518

Actuarial loss (gain) 5,237 ( 65,972 ) 2,401 ( 3,321 )

Plan amendment — — 7 15

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(1) Changes in the funded status of the pension plan that would be recorded in AOCI for an unregulated entity are recorded as a regulatory asset for Idaho Power as Idaho Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.

The actuarial losses reflected in the benefit obligations for the pension and SMSP plans in 2025 are due primarily to actual demographic experience varying from assumed for both plans, and a decrease in the assumed discount rate of the SMSP plan and partially offset by an increase in the assumed discount rates of the pension plan from December 31, 2024 to December 31, 2025.

The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2024 are due primarily to increases in the assumed discount rates of both plans from December 31, 2023 to December 31, 2024.

The actuarial losses reflected in the benefit obligations for the pension and SMSP plans in 2023 are due primarily to decreases in the assumed discount rates of both plans from December 31, 2022, to December 31, 2023.

For more information on discount rates, see “Plan Assumptions” below in this Note 12.

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The rabbi trust holds investments in marketable securities and corporate-owned life insurance.

The recorded value of these investments was approximately $ 159.1 million and $ 146.2 million at December 31, 2024 and 2023, respectively, and is reflected in Investments and in Company-owned life insurance on the consolidated balance sheets.

value of these investments was approximately $ 172.1 million and $ 159.1 million at December 31, 2025 and 2024, respectively, and is reflected in Investments and in Company-owned life insurance on the consolidated balance sheets.

The following table shows the components of net periodic pension cost for these plans (in thousands of dollars).

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As of the date of this report, IDACORP and Idaho Power have no estimated minimum required contributions to the pension plan for 2026.

Depending on market conditions and cash flow considerations in 2025, Idaho Power could contribute up to $ 20 million to the pension plan during 2025 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position.

Depending on market conditions and cash flow considerations in 2025, Idaho Power expects that it may contribute up to $ 30 million to the pension plan during 2026 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position.

Postretirement Benefits

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Interest cost 2,973 2,824

Actuarial gain ( 778 ) ( 2,004 )

Actuarial loss (gain) 1,976 ( 778 )

Benefits paid (1)

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Actuarial gain during the year $ 619 $ 3,616 $ 7,572

Prior service cost arising during the year — — ( 8,065 )

Reclassification adjustments for:

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Dental trend rate — — — — — — 4.0 % 3.5 % 3.5 %

The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 7.1 percent in 2024 and is assumed to decrease to 6.3 percent in 2025, 5.5 percent in 2026, decrease to 5.4 percent in 2027, and to gradually decrease to 3.8 percent by 2074.

The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years.

The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.2 percent in 2025 and is assumed to increase to 7.0 percent in 2026, decrease to 6.2 percent in 2027, decrease to 5.5 percent in 2028, and to gradually decrease to 3.8 percent by 2074.

For 2025 and beyond, the assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 4.0 percent, or equal to the medical trend rate if lower.

Pension Asset Allocation Policy:

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• maintain a prudent risk profile consistent with ERISA fiduciary standards.

Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private infrastructure funds, private direct lending funds, private equity funds, and cash and cash equivalents.

With the exception of real estate holdings, private infrastructure holdings, private direct lending loans, and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.

Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, private real estate funds, private infrastructure funds, private direct lending funds, private equity funds, and cash and cash equivalents.

With the exception of private real estate holdings, private infrastructure holdings, private direct lending loans, and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.

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

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Real estate 77,141

Private market investments 62,976

Other Private market investments 71,760

Total $ 410,786 $ 204,129 $ — $ 1,023,375

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Equity Securities:

Large-Cap 54,346

Commingled Fund:

Equity Securities:

Global and International 124,559

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Real estate 72,913

Private market investments 41,756

Other Private market investments 62,976

Total $ 404,751 $ 184,528 $ — $ 951,142

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The limited partner must hold the fund for the life of the fund or find a third-party buyer.

Private Market Investments :

Other Private Market Investments :

Private market investments represent three categories:

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The private infrastructure fund investment is valued by the fund manager through a process involving an independent third-party external valuator on a quarterly basis, with each investment undergoing a full independent valuation at least once per year.

Redemption on the infrastructure fund are available on a quarterly basis beginning in April of 2027 with 90 days written notice.

Redemption on the infrastructure fund are available on a quarterly basis beginning in April of 2027 with 90

days written notice.

If the fund has sufficient liquidity, the redemption will be processed at the fund NAV at the end of the quarter.

If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the

following quarter on a pro-rata basis with other redemption requests.

If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other redemption requests.

This same process will repeat until the redemption request has been completed.

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Idaho Power accrues a liability for such benefits.

The post-employment benefits included in other liabilities on both IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2024 and 2023, were approximately $ 3 million.

The post-employment benefits included in other liabilities on both IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2025 and 2024, were approximately $ 1 million and $ 3 million.

PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS

The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2024 and 2023 (in thousands of dollars):

Balance Avg Rate Balance Avg Rate

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Transmission 1,653,490 1.91 % 1,534,474 1.89 %

Energy Storage (1)

509,740 5.06 % 393,012 3.61 %

Distribution (1)

2,658,849 2.17 % 2,465,423 2.16 %

General and Other 751,356 5.27 % 706,176 5.18 %

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In service - net $ 5,649,641 $ 5,243,057

(1) The presentation of the major classifications of Idaho Power's utility plant in service in the table above has been modified to separately report the energy storage balance for the years ended December 31, 2025 and 2024.

The prior year energy storage balance, which had previously been classified in the distribution balance, has been reclassified to conform with the current year presentation.

This change reflects a shift from one acceptable presentation to another to enhance transparency.

At December 31, 2025, Idaho Power's construction work in progress balance of $ 1.7 billion included relicensing costs of $ 536.1 million for the HCC, Idaho Power's largest hydropower complex.

In 2024, 2023, and 2022, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $ 6.5 million annually ($ 8.8 million when grossed-up for the effect of income taxes) of AFUDC relating to the HCC relicensing project.

Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates.

The IPUC allows Idaho Power to collect a portion of AFUDC relating to the HCC relicensing project in its Idaho jurisdiction rates.

For more information, refer to Note 3 - "Regulatory Matters." Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates.

At December 31, 2025, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $ 281.0 million.

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Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs.

Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income.

Idaho Power's proportionate share of operating expenses for each facility is included in the

Consolidated Statements of Income.

These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, 2025 (in thousands of dollars):

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Jim Bridger units 1-4 Rock Springs, WY $ 777,096 $ 780 $ 575,151 33 775

North Valmy unit 2 (2)

North Valmy units 1 & 2 (2)

Winnemucca, NV 42,113 21,118 ( 128 ) 50 284

(1) Idaho Power’s share of nameplate capacity.

(2) Pursuant to an agreement with NV Energy, Idaho Power ceased participation in coal-fired operations of North Valmy in December 2019 at unit 1.

Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion of the two generating units at the North Valmy plant from coal to natural gas in 2026.

(2) Pursuant to an agreement with NV Energy, Idaho Power ceased participation in coal-fired operations of North Valmy in December 2019 at unit 1 and December 2025 at unit 2.

Idaho Power's 2025 IRP identified a preferred resource portfolio and action plan that includes the conversion of the two generating units at the North Valmy plant from coal to natural gas by mid-2026.

The conversion of Unit 1 has been completed and the unit was placed in-service in December 2025, and conversion of Unit 2 is expected to be completed by mid-2026.

IERCo, Idaho Power’s wholly-owned subsidiary, is a joint-owner of BCC.

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The regulatory assets recorded under this order do not earn a return on investment.

Idaho Power’s recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities.

Idaho Power’s recorded AROs relate to the reclamation and removal costs at its jointly-owned thermal generation facilities.

In 2025, changes in estimates at the jointly-owned thermal generation facilities resulted in a net increase of $ 21.6 million in the recorded AROs.

The increase is primarily related to updated post-closure cost estimates for a flue gas desulfurization pond at the Jim Bridger plant which was retired in December 2025.

Idaho Power also has additional AROs associated with its transmission system and generation facilities;

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The following table presents the changes in the carrying amount of AROs (in thousands of dollars):

Balance at beginning of year $ 48,997 $ 37,557

Balance at January 1 $ 51,126 $ 48,997

Accretion expense 2,457 1,895

1 unchanged sentence

Liability settled ( 1,249 ) ( 608 )

Balance at end of year $ 51,126 $ 48,997

Balance at December 31 $ 73,976 $ 51,126

The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):

36 unchanged sentences

IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk, with most of IFS’s investments having been made through syndicated funds.

IDACORP accounts for its equity-method investments in qualified real estate projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.

IDACORP accounts for its equity-method investments in

qualified real estate projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.

DERIVATIVE FINANCIAL INSTRUMENTS

6 unchanged sentences

Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement.

Idaho Power does not offset a

counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default.

Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default.

Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.

1 unchanged sentence

These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2024, 2023, and 2022 (in thousands of dollars):

The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31 (in thousands of dollars):

Location of Realized Gain/(Loss) on Derivatives Recognized in Income Gain/(Loss) on Derivatives Recognized in Income (1)

21 unchanged sentences

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2025, was $ 55.8 million.

Idaho Power posted $ 25.1 million cash collateral related to this amount.

As of December 31, 2025, Idaho Power posted $ 45.1 million of cash collateral related to this amount.

If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2025, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $ 34.0 million to cover open liability positions as well as completed transactions that have not yet been paid.

Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2024 and 2023 (in thousands of dollars):

Asset Derivatives Liability Derivatives

2 unchanged sentences

Financial swaps Other current liabilities 2,535 ( 2,535 ) — 34,486 ( 29,394 ) (1) 5,092

Forward contracts Other current assets 3 — 3 — — —

Forward contracts Other current liabilities — — — 1,009 — 1,009

Financial swaps Other assets 1,939 ( 1,939 ) (2) — 409 ( 409 ) —

Financial swaps Other liabilities 1,444 ( 1,444 ) — 7,479 ( 4,385 ) (2) 3,094

2 unchanged sentences

December 31, 2024

Financial swaps Other current assets $ 241 $ ( 169 ) $ 72 $ 169 $ ( 169 ) $ —

Financial swaps Other current liabilities 3,072 ( 3,072 ) — 18,092 ( 14,931 ) (3) 3,161

2 unchanged sentences

Financial swaps Other liabilities 177 ( 177 ) — 1,019 ( 177 ) 842

Forward contracts Other liabilities — — — 10,965 — 10,965

Total $ 5,188 $ ( 5,188 ) $ — $ 31,776 $ ( 15,517 ) $ 16,259

(1) Current liability derivative amounts offset include $ 26.9 million of collateral receivable at December 31, 2025.

(2) Long-term asset derivative amounts offset include $ 1.5 million of collateral payable at December 31, 2024.

(3) Current liability derivative amounts offset include $ 36.6 million of collateral receivable at December 31, 2023.

(2) Long-term liability derivative amounts offset include $ 2.9 million of collateral receivable at December 31, 2025.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2024 and 2023 (in thousands of units):

(3) Current liability derivative amounts offset include $ 11.9 million of collateral receivable at December 31, 2024.

(4) Long-term asset derivative amounts offset include $ 1.5 million of collateral payable at December 31, 2024.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31 (in thousands of units):

Commodity Units 2025 2024

22 unchanged sentences

however, in accordance with GAAP are not classified within the fair value hierarchy levels.

The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2024 and 2023 (in thousands of dollars):

December 31, 2024 December 31, 2023

The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31 (in thousands of dollars):

Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total

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The investments are measured using quoted prices in active markets and are held in a rabbi trust.

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2024 and 2023, using available market information and appropriate valuation methodologies (in thousands of dollars).

December 31, 2024 December 31, 2023

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, using available market information and appropriate valuation methodologies (in thousands of dollars).

Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value

22 unchanged sentences

The President and Chief Executive Officer of IDACORP and Idaho Power is the companies' chief operating decision maker (CODM).

The CODM uses net income to monitor the utility segment's results, monitor and plan utility-specific regulatory strategy, allocate capital investments, and inform financing decisions.

The CODM uses net income, compared with historical results and forecasted expectations, to monitor the utility segment's results, monitor and plan utility-specific regulatory strategy, allocate capital investments, and inform financing decisions.

The CODM is regularly provided with segment expense information for utility operations at the same level of detail as presented in Idaho Power's consolidated statements of income.

The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands):

The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars):

Operations All

1 unchanged sentence

Revenues $ 1,809,609 $ 3,388 $ — $ 1,812,997

Depreciation 223,410 — — 223,410

Depreciation and amortization 251,072 — — 251,072

Operating income 355,417 ( 1,441 ) — 353,976

4 unchanged sentences

Income before income taxes 302,685 7,733 — 310,418

Income tax expense (benefit) 17,681 ( 2,628 ) — 15,053

Income tax benefit ( 13,177 ) ( 538 ) — ( 13,715 )

Net Income attributable to IDACORP, Inc.

3 unchanged sentences

Revenues $ 1,822,965 $ 3,668 $ — $ 1,826,633

Depreciation 195,341 — — 195,341

Depreciation and amortization 223,410 — — 223,410

Operating income 328,183 ( 344 ) — 327,839

10 unchanged sentences

Revenues $ 1,762,894 $ 3,462 $ — $ 1,766,356

Depreciation 170,077 — — 170,077

Depreciation and amortization 195,341 — — 195,341

Operating income 313,379 98 — 313,477

26 unchanged sentences

Comprehensive income includes net income and amounts related to the SMSP.

The table below presents changes in components of AOCI, net of tax, during the years ended December 31, 2024, 2023, and 2022 (in thousands of dollars).

The table below presents changes in components of AOCI, net of tax, during the years ended December 31 (in thousands of dollars).

Items in parentheses indicate reductions to AOCI.

Year Ended December 31,

2025 2024 2023

7 unchanged sentences

Balance at end of period $ ( 14,944 ) $ ( 13,592 ) $ ( 17,184 )

The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2024, 2023, and 2022 (in thousands of dollars).

Items in parentheses indicate increases to net income.

Amount Reclassified from AOCI

Year Ended December 31,

2025 2024 2023

14 unchanged sentences

At December 31, 2025 and 2024, Idaho Power had a $ 3.3 million and $ 3.2 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance on its consolidated balance sheets.

At December 31, 2023, the payable was primarily related to income tax payments.

At IDACORP, the receivable from Idaho Power is eliminated in consolidation.

1 unchanged sentence

Idaho Power purchased $ 9.5 million in 2025, $ 9.6 million in 2024, and $ 9.1 million in 2023 of power from Ida-West.

SALE OF OREGON ASSETS

On February 13, 2026, Idaho Power executed a definitive agreement to sell its Oregon electric distribution business as well as certain Oregon transmission assets to OTEC.

The base purchase price to be paid by OTEC for the Oregon Sale is $ 154 million, and is subject to certain adjustments at the closing of the transaction.

Idaho Power has agreed to operate its Oregon electric distribution business and applicable transmission assets in the ordinary course of business and subject to certain operating covenants during the period between the date of the asset purchase agreement and the completion of the proposed transaction.

The Oregon Sale is subject to various closing conditions, including approvals of the OPUC, IPUC, and FERC, as well as certain

price adjustment and termination provisions.

Any gain or loss resulting from the Oregon Sale is expected to be immaterial to the consolidated financial statements of both IDACORP and Idaho Power.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

101 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data