What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2026-02-25 compared with 2025-02-25 · 1442 added, 1357 removed, 1838 unchanged (60% of the section changed)

18 unchanged sentences

Summary of Significant Accounting Policies

Regulatory Matters

Business Segments

New Accounting Standards

Lines of Credit and Short-Term Borrowings

Long-Term Debt and Liquidity Matters

Regulatory Matters

Retirement Plans and Other Postretirement Benefits

Jointly-Owned Facilities

Commitments and Contingencies

Asset Retirement Obligations

Fair Value Measurements

Common Stock Equity and Earnings Per Share

Stock-Based Compensation

Jointly-Owned Facilities

Variable Interest Entities

Derivative Accounting

Commitments and Contingencies

Other Income and Other Expense

Variable Interest Entities

Common Stock Equity and Earnings Per Share

Fair Value Measurements

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

Changes in Accumulated Other Comprehensive Loss

Asset Retirement Obligations

Sale of Bright Canyon Energy

New Accounting Standards

El Dorado Equity Investments

MANAGEMENT’S REPORT ON INTERNAL CONTROL

1 unchanged sentence

(PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), for Pinnacle West Capital Corporation.

Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2024.

Based on our evaluation under this framework , our management concluded that our internal control over financial reporting was effective as of December 31, 2025.

The effectiveness of our internal control over financial reporting as of December 31, 2025, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

38 unchanged sentences

Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment;

regulatory assets and liabilities;

deferred fuel and purchased power regulatory asset;

other regulatory assets;

regulatory liabilities (short-term and long-term);

operating revenues;

fuel and purchased power;

fuel and purchased power expense;

operations and maintenance expense;

and depreciation expense.

and depreciation and amortization expense.

The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital.

Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs and

return on invested capital included in rates and any refunds that may be required.

Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs and return on invested capital included in rates and any refunds that may be required.

While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve:

1 unchanged sentence

If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.

We identified Regulatory Accounting, specifically the impact of rate regulation on the financial statements, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements.

Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes, and recent rate orders specific to APS and to other regulated entities in the same jurisdiction.

2 unchanged sentences

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the impact of rate regulation on the financial statements included the following, among others:

Our audit procedures related to the uncertainty of future decisions by the ACC included the following, among others:

• We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs of recently completed plant and costs deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities.

2 unchanged sentences

and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

• We evaluated the Company’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.

• We evaluated the APS’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.

• We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances.

We evaluated the external information, regulatory orders and filings, and compared to management’s recorded regulatory assets and liabilities for completeness.

◦ We read the ACC’s approved decision regarding the 2022 Retail Rate Case.

◦ We obtained the Company’s internally prepared memo concluding on the impacts of the ACC’s approved decision regarding the 2022 Retail Rate Case on rates and recorded regulatory balances.

◦ We read and analyzed the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact

management’s conclusions with respect to the financial statement impacts of rate regulation.

• We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedents set by the ACC under similar circumstances.

We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.

• For regulatory matters in process, we inspected APS’s filings with the ACC and the filings with the ACC by intervenors that may impact the APS’s future rates, for evidence that might contradict management’s assertions.

• We obtained an analysis from management and internal legal counsel regarding the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ Deloitte & Touche LLP

57 unchanged sentences

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX

Derivative instruments:

Net unrealized gain (loss), net of tax benefit (expense) of $( 292 ), $ 234 , and $ 615

Derivative instruments net unrealized gain (loss), net of tax benefit (expense) of $ 49 , $( 292 ), and $ 234

( 147 ) ( 891 ) 713

16 unchanged sentences

Customer and other receivables 579,831 525,608

Accrued unbilled revenues 176,903 167,553

Accrued unbilled revenues (Note 4)

173,692 176,903

Allowance for doubtful accounts (Note 4)

4 unchanged sentences

Assets from risk management activities (Note 13)

Assets held for sale (Note 20)

Deferred fuel and purchased power regulatory asset (Note 8)

29 unchanged sentences

3,649,669 1,605,463

Assets for pension and other postretirement benefits (Note 7)

Assets for other postretirement benefits (Note 9)

399,334 342,102

30 unchanged sentences

DEFERRED CREDITS AND OTHER

Liabilities from risk management activities (Note 13)

Deferred income taxes (Note 5)

2 unchanged sentences

1,736,121 1,855,278

Liabilities for asset retirements (Note 11)

1,096,577 937,451

Liabilities for pension benefits (Note 9)

167,636 139,317

Liabilities from risk management activities (Note 15)

Liabilities for asset retirements (Note 21)

1,198,601 1,096,577

Customer advances 632,169 569,343

9 unchanged sentences

Common stock, no par value;

authorized 150,000,000 shares, 119,143,782 and 113,537,689 issued at respective dates

authorized 300,000,000 and 150,000,000 shares authorized at respective dates, 120,950,839 and 119,143,782 shares issued at respective dates

3,231,372 3,121,617

22 unchanged sentences

Depreciation and amortization including nuclear fuel 969,615 956,184 854,136

Deferred fuel and purchased power ( 250,288 ) ( 549,877 ) ( 291,992 )

Deferred fuel and purchased power amortization 425,886 547,243 219,579

Allowance for equity funds used during construction ( 61,146 ) ( 38,620 ) ( 53,118 )

8 unchanged sentences

Income tax receivable ( 5,979 ) 332 13,754

Deferred fuel and purchased power ( 324,482 ) ( 250,288 ) ( 549,877 )

Deferred fuel and purchased power amortization 463,011 425,886 547,243

Other current assets ( 42,991 ) ( 50,225 ) ( 19,550 )

2 unchanged sentences

Other current liabilities 18,714 47,329 40,510

Change in unrecognized tax benefits 81,090 75 1,177

Change in long-term regulatory assets 91,373 43,305 53,112

22 unchanged sentences

Common stock equity issuance and purchases — net 84,613 341,429 ( 4,093 )

Palo Verde sale leaseback noncontrolling interest acquisition ( 198,744 ) — —

Capital activities by noncontrolling interests ( 18,041 ) ( 21,255 ) ( 21,255 )

12 unchanged sentences

— — 501,557 — 17,224 518,781

Other comprehensive income

Other comprehensive loss

— — — ( 1,709 ) — ( 1,709 )

9 unchanged sentences

— — 608,806 — 17,224 626,030

Other comprehensive loss

Other comprehensive income

— — — 2,202 — 2,202

1 unchanged sentence

— — ( 408,162 ) — — ( 408,162 )

Issuance of common stock 290,500 27,936 — — — — 27,936

Issuance of common stock (b) 5,606,093 368,941 — — — — 368,941

Purchase of treasury stock (a) — ( 71,008 ) ( 4,907 ) — — — ( 4,907 )

5 unchanged sentences

— — 616,531 — 15,112 631,643

Other comprehensive income

Other comprehensive loss

— — — ( 1,466 ) — ( 1,466 )

2 unchanged sentences

Issuance of common stock (b) 1,807,057 109,755 — — — 109,755

Purchase of treasury stock (a) — ( 71,008 ) ( 4,907 ) — — — ( 4,907 )

Reissuance of treasury stock for stock-based compensation and other — 137,312 9,768 — — — 9,768

Capital activities by noncontrolling interests — — — — ( 18,041 ) ( 18,041 )

Deconsolidation of noncontrolling interests (c) — — — — ( 59,621 ) ( 59,621 )

Other — — ( 2 ) — — ( 2 )

2 unchanged sentences

(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

(b) See Note 13 for information related to our equity forward sale agreements that were executed in February 2024 and November 2024.

As of December 31, 2024, 5,377,115 shares of common stock have been issued as part of these agreements.

(b) See Note 16 for information related to our equity forward sale agreements.

The accompanying notes are an integral part of the financial statements.

2 unchanged sentences

(ARIZONA PUBLIC SERVICE COMPANY)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), for APS.

Based on our evaluation under this framework , our management concluded that our internal control over financial reporting was effective as of December 31, 2025.

38 unchanged sentences

Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment;

regulatory assets and liabilities;

deferred fuel and purchased power regulatory asset;

other regulatory assets;

regulatory liabilities (short-term and long-term);

operating revenues;

fuel and purchased power;

fuel and purchased power expense;

operations and maintenance expense;

and depreciation expense.

and depreciation and amortization expense.

The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital.

Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs and

return on invested capital included in rates and any refunds that may be required.

Decisions to be made by the ACC in the future will impact the

accounting for regulated operations, including decisions about the amount of allowable deferred costs and return on invested capital included in rates and any refunds that may be required.

While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve:

1 unchanged sentence

If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.

2 unchanged sentences

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the impact of rate regulation on the financial statements included the following, among others:

Our audit procedures related to the uncertainty of future decisions by the ACC included the following, among others:

4 unchanged sentences

• We read relevant regulatory rate orders issued by the ACC for the Company and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances.

We evaluated the external information, regulatory orders and filings, and compared to management’s recorded regulatory assets and liabilities for completeness.

◦ We read the ACC’s approved decision regarding the 2022 Retail Rate Case.

◦ We obtained the Company’s internally prepared memo concluding on the impacts of the ACC’s approved decision regarding the 2022 Retail Rate Case on rates and recorded regulatory balances.

◦ We read and analyzed the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact

management’s conclusions with respect to the financial statement impacts of rate regulation.

We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.

• For regulatory matters in process, we inspected the Company’s filings with the ACC and the filings with the regulatory authorities by intervenors that may impact the Company’s future rates, for evidence that might contradict managements assertions.

/s/ Deloitte & Touche LLP

64 unchanged sentences

(dollars in thousands)

PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)

Plant in service and held for future use $ 25,860,068 $ 24,207,706

Accumulated depreciation and amortization ( 9,026,544 ) ( 8,404,721 )

Net 16,833,524 15,802,985

Construction work in progress 1,592,659 1,724,004

Palo Verde sale leaseback, net of accumulated depreciation of $ 268,894 and $ 264,624 (Note 17)

82,556 86,426

Intangible assets, net of accumulated amortization of $ 925,880 and $ 884,371

591,154 266,955

Nuclear fuel, net of accumulated amortization of $ 115,894 and $ 118,074

97,850 99,490

Total property, plant and equipment 19,197,743 17,979,860

INVESTMENTS AND OTHER ASSETS

Nuclear decommissioning trusts (Notes 12 and 18)

1,282,845 1,201,246

Other special use funds (Notes 12 and 18)

374,156 362,781

Assets from risk management activities (Note 15)

Other assets 49,673 43,625

Total investments and other assets 1,712,654 1,607,652

CURRENT ASSETS

1 unchanged sentence

Customer and other receivables 592,146 522,886

Accrued unbilled revenues 176,903 167,553

Accrued unbilled revenues (Note 4)

173,692 176,903

Allowance for doubtful accounts (Note 4)

1 unchanged sentence

Materials and supplies (at average cost) 546,329 469,022

Fossil fuel (at average cost) 32,420 49,203

Income tax receivable (Note 5)

Fossil fuel (at average cost) 18,824 32,420

Assets from risk management activities (Note 13)

5 unchanged sentences

Total current assets 1,701,718 1,682,961

INVESTMENTS AND OTHER ASSETS

Nuclear decommissioning trusts (Notes 17 and 18)

1,414,166 1,282,845

Other special use funds (Notes 17 and 18)

394,514 374,156

Assets from risk management activities (Note 13)

Other assets 50,912 49,673

Total investments and other assets 1,864,729 1,712,654

PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 11)

Plant in service and held for future use 27,369,414 25,860,068

Accumulated depreciation and amortization ( 9,011,139 ) ( 9,026,544 )

Net 18,358,275 16,833,524

Construction work in progress 1,649,542 1,592,659

Palo Verde sale leaseback, net of accumulated depreciation of $ 110,886 and $ 268,894 (Note 12)

32,035 82,556

Intangible assets, net of accumulated amortization of $ 1,057,812 and $ 925,880

575,823 591,154

Nuclear fuel, net of accumulated amortization of $ 111,096 and $ 115,894

104,274 97,850

Total property, plant and equipment 20,719,949 19,197,743

DEFERRED DEBITS

3 unchanged sentences

3,648,658 1,604,324

Assets for pension and other postretirement benefits (Note 7)

Assets for other postretirement benefits (Note 9)

392,348 335,458

7 unchanged sentences

LIABILITIES AND EQUITY

CAPITALIZATION

Common stock $ 178,162 $ 178,162

Additional paid-in capital 4,116,696 3,321,696

Retained earnings 3,992,423 3,759,299

Accumulated other comprehensive loss (Note 19)

( 14,116 ) ( 17,219 )

Total shareholder equity 8,273,165 7,241,938

Noncontrolling interests (Note 17)

103,167 107,198

Total equity 8,376,332 7,349,136

Long-term debt less current maturities (Note 6)

7,190,878 7,041,891

Total capitalization 15,567,210 14,391,027

CURRENT LIABILITIES

Short-term borrowings (Note 5)

339,900 532,850

Current maturities of long-term debt (Note 6)

300,000 250,000

Accounts payable $ 672,518 $ 481,955

2 unchanged sentences

Common dividends payable 110,000 107,200

Short-term borrowings (Note 6)

507,305 339,900

Current maturities of long-term debt (Note 7)

250,000 300,000

Customer deposits 63,776 44,345

10 unchanged sentences

DEFERRED CREDITS AND OTHER

Liabilities from risk management activities (Note 13)

Deferred income taxes (Note 5)

2 unchanged sentences

1,736,121 1,855,278

Liabilities for asset retirements (Note 11)

1,096,577 937,451

Liabilities for pension benefits (Note 9)

164,892 134,855

Liabilities from risk management activities (Note 15)

Liabilities for asset retirements (Note 21)

1,198,601 1,096,577

Customer advances 632,169 569,343

8 unchanged sentences

COMMITMENTS AND CONTINGENCIES (Note 14)

CAPITALIZATION

Common stock 178,162 178,162

Additional paid-in capital 4,491,696 4,116,696

Retained earnings 4,227,237 3,992,423

Accumulated other comprehensive loss (Note 19)

( 15,457 ) ( 14,116 )

Total shareholder equity 8,881,638 8,273,165

Noncontrolling interests (Note 12)

40,617 103,167

Total equity 8,922,255 8,376,332

Long-term debt less current maturities (Note 7)

7,889,940 7,190,878

Total capitalization 16,812,195 15,567,210

TOTAL LIABILITIES AND EQUITY $ 29,886,359 $ 25,988,235

9 unchanged sentences

Depreciation and amortization including nuclear fuel 969,547 956,009 854,051

Deferred fuel and purchased power ( 250,288 ) ( 549,877 ) ( 291,992 )

Deferred fuel and purchased power amortization 425,886 547,243 219,579

Allowance for equity funds used during construction ( 61,146 ) ( 38,620 ) ( 53,118 )

6 unchanged sentences

Income tax receivable 5,463 ( 5,463 ) 1,102

Deferred fuel and purchased power ( 324,482 ) ( 250,288 ) ( 549,877 )

Deferred fuel and purchased power amortization 463,011 425,886 547,243

Other current assets ( 46,286 ) ( 14,704 ) ( 20,243 )

2 unchanged sentences

Other current liabilities 16,162 31,982 62,212

Change in unrecognized tax benefits 81,090 75 1,177

Change in long-term regulatory assets 91,373 43,305 53,112

21 unchanged sentences

Equity infusion from Pinnacle West 375,000 795,000 150,000

Capital activities of noncontrolling interests ( 21,255 ) ( 21,255 ) ( 21,255 )

Palo Verde sale leaseback noncontrolling interest acquisition ( 198,744 ) — —

Capital activities by noncontrolling interests ( 18,041 ) ( 21,255 ) ( 21,255 )

Net cash provided by financing activities 543,270 375,237 412,140

12 unchanged sentences

— — 547,337 — 17,224 564,561

Other comprehensive income

Other comprehensive loss

— — — ( 1,623 ) — ( 1,623 )

1 unchanged sentence

Capital activities by noncontrolling interests — — — — ( 21,255 ) ( 21,255 )

Other — — ( 2 ) — — ( 2 )

Balance, December 31, 2023

2 unchanged sentences

— — 641,925 — 17,224 659,149

Other comprehensive loss

Other comprehensive income

— — — 3,103 — 3,103

6 unchanged sentences

— — 667,315 — 15,112 682,427

Other comprehensive income

Other comprehensive loss

— — — ( 1,341 ) — ( 1,341 )

1 unchanged sentence

Capital activities by noncontrolling interests — — — — ( 18,041 ) ( 18,041 )

Deconsolidation of noncontrolling interests (a) — — — — ( 59,621 ) ( 59,621 )

Other — — ( 1 ) — — ( 1 )

1 unchanged sentence

71,264,947 $ 178,162 $ 4,491,696 $ 4,227,237 $ ( 15,457 ) $ 40,617 $ 8,922,255

(a) See Note 12 for information related to the Palo Verde sale leaseback purchases.

The accompanying notes are an integral part of the financial statements.

2 unchanged sentences

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado and PNW Power.

Pinnacle West is an investor-owned electric utility holding company that conducts business through its subsidiaries, APS, El Dorado and PNW Power.

APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.

1 unchanged sentence

El Dorado is a wholly-owned subsidiary that invests in energy-related and Arizona community-based ventures.

PNW Power is a wholly-owned subsidiary that was created in September 2023 to hold certain investments in wind and transmission joint projects.

See Note 20 for more information on PNW Power.

BCE was a Pinnacle West subsidiary that was formed in 2014.

On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which all of our equity interest in BCE was sold.

The sale was completed on January 12, 2024.

See Note 20 for more information relating to the sale of BCE.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries, including APS, El Dorado, and PNW Power, as well as our former subsidiary BCE until its sale.

Pinnacle West’s Consolidated Financial Statements also include the accounts of a VIE relating to a Captive Insurance Cell (“Captive”).

PNW Power, formed in September 2023, is a wholly-owned subsidiary that holds certain wind and transmission joint-venture investments previously held by BCE.

BCE was sold on January 12, 2024 and is no longer included in the Company’s consolidated financial statements.

See Note 22 for additional information.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries, including APS, El Dorado, and PNW Power, as well as BCE through the date of its sale.

Pinnacle West’s Consolidated Financial Statements also include the accounts of a VIE relating to the Captive.

APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.

In September 2025, APS purchased two of the three leased interests, resulting in the termination of the related lease agreements and discontinuation of VIE consolidation for those leases.

See Note 12 for additional information.

Intercompany accounts and transactions between the consolidated companies have been eliminated.

We consolidate Variable Interest Entities (each a “VIE”) for which we are the primary beneficiary.

We consolidate VIEs for which we are the primary beneficiary.

We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.

1 unchanged sentence

We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.

We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities.

We have determined that APS is the primary beneficiary of a VIE lessor trust relating to the Palo Verde sale leaseback, and therefore APS consolidates this entity.

We have also determined that Pinnacle West is the primary beneficiary of a protected captive insurance cell VIE, and therefore Pinnacle West consolidates this insurance cell.

1 unchanged sentence

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Our accounting records are maintained in accordance with GAAP.

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.

46 unchanged sentences

Distribution 9,626,629 9,016,843

Energy storage 515,935 276,954

Solar plant 1,501,301 1,159,385

General plant 1,587,029 1,596,222

10 unchanged sentences

We charge retired utility plant to accumulated depreciation.

Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.

Accretion of the liability due to the passage of time is an operating expense, and

Liabilities associated with the retirement of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the capitalized cost is depreciated over the useful life of the long-lived asset.

tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.

Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.

See Note 21 for additional information.

8 unchanged sentences

• Distribution — 33 years;

• Energy storage — 19 years;

• Solar plant — 28 years;

• General plant — 10 years.

12 unchanged sentences

Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 11 for further information on Asset Retirement Obligations.

See Note 21 for additional information.

Allowance for Funds Used During Construction

1 unchanged sentence

Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.

Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

AFUDC was calculated by using a composite rate of 6.67 % for 2025, 6.23 % for 2024, and 6.29 % for 2023.

APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020, through February 28, 2021.

On February 23, 2021, this waiver was extended until September 30, 2021.

On September 21, 2021, it was further extended until March 31, 2022.

The order provided a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic.

APS adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and left all other aspects of the AFUDC formula composite rate calculation unchanged.

This change impacted the AFUDC composite rate in 2021 and for the three-month period ended March 31, 2022.

Furthermore, the change in the composite rate calculation did not impact our accounting treatment for these costs.

The change did not have a material impact on our financial statements.

Materials and Supplies

4 unchanged sentences

On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans.

Due to the short-term nature of short-term borrowings, the carrying values of these instruments approximate fair value.

Due to the nature of short-term borrowings, the carrying values of these instruments approximate fair value.

Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.

7 unchanged sentences

For options, long-term contracts, and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.

Actual results could differ from the results estimated through application of these methods.

See Note 12 for additional information about fair value measurements.

See Note 17 for additional information.

Derivative Accounting

2 unchanged sentences

As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas as well as interest rate risk.

The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

The changes in market value

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of such contracts have a high correlation to price changes in the hedged transactions.

We also enter into derivative instruments for economic hedging purposes.

2 unchanged sentences

Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.

See Note 15 for additional information about our derivative instruments.

See Note 13 for additional information.

Loss Contingencies and Environmental Liabilities

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A reserve for IBNR is based upon a loss analysis prepared using actuarial assumptions and techniques.

Such liabilities are necessarily based on estimates and the ultimate liability may be in excess of or less than the amount provided.

Such liabilities are necessarily based on estimates and the ultimate obligation may be in excess of or less than the estimated liability.

The methods for making such estimates and for establishing the resulting liability are continually reviewed, and any adjustments for the review process as well as differences between estimates and ultimate payments are reflected in earnings currently.

As of December 31, 2024, no IBNR reserve relating to our captive insurance cell has been recorded.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2025, no IBNR reserve relating to our Captive has been recorded.

See Note 12 for additional information.

Retirement Plans and Other Postretirement Benefits

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Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.

See Note 7 for additional information on pension and other postretirement benefits.

See Note 9 for additional information.

APS amortizes nuclear fuel by using the unit-of-production method.

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APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.

The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $ 0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.

The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$ 0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.

In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we accrued a receivable and an offsetting regulatory liability through the settlement period ended December of 2025.

See Note 10 for information on spent nuclear fuel disposal costs.

See Note 14 for additional information.

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.

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The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50 % likely of being realized upon settlement for all known and measurable tax exposures.

See Note 4 for additional discussion.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 5 for additional information.

Cash and Cash Equivalents

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Cash paid during the period for:

Income taxes, net of refunds $ 133,968 $ 8,788 $ 46,227

Income taxes, net of refunds/credits $ 22,754 $ 133,968 $ 8,788

Interest, net of amounts capitalized 388,540 360,349 310,996

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Cash paid during the period for:

Income taxes, net of refunds $ 179,013 $ 21,734 $ 95,985

Income taxes, net of refunds/credits $ 53,638 $ 179,013 $ 21,734

Interest, net of amounts capitalized 307,520 299,799 267,261

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Dividends accrued but not yet paid 110,000 107,200 99,800

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Intangible Assets

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Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 3 - 5 % ownership and no significant influence).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 23 for additional information.

PNW Power holds investments in equity securities.

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Our investments in the nuclear decommissioning trusts, and other special use funds, are accounted for in accordance with guidance on accounting for investments in debt and equity securities.

See Notes 12 and 18 for more information on these investments.

See Notes 17 and 18 for additional information.

We determine if an agreement is a lease at contract inception.

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APS enters into purchased power contracts that may contain leases.

This occurs when a purchased power agreement designates a specific power plant or facility, APS obtains substantially all of the economic benefits from the use of the facility and has the right to direct the use of the facility.

This occurs when a PPA designates a specific power plant or facility, APS obtains substantially all of the economic benefits from the use of the facility and has the right to direct the use of the facility.

Purchased power lease contracts may also include energy storage facilities.

Lease costs relating to purchased power lease contracts are reported in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES.

Lease costs relating to purchased power lease contracts are

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

reported in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES.

See Note 8 for additional information.

We also may enter into lease agreements related to vehicles, office space, land, and other equipment.

See Note 8 for information on our lease agreements.

See Note 20 for a dditional information .

Preferred Stock

At December 31, 2025, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $ 25 , $ 50 , and $ 100 par values, none of which was outstanding.

Business Segments

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission, and distribution.

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of retail and wholesale sales supplied under traditional cost-based regulation and related activities and includes electricity generation, transmission, and distribution.

Our reportable segment activities are conducted through our wholly-owned subsidiary, APS.

All other operating segment activities are insignificant to Pinnacle West.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For segment reporting purposes, Pinnacle West’s Chief Executive Officer performs the function of chief operating decision maker (“CODM”).

The CODM uses net income to measure an operating segment’s profitability.

When assessing the performance of an operating segment, and making decisions about allocating resources, the CODM evaluates net income actual results compared to budget.

Our CODM uses net income to measure an operating segment’s profitability.

When assessing the performance of an operating segment, and making decisions about allocating resources, our CODM evaluates net income actual results compared to budget.

Net income is also used when implementing strategic initiatives and selecting projects to meet business objectives.

Our reportable segment’s revenue streams are dependent upon regulated rate recovery, which is a primary factor in how we identify operating segments.

For information on our reportable business segment’s revenues, significant expenses, net income, assets, and other reportable segment items, see the APS’s Consolidated Income Statements, APS Consolidated Balance Sheets, and APS Consolidated Statements of Cash Flows.

The following tables reconcile our reportable segment’s revenues, significant expenses, net income, and assets to the Pinnacle West Consolidated amounts (dollars in millions):

For information on our reportable business segment’s revenues, significant expenses, net income (loss), assets, and other reportable segment items, see the APS Consolidated Statements of Income, APS Consolidated Balance Sheets, and APS Consolidated Statements of Cash Flows.

The following table reconciles our reportable segment’s revenues, significant expenses, and net income (loss) to the Pinnacle West consolidated amounts (dollars in millions):

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31,

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Operating revenues $ 5,340 $ — $ 5,340 $ 5,125 $ — $ 5,125 $ 4,696 $ — $ 4,696

Fuel & Purchase Power ( 1,823 ) — ( 1,823 ) ( 1,793 ) — ( 1,793 ) ( 1,629 ) — ( 1,629 )

Operations & Maintenance ( 1,159 ) ( 6 ) ( 1,165 ) ( 1,044 ) ( 15 ) ( 1,059 ) ( 974 ) ( 13 ) ( 987 )

Depreciation & Amortization ( 895 ) — ( 895 ) ( 794 ) — ( 794 ) ( 753 ) — ( 753 )

Fuel and purchased power ( 1,933 ) — ( 1,933 ) ( 1,823 ) — ( 1,823 ) ( 1,793 ) — ( 1,793 )

Operations and maintenance ( 1,177 ) ( 8 ) ( 1,185 ) ( 1,159 ) ( 6 ) ( 1,165 ) ( 1,044 ) ( 15 ) ( 1,059 )

Depreciation and amortization ( 915 ) — ( 915 ) ( 895 ) — ( 895 ) ( 794 ) — ( 794 )

Taxes other than income taxes ( 235 ) — ( 235 ) ( 227 ) — ( 227 ) ( 224 ) — ( 224 )

Allowance for equity funds used during construction 61 — 61 39 — 39 53 — 53

Pension and other postretirement non-service credits, net 13 ( 1 ) 12 49 — 49 42 ( 1 ) 41

Other income and expenses, net (a) 28 22 50 60 — 60 22 ( 23 ) ( 1 )

Interest expense and costs ( 312 ) ( 65 ) ( 377 ) ( 285 ) ( 46 ) ( 331 ) ( 236 ) ( 20 ) ( 256 )

Other income and (expense), net ( 14 ) 30 16 ( 11 ) 22 11 7 — 7

Interest charges, net of allowance for borrowed funds used during construction ( 332 ) ( 90 ) ( 422 ) ( 312 ) ( 65 ) ( 377 ) ( 285 ) ( 46 ) ( 331 )

Income taxes ( 126 ) 19 ( 107 ) ( 127 ) 16 ( 111 ) ( 94 ) 17 ( 77 )

income related to noncontrolling interest ( 17 ) — ( 17 ) ( 17 ) — ( 17 ) ( 17 ) — ( 17 )

Net income attributable to noncontrolling interests ( 15 ) — ( 15 ) ( 17 ) — ( 17 ) ( 17 ) — ( 17 )

Net Income (Loss) $ 667 $ ( 50 ) $ 617 $ 642 $ ( 33 ) $ 609 $ 547 $ ( 45 ) $ 502

(a) See Note 16 for additional details regarding other income and other expenses.

Other income includes allowance for equity funds used during construction, see the APS Consolidated Income Statements.

The following table reconciles our reportable segment’s assets to the Pinnacle West consolidated amount (dollars in millions):

December 31, 2025 December 31, 2024

Regulated Electricity Segment Other PNW Consolidated Regulated Electricity Segment Other PNW Consolidated

Regulated Electricity Segment Other Pinnacle West Consolidated Regulated Electricity Segment Other Pinnacle West Consolidated

Total Assets $ 29,886 $ 146 $ 30,032 $ 25,988 $ 115 $ 26,103

New Accounting Standards

ASU 2023-09, Income Taxes:

Improvements to Income Tax Disclosures

In December 2023, a new accounting standard was issued that expands disclosures relating to income taxes.

The expanded disclosures include a tabular income tax rate reconciliation, disclosure of specific reconciliation categories and reconciling items, the amount of income taxes paid by jurisdiction, and other disclosures.

We adopted this standard on December 31, 2025, using a retrospective approach.

The adoption of the new standard results in changes to our income tax disclosures, but did not impact our accounting for income taxes or our financial statement results.

ASU 2024-03, Income Statement Reporting:

Expense Disaggregation Disclosures

In November 2024, a new accounting standard was issued that requires specific disclosures related to certain costs and expenses.

Companies will be required to disclose the amounts of certain cost and expense categories, such as purchases of inventory, employee compensation, depreciation, and amortization, among other disclosures.

The new disclosures may be provided in the notes to the financial statements and will not require changes to the face of the Consolidated Statements of Income.

The standard becomes effective on December 31, 2027, using either a prospective or retrospective approach,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Preferred Stock

At December 31, 2024, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $ 25 , $ 50 , and $ 100 par values, none of which was outstanding.

with early adoption permitted.

The adoption of the new standard will result in disclosure changes, but will not impact our accounting for such costs and expenses or our financial statement results.

We are currently evaluating the transition method and date of adoption we will elect for this new standard.

ASU 2025-03, Business Combinations and Consolidation:

Determining the Accounting Acquirer in the Acquisition of a Variable Interest Entity

In May 2025, a new accounting standard was issued that revises the guidance on identifying the accounting acquirer in a business combination in which the acquiree is a VIE that meets the definition of a business.

Prior to the issuance of the amended guidance, for certain transactions, the primary beneficiary of the VIE was always required to be deemed the acquirer in the transaction.

Under the amended guidance, an entity will now need to complete an assessment of the transaction to determine the acquiring entity and is no longer required to assume that the primary beneficiary is the acquirer in the transaction.

The standard will become effective for us on January 1, 2027, with early adoption permitted.

We expect to adopt this guidance on January 1, 2027, and will apply the guidance prospectively to acquisition transactions occurring on and after the adoption date.

Upon adoption, we do not expect the guidance will have a material impact on our financial statements.

The adoption of this guidance will not impact the APS purchase transactions relating to the Palo Verde sale leaseback VIEs.

ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software:

Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, a new accounting standard was issued that modernizes the accounting for internal-use software costs by removing references to prescriptive and sequential development stages of a project and replacing them with new criteria used in determining when to start capitalizing software costs.

Under the new guidance, capitalization begins when management authorizes and commits to funding the software project and it is probable the project will be completed and used as intended.

When determining if a project is probable of being completed, entities must evaluate whether significant development uncertainty exists, such as unresolved technological innovations or unproven features.

The new guidance also clarifies that capitalized internal-use software costs are subject to the property, plant, and equipment disclosure requirements.

The standard will become effective for us on January 1, 2028, with early adoption permitted.

Entities may adopt the standard using one of the following transition methods:

a prospective approach, a retrospective approach, or a modified transition approach that considers in-process projects at the date of adoption.

We are currently evaluating the impacts on our financial statements of adopting this new standard and the transition method and date of adoption we will elect.

The adoption of this guidance may impact our timing and scope of software costs eligible for capitalization, and may also impact our disclosures relating to software.

ASU 2025-09, Derivatives and Hedging:

Hedge Accounting Improvements

In November 2025, a new accounting standard was issued which clarifies certain aspects of the hedge accounting guidance.

The new standard is intended to better align hedge accounting with the economics of an entity’s risk management activities, and provides entities the ability to apply hedge accounting to an expanded population of economic hedges of forecasted transactions.

The standard will become effective for us on January 1, 2027, applied on a prospective basis.

Early adoption is permitted.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We expect to adopt this guidance on January 1, 2027.

We are not currently applying hedge accounting, and do not expect the adoption of this guidance will have a material impact on our financial statements.

ASU 2025-10, Government Grants:

Accounting for Government Grants Received by Business Entities

In December 2025, a new accounting standard was issued establishing authoritative GAAP guidance on the accounting for government grants received by business entities.

Prior to the issuance of this new standard, GAAP did not include guidance relating to government grants received by business entities.

The new standard is intended to eliminate diversity in practice and improve the financial reporting and consistency across business entities for government grants.

The new standard defines government grants and includes recognition, measurement, presentation, and disclosure requirements.

The new standard includes guidance pertaining to both government grants received relating to an asset and government grants received relating to income.

The guidance includes recognition thresholds based on the probability of compliance with grant conditions and receipt of the grant, among other accounting requirements.

Disclosure requirements include the nature and amounts of government grants received, the conditions attached to the grants, and accounting policies applied.

The new standard will become effective for us on January 1, 2029, with early adoption permitted.

Entities may adopt the standard using various transition methods, including a modified prospective approach, a modified retrospective approach, or a retrospective approach to all government grants.

We are currently evaluating the impacts on our financial statements of adopting this new standard, as well as the date we will adopt this guidance and the transition method we will elect.

Sources of Revenue

The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):

The following table provides detail of Pinnacle West’s consolidated revenues disaggregated by revenue sources (dollars in thousands):

Year Ended December 31,

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Total Operating Revenues $ 5,339,939 $ 5,124,915 $ 4,695,991

Retail Electric Revenue.

All of Pinnacle West’s retail electric revenue is generated by APS.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retail Electric Revenues

All of Pinnacle West’s retail electric revenues are generated by APS.

Retail electric revenue is generated by the sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage.

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See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.

In addition, see the section titled “2025 Rate Case” in Note 8 for details related to proposed adjustments to rate design and modifications of cost allocation methodologies to reduce cross-subsidization by ensuring customers causing production costs are covering those costs through rates.

Wholesale Energy Sales and Transmission Services for Others

All of Pinnacle West’s wholesale energy sales and transmission services for others revenues is generated by APS.

Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers.

These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements.

These activities consist of managing fuel and purchased power risks and transmission needs in connection with the cost of serving our retail customers’ energy requirements.

We may also sell into the wholesale markets generation that is not needed for APS’s retail load.

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Our revenues from contracts with customers for the year ended December 31, 2025, 2024 and 2023 were $ 5,319 million, $ 5,073 million, and $ 4,651 million, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers.

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Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk.

The allowance for doubtful accounts represents our best estimate of customer and other receivables and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk.

The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues.

The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success.

The write-off factor used to estimate uncollectible accounts is based upon consideration of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success.

We continue to monitor the impacts of our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor, and allowance for doubtful accounts.

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Balance at end of period $ 25,495 $ 24,849 $ 22,433

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.

The tax effect of these differences is recorded as deferred taxes.

We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations.

The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, ITC basis adjustment and tax expense of Medicare subsidy.

The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the Statements of Income.

On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $ 23 million of investment tax credits from the BCE Los Alamitos project for $ 21 million.

While the $ 23 million reduced tax payments, the $ 21 million paid to Ameresco is not included in the income taxes paid table below.

See Note 22 for more information about the BCE Sale.

The Company claimed a $ 33.4 million benefit for the Nuclear PTC on its 2024 tax return using a revenue requirement methodology to determine its gross receipts from nuclear sales.

In the continued absence of IRS guidance regarding the definition of gross receipts from nuclear sales, management intends to utilize this same methodology to claim a 2025 credit of $ 39.6 million.

These benefits include the five times multiplier for complying with IRS prevailing wage rules.

However, due to the continued lack of IRS guidance, management believes that there remains uncertainty as to whether the IRS will ultimately agree with the Company’s gross receipts methodology.

As a result, the entire amount of the 2024 and 2025 benefits is recorded as uncertain tax positions and the Company continues to not recognize any income tax benefits related to the Nuclear PTC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net income associated with the Captive and Palo Verde sale leaseback VIEs is not subject to tax.

As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income.

See Note 12 for additional details related to Palo Verde sale leaseback VIEs.

The components of income tax expense are as follows (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

Year Ended December 31, Year Ended December 31,

2025 2024 2023 2025 2024 2023

Federal $ 87,913 $ 137,342 $ 21,272 $ 94,207 $ 165,653 $ 26,405

State 10,892 2,392 2,854 31,424 26,054 1,027

Total current 98,805 139,734 24,126 125,631 191,707 27,432

Federal ( 11,073 ) ( 53,228 ) 37,273 ( 2,902 ) ( 69,075 ) 44,922

State 18,994 24,023 15,513 3,190 4,361 21,830

Total deferred 7,921 ( 29,205 ) 52,786 288 ( 64,714 ) 66,752

Income tax expense

106,726 110,529 76,912 125,919 126,993 94,184

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table compares Pinnacle West Consolidated pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands) and effective tax rates:

Pinnacle West Consolidated

Year Ended December 31,

2025 2024 2023

Amount Percent Amount Percent Amount Percent

Income before income taxes (a) $ 738,369 $ 736,559 $ 595,693

Federal income tax expense at statutory rate 155,057 21.00 % 154,677 21.00 % 125,095 21.00 %

State income tax net of federal income tax benefit (b) 23,610 3.20 % 23,735 3.22 % 17,832 2.99 %

Changes in Valuation Allowance — — % — — % — — %

Nontaxable or Nondeductible Items

Share based compensation ( 4,062 ) ( 0.55 ) % ( 421 ) ( 0.06 ) % 1,346 0.23 %

Palo Verde VIE noncontrolling interest (Note 12)

( 3,173 ) ( 0.43 ) % ( 3,617 ) ( 0.49 ) % ( 3,617 ) ( 0.61 ) %

Other Nontaxable or Nondeductible Items 5,896 0.80 % 3,667 0.50 % 2,405 0.40 %

Effect of changes in tax laws or rates enacted in the current period — — % — — % — — %

Solar or Wind Production Tax Credit ( 14,698 ) ( 1.99 ) % ( 15,206 ) ( 2.07 ) % ( 8,441 ) ( 1.42 ) %

Other Federal Income Tax Credits ( 19 ) — % ( 242 ) ( 0.03 ) % ( 650 ) ( 0.11 ) %

Investment credit amortization – deferral method ( 12,625 ) ( 1.71 ) % ( 9,425 ) ( 1.28 ) % ( 9,495 ) ( 1.59 ) %

Changes in Unrecognized Tax Benefits 1,523 0.21 % ( 28 ) — % ( 1,961 ) ( 0.33 ) %

Effects of Utility Ratemaking

Excess deferred income taxes — Tax Cuts and Jobs Act ( 36,558 ) ( 4.95 ) % ( 36,559 ) ( 4.96 ) % ( 36,558 ) ( 6.14 ) %

Allowance for equity funds used during construction (Note 1)

( 7,005 ) ( 0.95 ) % ( 2,545 ) ( 0.35 ) % ( 5,964 ) ( 1.00 ) %

Other regulatory amortization ( 2,758 ) ( 0.38 ) % ( 1,796 ) ( 0.24 ) % ( 1,828 ) ( 0.31 ) %

Other Adjustments 1,538 0.20 % ( 1,711 ) ( 0.23 ) % ( 1,252 ) ( 0.20 ) %

Income tax expense

$ 106,726 14.45 % $ 110,529 15.01 % $ 76,912 12.91 %

(a) Income before income taxes is from continuing operations and is entirely domestic.

(b) The State of Arizona makes up the majority (greater than 50 percent) of the effect of the state and local income tax category.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table compares APS Consolidated pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands) and effective tax rates:

APS Consolidated

Year Ended December 31,

2025 2024 2023

Amount Percent Amount Percent Amount Percent

Income before income taxes (a) $ 808,346 $ 786,142 $ 658,745

Federal income tax expense at statutory rate 169,753 21.00 % 165,090 21.00 % 138,337 21.00 %

State income tax net of federal income tax benefit (b) 27,345 3.38 % 26,824 3.41 % 21,453 3.26 %

Changes in Valuation Allowance — — % — — % — — %

Nontaxable or Nondeductible Items

Share based compensation ( 2,482 ) ( 0.31 ) % 23 — % 997 0.15 %

Palo Verde VIE noncontrolling interest (Note 12)

( 3,173 ) ( 0.39 ) % ( 3,617 ) ( 0.46 ) % ( 3,617 ) ( 0.55 ) %

Other Nontaxable or Nondeductible Items 1,727 0.21 % 694 0.09 % 263 0.04 %

Effect of changes in tax laws or rates enacted in the current period — — % — — % — — %

Solar or Wind Production Tax Credit ( 11,254 ) ( 1.39 ) % ( 12,110 ) ( 1.54 ) % ( 5,460 ) ( 0.83 ) %

Other Federal Income Tax Credits ( 19 ) — % ( 242 ) ( 0.03 ) % ( 650 ) ( 0.10 ) %

Investment credit amortization – deferral method ( 12,625 ) ( 1.56 ) % ( 9,425 ) ( 1.20 ) % ( 9,495 ) ( 1.44 ) %

Changes in Unrecognized Tax Benefits 1,483 0.18 % ( 107 ) ( 0.01 ) % ( 1,946 ) ( 0.30 ) %

Effects of Utility Ratemaking

Excess deferred income taxes — Tax Cuts and Jobs Act ( 36,558 ) ( 4.52 ) % ( 36,559 ) ( 4.65 ) % ( 36,558 ) ( 5.55 ) %

Allowance for equity funds used during construction (Note 1)

( 7,005 ) ( 0.87 ) % ( 2,545 ) ( 0.32 ) % ( 5,964 ) ( 0.91 ) %

Other regulatory amortization ( 2,758 ) ( 0.34 ) % ( 1,796 ) ( 0.23 ) % ( 1,828 ) ( 0.28 ) %

Other Adjustments 1,485 0.19 % 763 0.09 % ( 1,348 ) ( 0.19 ) %

Income tax expense

$ 125,919 15.58 % $ 126,993 16.15 % $ 94,184 14.30 %

(a) Income before income taxes is from continuing operations and is entirely domestic.

(b) The State of Arizona makes up the majority (greater than 50 percent) of the effect of the state and local income tax category.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the income taxes paid for Pinnacle West and APS on a retrospective basis (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

Year Ended December 31, Year Ended December 31,

2025 2024 2023 2025 2024 2023

Federal $ 20,894 $ 112,870 $ 8,609 $ 30,207 $ 156,112 $ 21,438

State 1,860 128 179 23,431 22,901 296

Total $ 22,754 $ 112,998 $ 8,788 $ 53,638 $ 179,013 $ 21,734

State income taxes paid (net of refunds) exceed 5 percent of total income taxes paid (net of refunds) in the following jurisdictions (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

Year Ended December 31, Year Ended December 31,

2025 2024 2023 2025 2024 2023

Arizona $ 2,000 $ — (a) $ — (a) $ 23,423 $ 22,788 $ — (a)

(a) Jurisdiction below the threshold for the period presented.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

2025 2024 2023 2025 2024 2023

Total unrecognized tax benefits, January 1 $ 44,349 $ 44,274 $ 43,097 $ 44,349 $ 44,274 $ 43,097

Additions for tax positions of the current year 81,286 1,271 1,473 81,286 1,271 1,473

Additions for tax positions of prior years 2,818 2,031 419 2,818 2,031 419

Reductions for tax positions of prior years for:

Changes in judgment ( 2,044 ) ( 2,043 ) 661 ( 2,044 ) ( 2,043 ) 661

Settlements with taxing authorities — — — — — —

Lapses of applicable statute of limitations ( 970 ) ( 1,184 ) ( 1,376 ) ( 970 ) ( 1,184 ) ( 1,376 )

Total unrecognized tax benefits, December 31 $ 125,439 $ 44,349 $ 44,274 $ 125,439 $ 44,349 $ 44,274

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

2025 2024 2023 2025 2024 2023

Tax positions, that if recognized, would decrease our effective tax rate $ 103,785 $ 27,899 $ 28,762 $ 103,785 $ 27,899 $ 28,762

As of December 31, 2025, the tax year ended December 31, 2022 and all subsequent tax years remain subject to examination by the IRS.

With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2021.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.

The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

2025 2024 2023 2025 2024 2023

Unrecognized tax benefit interest expense recognized

$ 3,610 $ 2,743 $ 452 $ 3,610 $ 2,743 $ 452

Following are the total amounts of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

2025 2024 2023 2025 2024 2023

Unrecognized tax benefit interest accrued $ 7,986 $ 4,376 $ 1,633 $ 7,986 $ 4,376 $ 1,633

As of December 31, 2025, we have recognized approximately $ 2.8 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net deferred income tax liability were as follows (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

December 31, December 31,

2025 2024 2025 2024

DEFERRED TAX ASSETS

Risk management activities $ 8,422 $ 14,539 $ 8,422 $ 14,539

Regulatory liabilities:

Excess deferred income taxes — Tax Cuts and Jobs Act 259,000 271,004 259,000 271,004

Asset retirement obligation and removal costs 66,031 81,308 66,031 81,308

Unamortized investment tax credits 81,949 66,327 81,949 66,327

Other postretirement benefits 57,833 58,862 57,833 58,862

Other 50,611 47,671 50,611 47,671

Operating lease liabilities 923,774 400,771 923,479 400,442

Pension liabilities 46,613 39,070 43,422 36,100

Coal reclamation liabilities 39,450 42,391 39,450 42,391

Renewable energy incentives 11,908 14,571 11,908 14,571

Credit and loss carryforwards — 7,682 — —

Employee benefit liabilities 56,447 57,853 55,243 56,561

Other 49,098 44,412 49,098 44,412

Total deferred tax assets 1,651,136 1,146,461 1,646,446 1,134,188

DEFERRED TAX LIABILITIES

Plant-related ( 2,595,668 ) ( 2,562,990 ) ( 2,595,668 ) ( 2,562,990 )

Risk management activities ( 2,072 ) ( 4,089 ) ( 2,072 ) ( 4,089 )

Pension and other postretirement assets ( 97,557 ) ( 83,401 ) ( 96,988 ) ( 82,925 )

Other special use funds ( 58,175 ) ( 55,146 ) ( 58,175 ) ( 55,146 )

Operating lease right-of-use assets ( 923,774 ) ( 400,771 ) ( 923,479 ) ( 400,443 )

Regulatory assets:

Allowance for equity funds used during construction ( 50,402 ) ( 47,694 ) ( 50,402 ) ( 47,694 )

Deferred fuel and purchased power ( 45,504 ) ( 84,393 ) ( 45,504 ) ( 84,393 )

Pension benefits ( 178,736 ) ( 185,641 ) ( 178,736 ) ( 185,641 )

Ocotillo deferral ( 24,703 ) ( 28,372 ) ( 24,703 ) ( 28,372 )

SCR deferral ( 19,080 ) ( 20,548 ) ( 19,080 ) ( 20,548 )

Retired power plant costs ( 13,157 ) ( 16,904 ) ( 13,157 ) ( 16,904 )

Other ( 58,822 ) ( 57,602 ) ( 58,822 ) ( 57,602 )

Other ( 54,418 ) ( 43,383 ) ( 7,425 ) ( 7,378 )

Total deferred tax liabilities ( 4,122,068 ) ( 3,590,934 ) ( 4,074,211 ) ( 3,554,125 )

Deferred income taxes — net $ ( 2,470,932 ) $ ( 2,444,473 ) $ ( 2,427,765 ) $ ( 2,419,937 )

As of December 31, 2025, Pinnacle West consolidated deferred tax assets for credit and loss carryforwards relate to federal credit carryforwards of $ 27.9 million.

Pinnacle West consolidated credit and loss carryforwards amount above has been reduced by $ 27.9 million of unrecognized tax benefits.

As of December 31, 2025, APS consolidated deferred tax assets for credit and loss carryforwards relate to federal credit carryforwards of $ 12.4 million.

APS consolidated credit and loss carryforwards amount above has been reduced by $ 12.4 million of unrecognized tax benefits.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lines of Credit and Short-Term Borrowings

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.

The table below presents the consolidated credit and term loan facilities and the amounts available and outstanding (dollars in thousands):

December 31, 2025 December 31, 2024

Pinnacle West Consolidated APS Consolidated Total Pinnacle West Consolidated APS Consolidated Total

Commitments under Revolving Credit and Term Loan Facilities $ 375,000 $ 1,250,000 $ 1,625,000 $ 400,000 $ 1,650,000 $ 2,050,000

Outstanding short-term borrowings ( 249,700 ) ( 507,305 ) ( 757,005 ) ( 228,550 ) ( 339,900 ) ( 568,450 )

Amount available under Revolving Credit and Term Loan Facilities $ 125,300 $ 742,695 $ 867,995 $ 171,450 $ 1,310,100 $ 1,481,550

Weighted-Average Commitment Fees 0.225 % 0.175 % 0.225 % 0.175 %

Pinnacle West

As of December 31, 2025, Pinnacle West had a $ 200 million revolving credit facility that matures on April 10, 2029.

Pinnacle West has the option to increase the amount of the facility up to a total of $ 300 million upon the satisfaction of certain conditions and with the consent of the lenders.

Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives.

Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility.

The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $ 200 million commercial paper program, for bank borrowings or for issuances of letters of credit.

As of December 31, 2025, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under its credit facility, and $ 75 million of outstanding commercial paper borrowings.

The weighted-average interest rate for the outstanding borrowings on December 31, 2025 was 3.81 %.

On February 18, 2026, Pinnacle West’s revolving credit facility was amended and extended with the following modifications, among others:

(1) increasing the amount of the facility to $ 300 million and maintaining the option to expand it up to a total of $ 400 million, (2) extending the maturity date to February 18, 2031, with two 1-year extension options, (3) eliminating the sustainability-linked pricing metric, and (4) certain modifications to the definition and calculation of indebtedness to exclude (a) PPAs and energy storage leases that are recoverable through the PSA and (b) certain qualified securitization bonds.

Pinnacle West’s commercial paper program was also increased to $ 300 million.

Pinnacle West had an outstanding 364 -day $ 200 million term loan facility that matured on December 4, 2025.

Borrowings under the facility bore interest at SOFR plus 0.95 % per annum.

On December 20, 2024, Pinnacle West drew the full amount of $ 200 million and repaid it on December 4,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2025 using proceeds from a new unsecured 364 -day $ 175 million term loan facility discussed below and commercial paper borrowings.

Pinnacle West has an outstanding 364 -day $ 175 million term loan facility that matures on December 3, 2026.

Borrowings under the facility bear interest at SOFR plus 0.80 % per annum.

On December 3, 2025, Pinnacle West drew the full amount of $ 175 million.

As of December 31, 2025, APS had a $ 1.25 billion revolving credit facility, that matures on April 10, 2029.

APS has the option to increase the amount of the facility to a total of $ 1.65 billion, upon the satisfaction of certain conditions and with the consent of the lenders.

Interest rates are based on APS’s senior unsecured debt credit ratings, and the agreement includes a sustainability-linked pricing metric which provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives.

Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility.

The facility is available to support APS’s general corporate purposes, including support for APS’s $ 1 billion commercial paper program, for bank borrowings or for issuances of letters of credit.

As of December 31, 2025, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $ 507 million of outstanding commercial paper borrowings.

The weighted-average interest rate for the outstanding borrowings on December 31, 2025 was 3.83 %.

On February 18, 2026, APS’s revolving credit facility was amended and extended with the following modifications, among others:

(1) increasing the amount of the facility to $ 1.7 billion and maintaining the option to expand it up to a total of $ 2.1 billion, (2) extending the maturity date to February 18, 2031, with two 1-year extension options, (3) eliminating the sustainability-linked pricing metric, and (4) certain modifications to the definition and calculation of indebtedness to exclude (a) PPAs and energy storage leases that are recoverable through the PSA and (b) certain qualified securitization bonds.

APS’s commercial paper program was also increased to $ 1.5 billion.

On December 5, 2024, APS entered into a $ 400 million 364 -Day Term Loan Agreement that matured on December 4, 2025.

Borrowings under the facility bore interest at SOFR plus 0.90 % per annum.

APS drew the full amount of $ 400 million on April 29, 2025 and repaid it on August 15, 2025 using proceeds from unsecured senior notes issuances.

See “Financial Assurances” in Note 14 for a discussion of other outst anding letters of credit.

Debt Provisions

On December 17, 2024, the ACC issued a financing order that reaffirmed APS’s short-term debt authorization equal to the sum of (i) 7 % of APS’s capitaliza tion, and (ii) $ 500 million (which is required to be used for costs relating to purchases of natural gas and power) and increased the long-term debt limit to $ 9.5 billion and made certain changes to permitted annual equity infusions into APS.

See Note 7 for additional long-term debt provisions.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt and Liquidity Matters

All of Pinnacle West’s and APS’s debt is unsecured.

The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding (dollars in thousands):

Maturity Interest December 31,

Dates (a) Rates 2025 2024

Pollution control bonds:

Variable 2029 (b) $ 163,975 $ 163,975

Total pollution control bonds 163,975 163,975

Senior unsecured notes 2026-2055 2.20 %- 6.88 %

8,030,000 7,380,000

Unamortized discount ( 16,796 ) ( 14,252 )

Unamortized premium 17,144 9,955

Unamortized debt issuance cost ( 54,383 ) ( 48,800 )

Total APS long-term debt 8,139,940 7,490,878

Less current maturities 250,000 300,000

Total APS long-term debt less current maturities 7,889,940 7,190,878

Pinnacle West

Senior unsecured notes 2027-2030 4.75 %- 5.15 %

1,325,000 1,025,000

Floating rate note 2026 (c) 350,000 350,000

Unamortized discount ( 681 ) ( 5 )

Unamortized debt issuance cost ( 8,583 ) ( 7,225 )

Total Pinnacle West long-term debt 1,665,736 1,367,770

Less current maturities 350,000 500,000

Total Pinnacle West long-term debt less current maturities 1,315,736 867,770

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES

$ 9,205,676 $ 8,058,648

(a) This schedule does not reflect the timing of redemptions that may occur prior to scheduled maturity.

(b) The weighted-average interest rate for the variable rate pollution control bonds was 3.52 % at December 31, 2025, and 4.01 % at December 31, 2024.

See additional details below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):

Year Pinnacle West Consolidated APS Consolidated

2026 $ 600,000 $ 250,000

2027 825,000 300,000

2028 400,000 —

2029 568,975 568,975

2030 400,000 —

Thereafter 7,075,000 7,075,000

Total $ 9,868,975 $ 8,193,975

Debt Fair Value

Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy.

The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

As of December 31, 2025 As of December 31, 2024

Amount Fair Value Carrying

Amount Fair Value

Pinnacle West $ 1,665,736 $ 1,731,388 $ 1,367,770 $ 1,393,744

APS 8,139,940 7,433,142 7,490,878 6,525,248

Total $ 9,805,676 $ 9,164,530 $ 8,858,648 $ 7,918,992

Debt and Equity Issuances

Pinnacle West

On February 28, 2024, Pinnacle West entered into equity forward sale agreements (the “February 2024 Forward Sale Agreements”), which may be settled with Pinnacle West common stock or cash.

Pinnacle West also has an ATM Program under which it may offer and sell common stock and enter into forward sale agreements from time to time, subject to market conditions and other factors.

In August 2025, Pinnacle West amended the February 2024 Forward Sale Agreements with Wells Fargo Bank, National Association to extend the maturity date to December 31, 2026.

In September 2025, Pinnacle West partially settled the February 2024 Forward Sale Agreements by issuing 243,186 shares of common stock and receiving net proceeds of $ 15 million.

In December 2025, Pinnacle West partially settled the February 2024 Forward Sale Agreements by issuing 1,193,950 shares of common stock and receiving net proceeds of $ 75 million.

The proceeds from both partial settlements were recorded in equity and were used for general corporate purposes.

See Note 16 for more information on the February 2024 Forward Sale Agreements and the ATM Program.

On May 15, 2025, Pinnacle West issued $ 400 million of 4.90 % senior unsecured notes that mature May 15, 2028 and $ 400 million of 5.15 % senior unsecured notes that mature May 15, 2030.

The net proceeds from the issuances were used to repay $ 500 million of 1.3 % senior unsecured notes that were maturing June 15, 2025 and for general corporate purposes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West also has $ 525 million of 4.75 % Convertible Senior Notes due 2027 (“Convertible Notes”) outstanding, which are senior unsecured obligations of Pinnacle West and will mature on June 15, 2027.

See Note 16 for more information.

On May 15, 2025, Pinnacle West contributed $ 300 million into APS in the form of an equity infusion.

APS used this contribution to repay the $ 300 million of 3.15 % senior notes that matured on the same date.

On December 18, 2025, Pinnacle West contributed $ 75 million into APS in the form of an equity infusion.

APS used this contribution for general corporate purposes.

On August 15, 2025, APS issued $ 700 million of 5.90 % senior unsecured notes that mature August 15, 2055 and reopened its 5.70 % senior unsecured notes that mature August 15, 2034, issuing an additional $ 250 million of such notes.

The net proceeds from the issuances were used to repay the $ 400 million 364 -day Term Loan and for general corporate purposes.

See “Lines of Credit and Short-Term Borrowings” in Note 6 for discussion of Pinnacle West’s and APS’s revolving credit facilities.

See Notes 6 and 14 for discussion of APS’s separate outstanding letters of credit.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.

Pinnacle West and APS comply with these covenants.

For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65 %.

At December 31, 2025, the ratio was approximately 60 % for Pinnacle West and 50 % for APS.

Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.

See further discussion of “cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.

However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

All of Pinnacle West’s and APS’s credit agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment if Pinnacle West or APS were to default under certain other material agreements.

Pinnacle West and APS do not have a material adverse change covenant for credit facility borrowings.

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The ACC has authorized a limit on yearly equity infusions into APS equal to 2.5 % of APS’s total assets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus 50 basis points.

See Note 6 for additional short-term debt provisions.

Regulatory Matters

APS expects to file an application with the ACC for its next general rate case mid-year 2025 and is continuing to evaluate the timing of such filing.

2022 Retail Rate Case

APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates.

On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order (“ROO”) in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”).

The 2022 Rate Case ROO recommended, among other things, (i) a $ 523.1 million increase in the annual base rate revenue requirement, (ii) a 9.55 % return on equity, (iii) a 0.25 % return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.36 %, (v) 12 months of post-

ACC General Retail Rate Cases

2025 Rate Case

On June 13, 2025, APS filed an application with the ACC (the “2025 Rate Case”) seeking a net base rate increase of $ 579.5 million, which represents a 13.99 % net increase.

The requested net increase addresses a total base revenue deficiency of $ 662.4 million, offset by proposed adjustor transfers of cost recovery to base rates.

The 2025 Rate Case application includes the following proposals:

• a test year comprised of the 12-month period ended on December 31, 2024, including certain pro forma adjustments;

• 12 months of post-test year plant placed into service from January 1, 2025 through December 31, 2025;

• an original cost rate base of $ 12.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

• the following proposed capital structure and costs of capital:

Capital Structure Cost of Capital

Long-term debt 47.65 % 4.26 %

Common stock equity 52.35 % 10.70 %

Weighted-average cost of capital 7.63 %

• a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

• a rate of $ 0.043881 per kWh for the portion of APS’s base rates attributable to fuel and purchased power costs;

• adjustments to rate designs, including direct assignment of costs, to reduce cross-subsidization by certain customer classes;

• modification of cost allocation methodologies based on customer growth to ensure customers causing new production costs are covering those costs through rates, along with corresponding changes to adjustor mechanisms, such as for fuel and purchased power;

• implementation of a FRAM to assist with reducing regulatory lag and allow for rate gradualism;

• elimination of the LFCR following the first annual adjustment pursuant to the FRAM;

• modification to the SRB due to the FRAM proposal.

APS requested that the increase become effective in the second half of 2026.

The hearing for this rate case is currently scheduled to begin in May 2026.

APS cannot predict the outcome of its request nor when the 2025 Rate Case will be decided by the ACC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

test year plant and the inclusion of the Four Corners Effluent Limitations Guideline (“ELG”) project, (vi) the approval of APS’s System Reliability Benefit (“SRB”) proposal with certain procedural and other modifications, (vii) no additional Coal Community Transition (“CCT”) funding, (viii) a 5.0 % return on the prepaid pension asset and a return of 5.35 % on the OPEB liability, and (ix) no disallowances on APS’s coal contracts.

The 2022 Rate Case ROO also recommended a number of changes to existing adjustors, including (i) the approval of modified DSM performance incentives and the requested DSM transfer to base rates, (ii) the retention of $ 1.9 million of Renewable Energy Adjustment Charge (“REAC”) in the adjustor rather than base rates, (iii) a partial transfer of $ 27.1 million of LFCR funds to base rates, and (iv) the adoption of an increase in the annual PSA cap to $ 0.006 /kWh.

On February 22, 2024, the ACC approved a number of amendments to the 2022 Rate Case ROO that resulted in, among other things, (i) an approximately $ 491.7 million increase in the annual base revenue requirement, (ii) a 9.55 % return on equity, (iii) a 0.25 % return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39 %, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an all-source request for proposal (“ASRFP”), and (viii) recovery of all DSM costs through the DSM Adjustment Charge (“DSMAC”) rather than through base rates.

The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $ 253.4 million and a roughly 8 % increase to the typical residential customer’s bill.

2022 Rate Case

On October 28, 2022, APS filed an application with the ACC (the “2022 Rate Case”) for an increase in retail base rates, and on January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order (“ROO”), as corrected on February 6, 2024 (the “2022 Rate Case ROO”).

On February 22, 2024, the ACC approved the 2022 Rate Case ROO with certain amendments that resulted in, among other things, (i) an approximately $ 491.7 million increase in the annual base revenue requirement, (ii) a 9.55 % return on equity, (iii) a 0.25 % return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39 %, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an ASRFP, and (viii) recovery of all DSM costs through the DSMAC rather than through base rates.

The ACC issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.

Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the grid access charge (“GAC”) for solar customers, the SRB, and CCT funding.

On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association, Solar Energy Industries Association, and Vote Solar specifically to review whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers.

Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the GAC for solar customers, the SRB, and Coal Community Transition funding.

On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, AriSEIA, SEIA, and Vote Solar specifically to review whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers.

All other applications for rehearing were denied.

3 unchanged sentences

On December 17, 2024, the ACC approved the Limited Rehearing ROO with an amendment that requires APS in its next rate case to propose a revenue allocation based on a site-load cost of service study in order to bring further parity in revenue collection between solar and non-solar customers.

SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the Commission’s December 17, 2024 decision on the rehearing.

The Commission has taken no action on these requests.

In addition, each of these parties have subsequently filed notices of appeal to the Arizona Court of Appeals seeking review of the Commission’s decisions regarding the GAC and on rehearing.

SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the ACC’s December 17, 2024 decision on the rehearing.

The ACC has taken no action on these requests.

In addition, each of these parties have subsequently filed an appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing.

APS cannot predict the outcome of these proceedings.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2019 Retail Rate Case

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates (the “2019 Rate Case”).

On August 2, 2021, an Administrative Law Judge issued a ROO in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021.

On November 2, 2021, the ACC approved the 2019 Rate Case ROO, with various amendments, that resulted in, among other things, (i) a return on equity of 8.70 %, which included a 20 basis points penalty;

(ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners selective catalytic reduction (“SCR”) project, with the exception of $ 215.5 million (see “Four Corners SCR Cost Recovery” below);

(iii) the CCT plan including the following components:

(a) a payment of $ 1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $ 10 million over three years to the Navajo Nation, (c) a payment of $ 0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $ 1.25 million for electrification of homes and businesses on the Hopi reservation, and (e) up to $ 1.25 million for the electrification of homes and businesses on the Navajo Nation reservation;

and (iv) a change in the residential on-peak time-of-use period from 3 p.m.

Monday through Friday, excluding holidays.

The 2019 Rate Case ROO, as amended, resulted in a total annual revenue decrease for APS of $ 4.8 million, excluding temporary payments and expenditures, under the CCT plan.

Consistent with the 2019 Rate Case decision, APS completed the following payments that are being recovered through rates related to the CCT:

(i) $ 10 million to the Navajo Nation;

(ii) $ 0.5 million to the Navajo County communities;

and (iii) $ 1 million to the Hopi Tribe.

Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments:

(i) $ 1.5 million to the Navajo Nation for CCT;

(ii) $ 1.1 million to the Navajo County communities for CCT and economic development;

and (iii) $ 1.25 million to the Hopi Tribe for CCT and economic development.

The ACC also authorized $ 1.25 million to be spent for electrification of homes and businesses on each of the Navajo Nation and Hopi reservations.

Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory.

The census work was completed in November 2022 and disbursement of the funds for electrification of homes and businesses is planned to be finalized after discussions with the Navajo Nation and the Hopi Tribe are completed.

On February 22, 2024, the ACC voted to not approve any further CCT funding.

APS filed a Notice of Direct Appeal to the Arizona Court of Appeals on December 17, 2021 requesting review of certain aspects of the 2019 Rate Case.

On March 6, 2023, the Court issued its opinion in this matter, affirming in part and reversing in part the ACC’s decision in the 2019 Rate Case.

The Court vacated the 20 basis points penalty included in the ACC’s allowed return on equity, as the Court determined the use of customer service metrics to justify the reduction exceeded the ACC’s ratemaking authority.

Additionally, the Court vacated the disallowance of $ 215.5 million of APS’s Four Corners SCR investment.

The Court remanded the issue to the ACC for further proceedings.

On June 14, 2023, APS and the ACC Legal Division filed a joint resolution with the ACC to allow recovery of the $ 215.5 million in costs related to the installation of the Four Corners SCR, a reversal of the 20 basis points reduction to APS’s return on equity from 8.9 % to 8.7 % as a result of the 2019 Rate Case decision, and recovery of $ 59.6 million in revenue lost by APS between December 2021 and June 20, 2023.

On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the Court Resolution Surcharge (“CRS”) mechanism, which became effective on July 1, 2023.

See “Court Resolution Surcharge” below for more information.

Regulatory Lag Docket

2 unchanged sentences

On December 3, 2024, the ACC approved a policy statement regarding formula rate plans.

The policy statement allows regulated utilities to propose formula rate plans in future rate cases.

Proposed plans must be based on a historical test year, include an annual update with a true-up and an earnings test to ensure a utility earns within a 20 basis points band of its authorized return on equity.

Proposed plans should also include an annual meeting and challenge periods for stakeholder feedback.

Utilities that implement formula rates also must file a full rate case at least every five years unless an alternate schedule is set by the ACC.

The policy statement provides regulated utilities with the opportunity to propose formula rate plans in future rate cases.

On March 28, 2025, RUCO, ALCG, and an individual customer

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

filed a lawsuit challenging the ACC’s authority to issue the formula rate policy statement outside of Arizona’s formula rulemaking process.

On June 13, 2025, the lawsuit challenging the ACC’s formula rate policy was dismissed by the Superior Court of Maricopa County.

Following the dismissal, the plaintiffs filed an appeal with the Arizona Court of Appeals as well as a Petition for Special Action with the Arizona Supreme Court.

The Supreme Court declined to exercise jurisdiction on the Petition for Special Action.

The plaintiffs also filed a Petition for Special Action with the Arizona Court of Appeals, which has accepted jurisdiction to determine whether the case should be remanded back to the Superior Court for expedited consideration of the merits.

On November 21, 2025, the Arizona Court of Appeals ruled that the issue should be remanded back to the Superior Court to determine whether the ACC’s formula rate policy must go through a formal rulemaking process.

In response, APS, the ACC, and several other Arizona utility companies filed petitions for review of the Court of Appeals decision with the Arizona Supreme Court, which is pending at this time.

APS cannot predict the outcome of this matter.

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APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.

See “2022 Retail Rate Case” above for modifications of adjustment mechanisms in the 2022 Rate Case.

See “2022 Rate Case” above for modifications of adjustment mechanisms in the 2022 Rate Case and “2025 Rate Case” above for proposed modifications to adjustment mechanisms in the 2025 Rate Case.

Renewable Energy Standard

In 2006, the ACC approved the RES.

Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including, for example, solar, wind, biomass, biogas and geothermal technologies.

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Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its Integrated Resource Plan (“IRP”), and seek cost recovery in a rate process.

Since the adopted clean energy rules differed substantially from the original ROO, supplemental rulemaking procedures were required before the rules could become effective.

On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process.

Instead, the ACC opened a new docket to consider ASRFP requirements and the IRP process.

See “Energy Modernization Plan” below for more information.

On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $ 93.1 million.

APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $ 100.5 million.

This budget included funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $ 20 million to $ 30 million in capital costs for the continuation of the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision.

APS’s budget proposal supported existing approved projects and commitments and requested a waiver of the RES residential and non-residential distributed energy requirements for 2022.

On May 18, 2022, the ACC approved the 2022

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RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the ACC’s consideration at a future date.

As discussed below in “Energy Modernization Plan,” on August 14, 2025, the ACC voted to send a full repeal of the RES rules to the Secretary of State for publication.

APS cannot predict the outcome of this matter, or the impact it may have on the RES surcharge.

On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $ 86.2 million, excluding any funding offsets.

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On November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023.

On June 30, 2023, APS filed its 2024 RES Implementation Plan and proposed a budget of approximately $ 95.1 million.

APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2023.

The ACC has not yet ruled on the 2024 RES Implementation Plan.

APS cannot predict the outcome of this proceeding.

On June 30, 2023, APS filed its 2024 RES Implementation Plan and proposed a budget of approximately $ 95.1 million, excluding any funding offsets.

On July 1, 2024, APS filed its 2025 RES Implementation Plan and proposed a budget of approximately $ 92.7 million.

On July 1, 2025, APS filed its 2026 RES Implementation Plan and proposed a budget of approximately $ 110.1 million, excluding any funding offsets.

The ACC has not yet ruled on the 2025 RES Implementation Plan.

APS cannot predict the outcome of this proceeding.

On June 14, 2021, APS filed an application for approval of its Green Power Partners Program (“GPP”).

On September 1, 2021, the ACC approved the application.

On June 28, 2024, APS filed an application for approval of modifications to the GPP and requested a renewable generation renewable energy credits waiver.

The ACC has not yet ruled on the GPP application.

APS cannot predict the outcome of this proceeding.

The proposed plan also notifies the ACC that continued

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evaluation and approval of the pending 2024 and 2025 RES Implementation Plans is no longer necessary.

On February 4, 2026, the ACC approved APS’s 2026 RES Implementation Plan.

On April 22, 2025, the ACC approved APS’s request to refund uncommitted DSMAC and RES surcharge funds of approximately $ 9 million and $ 43 million, respectively, with final amounts subject to adjustment dependent upon billed usage.

Refunds were issued during July and August of 2025 totaling $ 7.6 million for DSMAC and $ 44.2 million for RES.

APS has a Green Power Partners Program that allows customers to pay a specified price to receive a contracted amount of green power in addition to their normal rate in order to support those customers in meeting their individual sustainability goals.

On June 28, 2024, APS filed an application for approval of modifications to the Green Power Partners Program and requested a renewable energy credit waiver.

On February 4, 2026, the ACC approved APS’s proposed changes to the Green Power Partners Program, including modifications to pricing structures for participating customers.

Demand Side Management Adjustor Charge

The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan annually for review and approval by the ACC.

The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan at least every odd year for review and approval by the ACC.

Verified energy savings from APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards;

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See below for discussion of the LFCR.

On December 17, 2021, APS filed its 2022 D SM Implementation Plan in accordance with an extension granted in 2021.

The 2022 DSM Plan requested a budget of $ 78.4 million and represents an increase of approximately $ 14 million in DSM spending above 2021.

On November 10, 2022, the ACC approved the 2022 DSM Implementation Plan, including a proposed performance incentive.

On June 1, 2022, APS filed its 2023 Transportation Electrification Plan (“2023 TE Plan”).

The 2023 TE Plan detailed APS’s efforts to support transportation electrification in Arizona, including the Take Charge AZ Pilot Program and customer education and outreach related to transportation electrification.

Subsequently, APS filed an amended 2023 TE Plan on November 30, 2022, that included a request for a $ 5 million budget.

On December 12, 2023, the ACC approved the 2023 TE Plan without including the

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Take Charge AZ Program and its budget going forward, but allowed APS to complete projects already underway.

Additionally, the ACC discontinued the residential EV SmartCharger rebate and approved modifications to the EV rate plan.

On November 30, 2022, APS filed its 2023 DSM Implementation Plan, which requested a budget of $ 88 million.

On May 31, 2023, APS filed an amended 2023 DSM Implementation Plan.

The amended plan maintained the originally proposed budget of $ 88 million.

On November 30, 2022 and May 31 2023, APS filed its 2023 DSM Implementation Plan, which requested a budget of $ 88 million, and an amended 2023 DSM Implementation Plan, respectively.

Subsequent to filing the amended 2023 DSM Implementation Plan and prior to the ACC approving it, on November 30, 2023, APS filed its 2024 DSM Implementation Plan.

The 2024 DSM Implementation Plan requested a total budget of $ 91.5 million and incorporated all elements of the amended 2023 DSM Implementation Plan as well as the 2024 TE Implementation Plan.

On April 26, 2024, APS filed an amendment to the 2024 DSM Implementation Plan.

The amended 2024 DSM Implementation Plan includes an updated budget of $ 90.9 million to reflect removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, an update on the performance incentive calculation, and the withdrawal of tranches two and three of the residential battery pilot.

The ACC has not yet ruled on the amended 2024 DSM Implementation Plan.

In a letter filed May 31, 2024, APS said it would not file a 2025 DSM Implementation Plan pending ACC review of the amended 2024 DSM Implementation Plan.

APS cannot predict the outcome of this proceeding.

The 2024 DSM Implementation Plan requested a total budget of $ 91.5 million and incorporated all elements of the amended 2023 DSM Implementation Plan as well as the 2024 Transportation Electrification Implementation Plan.

On April 26, 2024 and June 20, 2025, APS filed amendments to the 2024 DSM Implementation Plan.

The Second Amended 2024 DSM Implementation Plan, compared to the initially filed plan, supported an updated budget of $ 90.9 million, which reflected (i) removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, (ii) exclusion of the proposed tranches two and three of the Residential Battery Pilot, and inclusion of the newly approved Bring-Your-Own-Device Battery (“BYOD”) Pilot described below, and (iii) an update on the performance incentive calculation.

On May 16, 2025, APS filed a request with the ACC to extend the deadline to file its 2026 DSM Implementation Plan until 120 days after the ACC acts on its Second Amended 2024 DSM Implementation Plan.

On July 9, 2025, the ACC approved APS’s extension request.

On December 3, 2025, the ACC voted to reduce the budget of the DSM program to $ 40 million and discontinue several programs and customer rebates while promoting the expansion of Virtual Power Plant programs.

APS will file a compliance plan with the ACC within 120 days of the decision.

On August 30, 2024, APS filed an application for a new BYOD Battery Pilot Plan of Administration with the ACC as required by Decision No.

This plan would allow APS to work with residential customers to enable APS to dispatch participating batteries and use them to provide demand response capacity to the grid.

On March 20, 2025, the ACC approved the BYOD Plan of Administration.

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As discussed above under “RES,” APS refunded uncommitted DSMAC funds during July and August 2025 totaling $ 7.6 million for DSMAC.

As discussed below in “Energy Modernization Plan,” on September 17, 2025, the ACC voted to send a full repeal of the EES rules to the Secretary of State for publication.

APS cannot predict the outcome of this matter, or the impact it may have on the DSMAC.

Power Supply Adjustor Mechanism and Balance

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The PSA is subject to specified parameters and procedures, including the following:

• APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

• APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from Base Fuel Rate;

• an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

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• the PSA rate may not be increased or decreased more than $ 0.006 per kWh in a year without permission of the ACC.

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The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2024 and 2023 (dollars in thousands):

The following table shows the changes in the deferred fuel and purchased power regulatory asset (dollars in thousands):

Year Ended December 31,

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Balance at end of period $ 149,068 $ 287,597

On November 30, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022.

That rate was $ 0.007544 per kWh, which consisted of a forward component of $( 0.004842 ) per kWh and a historical component of $ 0.012386 per kWh.

The 2022 PSA rate was a $ 0.004 per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA.

These rates went into effect as filed on February 1, 2022.

On April 1, 2022, the ACC filed a final report of its third-party audit findings regarding APS’s fuel and purchased power costs for the period January 2019 through January 2021.

The report contained an in-depth review of APS’s fuel and purchased power contracts, its monthly fuel accounting activities, its forecasting and dispatching procedures, and its monthly PSA filings, among other fuel-related activities.

The report found that APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity were reasonable and appropriate.

The report included several recommendations for the ACC’s consideration, including review of current contracts, maintenance schedules, and certain changes and improvements to the schedules in APS’s monthly PSA filings.

On December 27, 2022, ACC Staff filed a proposed order supporting adoption of the recommendations in the third-party audit report, and the ACC approved the proposed order on February 22, 2023.

On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023.

In this filing, APS also requested that one of three different options be adopted to address the growing undercollected PSA balance.

On February 23, 2023, the ACC approved an overall PSA rate of $ 0.019074 per kWh, which consisted of a forward component of $( 0.005527 ) per kWh, a historical component of $ 0.013071 per kWh and a transition component of $ 0.011530 per kWh, that will continue until further notice of the ACC.

The rate became effective with the first billing cycle in March 2023 and is designed to bring the PSA balancing account to near-zero over a 24 -month period.

On November 30, 2023, APS notified the ACC that it will be maintaining the current PSA rate of $ 0.019074 per kWh and an updated PSA adjustment schedule would not be filed at that time.

In Decision No.

79293 in the 2022 Rate Case, the ACC approved a permanent increase in the annual PSA adjustor rate cap from $ 0.004 per kWh to $ 0.006 per kWh and a requirement that APS report to the ACC for possible action when the overall PSA balance reaches $ 100 million.

As part of the 2022 Rate Case decision, the ACC also approved an overall PSA rate of $ 0.011977 per kWh, which consisted of a forward component of $( 0.012624 ) per kWh, a historical component of $ 0.013071 per kWh, and a transition component of $ 0.011530 per kWh.

As part of the 2022 Rate Case decision, the ACC also approved an overall PSA rate of $ 0.011977 per kWh, which consisted of

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a forward component of $( 0.012624 ) per kWh, a historical component of $ 0.013071 per kWh, and a transition component of $ 0.011530 per kWh.

The overall PSA rate was reduced to offset an increase in base fuel prices.

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On November 27, 2024, APS filed its PSA rate for the PSA year beginning February 1, 2025.

The overall PSA rate of $ 0.013977 per kWh consists of a forward component of $( 0.000281 ) per kWh, a

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historical component of $ 0.008728 per kWh, and a transition component of $ 0.005530 .

The overall PSA rate of $ 0.013977 per kWh consists of a forward component of $( 0.000281 ) per kWh, a historical component of $ 0.008728 per kWh, and a transition component of $ 0.005530 per kWh.

This overall PSA rate is an increase of $ 0.002 per kWh over the prior overall rate approved in the 2022 Rate Case decision, and it is below the annual PSA rate increase cap of $ 0.006 per kWh.

On February 5, 2025, the ACC voted to approve this request, with a rate effective date of the first billing cycle in March 2025.

On November 26, 2025, APS filed its PSA rate for the PSA year beginning February 1, 2026.

The overall PSA rate of $ 0.016977 per kWh consists of a forward component of $ 0.012457 per kWh, a historical component of $ 0.00452 per kWh, and a transition component of $ 0.0 per kWh.

This overall PSA rate is an increase of $ 0.003 per kWh over the prior approved rate, and it is below the annual PSA rate increase cap of $ 0.006 per kWh.

The rate became effective the first billing cycle of February 2026.

Environmental Improvement Surcharge

On March 5, 2024, the ACC approved the elimination of the EIS, and the surcharge is no longer in effect.

The EIS permitted APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.

APS’s February 1, 2023, EIS application requested an increase in the charge to $ 14.7 million, or $ 3.3 million over the prior-period charge.

On March 10, 2023, APS filed an amended application requesting an EIS charge of $ 4.0 million, a decrease of $ 10.7 million from the February EIS request, and a decrease of $ 7.5 million from the prior-period charge.

The revised 2023 EIS became effective with the first billing cycle in April 2023;

however, with the elimination of the surcharge, it is no longer in effect, and any remaining amounts are being collected through base rates.

Following the ACC approval to eliminate the Environmental Improvement Surcharge on March 5, 2024, the surcharge is no longer in effect, and any remaining amounts are being collected through base rates.

The Environmental Improvement Surcharge permitted APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.

Transmission Rates, Transmission Cost Adjustor, and Other Transmission Matters

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The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.

Effective June 1, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $ 33 million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula.

Of this net amount, wholesale customer rates decreased by approximately $ 6.4 million and retail customer rates would have decreased by approximately $ 26.6 million.

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $ 2.4 million, resulting in a reduction to the residential rate and increases to commercial rates.

An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022.

Effective June 1, 2023, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $ 34.7 million for the 12-month period beginning June 1, 2023, in accordance with the FERC-approved formula.

Of this net amount, wholesale customer rates increased by approximately $ 20.7 million and retail customer rates would have increased by approximately $ 14 million.

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $ 10 million, resulting in reductions to the residential

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $ 10 million, resulting in reductions to the residential and commercial rates.

An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2023.

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and commercial rates.

Effective June 1, 2024, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $ 27.4 million for the 12-month period beginning June 1, 2024 in accordance with the FERC-approved formula.

Of this net amount, wholesale customer rates increased by approximately $ 16.6 million and retail customer rates would have increased by approximately $ 10.8 million.

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement increased by $ 8.8 million, resulting in an increase to residential rates and commercial rates over 3 MW and a decrease to commercial rates less than or equal to 3 MW.

An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2024.

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Of this net amount, wholesale customer rates increased by approximately $ 4.6 million and retail customer rates would have increased by approximately $ 114.4 million.

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement increased by $ 8.8 million, resulting in an increase to residential and commercial rates over 3 MW and a decrease to commercial rates less than or equal to 3 MW.

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement increased by $ 88.3 million, resulting in increases to both residential and commercial rates.

An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2025.

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DG sales losses are determined from the metered output from the DG units.

On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $ 59.1 million (a $ 32.5 million increase from previous levels, which was inclusive of a $ 11.8 million balance from APS’s 2021 LFCR filing).

On May 9, 2022, the ACC Staff filed its revised report and proposed order regarding APS’s 2022 LFCR adjustment, concluding that APS calculated the adjustment in accordance with its Plan of Administration.

On May 18, 2022, the ACC approved the 2022 LFCR adjustment, with a rate effective date of June 1, 2022.

On February 15, 2023, APS filed a letter to the ACC docket stating that, in accordance with Decision No.

78585, APS and ACC Staff have agreed to move the filing date for the annual LFCR adjustment to July 31 each year.

On September 5, 2023, APS filed an updated LFCR Plan of Administration, which was approved by ACC Staff on December 8, 2023.

On July 31, 2023, APS filed its 2023 annual LFCR adjustment, requesting that the annual LFCR recovery amount be increased to $ 68.7 million (a $ 9.6 million increase from previous levels).

On October 19, 2023, a request for intervention was filed, which was granted.

Consistent with an October 25, 2023, Procedural Order, the parties met and conferred and conducted limited discovery.

As a result of Decision No.

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The ACC approved the revised Plan of Administration on October 8, 2024.

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On July 31, 2024, APS filed its 2024 annual LFCR adjustment, requesting that effective November 1, 2024, the annual LFCR recovery amount be increased to $ 49.6 million (an $ 8 million increase from previous levels).

On December 3, 2024, the ACC approved the 2024 annual LFCR adjustment, with new rates effective in the first billing cycle of January 2025.

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On July 31, 2025, APS filed its 2025 annual LFCR adjustment, requesting that effective

November 1, 2025, the annual LFCR recovery amount be increased to $ 60.1 million (a $ 10.5 million increase from previous levels).

On November 21, 2025, the ACC approved the 2025 annual LFCR adjustment, with new rates effective in the first billing cycle of December 2025.

Tax Expense Adjustor Mechanism

The TEAM helps address potential federal income tax reform and enable the pass-through of certain income tax effects to customers.

The TEAM helps address potential federal income tax reform and enables the pass-through of certain income tax effects to customers.

The TEAM expressly applies to APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs.

As part of the 2019 Rate Case decision, there remains small true up balances in the TEAM balancing account.

In the 2022 Rate Case, these true up balances are being recovered and amortized through 2032.

Currently, the TEAM is set to a zero rate as per ACC Decision No.

Court Resolution Surcharge

The CRS mechanism permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of SCR technology for Four Corners Units 4 and 5 and a change in APS’s allowable return on equity as required by the Arizona Court of Appeals and approved by the ACC in Decision No.

Following an appeal of the 2019 Rate Case decision, the ACC approved a Court Resolution Surcharge (“CRS”) mechanism that permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of selective catalytic reduction (“SCR”) technology for Four Corners Units 4 and 5 and a change in APS’s allowable return on equity as required by the Arizona Court of Appeals and approved by the ACC in Decision No.

The CRS went into effect on July 1, 2023, at a rate of $ 0.00175 per kWh.

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79293 in the 2022 Rate Case.

See “2019 Retail Rate Case” above for more information.

The ACC’s decision from APS’s 2017 rate case (the “2017 Rate Case Decision”) provides that payments by utilities for energy exported to the grid from residential DG solar facilities will be determined using a Resource Comparison Proxy (“RCP”) methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket.

RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar photovoltaic projects.

Solar Export Price

Payments by APS for energy exported to the grid from residential DG solar facilities are determined using a Resource Comparison Proxy (“RCP”) methodology as determined in the ACC’s generic Value and Cost of DG docket.

The RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar photovoltaic projects.

The price established by this RCP method is updated annually (between general retail rate cases) but cannot be decreased by more than 10 % per year.

On April 29, 2022, APS filed an application to decrease the RCP price from 9.4 cents per kWh, which had been in effect since October 1, 2021, to 8.46 cents per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2022.

On July 12, 2022, the ACC approved the RCP as filed.

On May 1, 2023, APS filed an application for revisions to the RCP.

This application would decrease the RCP price to 7.619 cents per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2023.

This application would decrease the RCP price to $ 0.07619 per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2023.

On August 25, 2023, the ACC approved the RCP as filed.

On May 1, 2024, APS filed an application for revisions to the RCP.

This application would decrease the RCP price to 6.857 cents per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2024.

This application would decrease the RCP price to $ 0.06857 per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2024.

On August 13, 2024, the ACC approved the RCP as filed.

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On October 11, 2023, the ACC voted to open a new general docket to hold a hearing to explore potential future changes to the 10 % annual reduction cap in the solar export rate paid by utilities to distributed solar customers for exports to the grid and the 10 -year rate lock period for those customers that were approved in the ACC’s Value and Cost of Distributed Generation Docket.

A procedural conference was held on November 1, 2023, to discuss the process going forward.

As a result of the procedural conference, ACC Staff issued a request for information to investigate the issues related to this matter.

A status conference was held on March 20, 2024 to determine if ACC Staff is prepared to present a recommendation on this matter at that time.

Stakeholders provided responses to the ACC Staff’s request for information on March 21, 2024.

Another status conference took place on May 20, 2024 and ACC Staff issued a request for additional information to investigate the issues related to the matter on May 31, 2024.

Stakeholders provided responses to the ACC Staff’s request for additional information on July 1, 2024, and on October 15, 2024, the ACC Staff filed a report finding that the RCP is working as intended and recommending no changes to the RCP at this time.

The ACC Staff also recommended that the ACC close the docket without a hearing or further action.

The ACC has not yet acted on the ACC Staff’s recommendation, and APS cannot predict the outcome of this matter.

On May 1, 2025, APS filed an application for revisions to the RCP.

This application would decrease the RCP price to $ 0.06171 per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2025.

On August 14, 2025, the ACC approved the RCP as filed.

Following various conferences, the ACC Staff filed a report finding that the RCP is working as intended and recommending no changes at this time along with closure of the docket.

On October 6, 2025, the ACC administratively closed the general docket, and APS expects no additional action in this matter.

Energy Modernization Plan

On May 26, 2023, the ACC opened a new docket to review articles within the Arizona Administrative Code related to Resource Planning, the Renewable Energy Standard and Tariff, and Electric Energy Efficiency Standards.

On January 9, 2024, the ACC approved a rulemaking process for this matter.

During the ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current Electric Energy Efficiency and Renewable Energy Standard rules during the rulemaking process.

On August 21, 2024, the ACC Staff filed separate reports for each set of rules, including its recommendations to repeal the Electric Energy Efficiency and Renewable Energy Standard rules along with required preliminary economic, small business, and consumer impact statements.

On May 26, 2023, the ACC opened a new docket to review the Arizona Administrative Code related to Resource Planning, the RES, and EES.

On January 9, 2024, the ACC approved the opening of new dockets to begin rulemaking process for EES and RES.

It was also ordered that an existing rulemaking docket would be utilized to review proposed updates to the ASRFP and Resource Planning Rules.

During an ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current EES and RES rules during the rulemaking process.

On August 21, 2024, the ACC Staff filed separate reports for each set of rules, including its recommendations to repeal the EES and RES rules along with required preliminary economic, small business, and consumer impact statements.

APS and other interested parties have filed comments about the ACC Staff reports.

APS cannot predict the outcome of this matter.

Integrated Resource Planning

The ACC voted to send to the Secretary of State full repeals of the RES and EES rules on August 14, 2025 and September 17, 2025, respectively, for publication and to begin the public rulemaking process.

APS cannot predict the outcome of these matters, or the impacts they may have on the RES or DSM surcharges discussed above.

Integrated Resource Plan

ACC rules require utilities to develop triennial 15-year IRPs which describe how the utility plans to serve customer load in the plan time frame.

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On July 31, 2024, the ACC held an IRP workshop where utilities and stakeholders presented on the 2023 IRPs.

On October 8, 2024, the ACC acknowledged APS’s 2023 IRP and approved certain amendments to the IRP process, including requirements for APS to demonstrate resource adequacy prior to exiting Four Corners as well as analysis of impacts from western market participation and planned resource requirements in the next IRP.

See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

On October 8, 2024, the ACC acknowledged APS’s 2023 IRP and approved certain amendments to the IRP process, including requirements for APS to demonstrate system resource

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Equity Infusions

On October 27, 2023, APS filed a notice of intent to increase Pinnacle West’s equity in APS in 2024.

APS sought approval to receive from Pinnacle West in 2024 up to $ 500 million in additional equity infusions above the previously authorized limit of $ 150 million annually.

The ACC approved the increased equity infusion limit for 2024 on January 9, 2024.

On April 19, 2024, APS submitted a request to the ACC to permanently modify Pinnacle West’s permitted yearly equity infusions to equal up to 2.5 % of APS’s consolidated assets each calendar year on a three-year rolling average basis.

On December 17, 2024, the ACC issued a financing order that approved an annual equity infusion allowance of 2.5 % of APS’s consolidated assets on a three-year rolling average basis.

Public Utility Regulatory Policies Act

Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens.

On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona and established that the rate paid to qualifying facilities must be based on the long-term avoided cost.

“Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis.

adequacy as well as analysis of impacts from western market participation and planned resource requirements in the next IRP, which is due to be filed on August 3, 2026.

Residential Electric Utility Customer Service Disconnections

In accordance with the ACC’s service disconnection rules, APS uses a calendar-based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”).

Since the Annual Disconnection Moratorium began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts.

Pursuant to an ACC order, customers with past due balances of $ 75 or greater as of approximately one month prior to the end of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements.

In addition, APS voluntarily began waiving late payment fees of its customers (“Late Fee Waivers”) on March 13, 2020.

Effective February 1, 2023, late payment fees for residential customers were reinstated.

Late payment fees for commercial and industrial customers were reinstated effective May 1, 2022.

Since the suspensions and moratoriums on disconnections began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.

On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules.

On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules.

On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules.

During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken.

In April 2022, the Arizona Legislature passed, and the Governor signed a bill that repealed the electric deregulation law that

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

had been in place in Arizona since 1998.

On August 27, 2024, the ACC administratively closed this docket due to inactivity and obsolescence.

Four Corners SCR Cost Recovery

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.

APS filed the SCR Adjustment request in April 2018.

The SCR Adjustment request provided that there would be a $ 67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers.

Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019.

The hearing for this matter occurred in September 2018.

At the hearing, APS accepted ACC Staff’s recommendation of a lower annual revenue impact of approximately $ 58.5 million.

The Administrative Law Judge issued a ROO finding that the costs for the SCR project were prudently incurred and recommending authorization of the $ 58.5 million annual revenue requirement related to the installation and operation of the SCRs.

The ACC did not issue a decision on this matter.

APS included the costs for the SCR project in the retail rate base in its 2019 Rate Case filing with the ACC.

On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $ 194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031.

The decision also included a partial and combined disallowance of $ 215.5 million on the SCR investments and deferrals.

APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $ 215.5 million disallowance.

The Arizona Court of Appeals heard oral arguments on November 30, 2022.

On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals.

On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs.

See above for further discussion on the 2019 Rate Case decision.

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules.

Cholla Power Plant

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules.

On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit.

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In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020, and the unit ceased operation in December 2020.

APS is required to cease burning coal at its remaining Cholla units by April 2025.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033.

APS has been recovering a return on and of the net book value of the unit in base rates.

APS is allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $ 28.1 million as

APS was required to cease burning coal at its remaining Cholla units by April 2025.

On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and decommissioning and site remediation costs of Cholla Units 1 and 3 related to the cessation of coal-burning operations at Cholla in April 2025.

This order would authorize APS to defer for future recovery in rates the expenses necessary to cease operating coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, CCR corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025.

On July 8, 2025, APS withdrew its deferral application, requesting that the costs that would have been covered in the deferral order request instead be addressed in the 2025 Rate Case.

APS cannot predict the outcome of this matter.

APS ceased coal-burning operations at Cholla in March 2025 and formally retired Cholla Units 1 and 3 on April 30, 2025.

Upon the cessation of coal-fired operations, APS had approximately $ 81 million of remaining net-book value associated with Units 1 and 3 plant assets.

APS is currently recovering in rates a return on the net-book value of its interest in Cholla and associated depreciation costs.

In the 2025 Rate Case, APS has requested recovery in rates of the ongoing environmental remediation and CCR closure costs associated with Cholla and any remaining unrecovered plant costs.

The 2025 Rate Case also includes a request for an ongoing deferral order relating to anticipated increased environmental remediation costs relating to Cholla that may be incurred after the 2025 Rate Case proceeding.

For Cholla Unit 2, APS has been allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, totaling $ 23.6 million as of December 31, 2025, in addition to a return on its investment.

I n the third quarter of 2014, Unit 2’s remaining net book

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of December 31, 2024, in addition to a return on its investment.

In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset.

value was reclassified from property, plant and equipment to regulatory assets.

In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.

On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and closure costs of the remaining Cholla units.

This order would authorize APS to defer, for future recovery in rates, both the expenses necessary to close and decommission coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, CCR corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025.

APS cannot predict the outcome of this matter.

The Navajo Plant ceased operations in November 2019.

The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased operations.

In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset.

In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to regulatory assets.

APS has been recovering a return on and of the net book value of its interest in the Navajo plant in base rates over its previously estimated life through 2026.

4 unchanged sentences

On August 14, 2024, APS filed a request with the ACC for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs.

APS cannot predict the outcome of this matter.

On June 18, 2025, the ACC denied APS’s request and recommended that wildfire related expenses be recovered in APS’s 2025 Rate Case.

On May 12, 2025, Arizona Governor Hobbs signed into law a bill that requires Arizona electric utilities to develop and seek approval for wildfire mitigation plans and defines the standard of care with respect to wildfire-related claims by reference to such plans.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 unchanged sentence

The detail of regulatory assets is as follows (dollars in thousands):

Amortization Through 2024 2023

Amortization Through December 31,

2025 December 31,

Pension (a) $ 723,042 $ 750,976

Income taxes — AFUDC equity 2054 203,890 192,936

Palo Verde sale leaseback noncontrolling interests’ acquisition (b) N/A 151,506 —

Deferred fuel and purchased power (c) (d) 2026 149,068 287,597

Ocotillo deferral 2034 99,931 114,775

SCR deferral (e) 2038 83,123 89,477

Lease incentives (g) 70,541 46,615

Lease incentive (Note 20)

2045 90,005 70,541

Retired power plant costs 2031 56,809 68,380

Income taxes — investment tax credit basis adjustment (Note 5)

2056 42,459 34,834

Deferred compensation 2036 32,204 33,108

Deferred fuel and purchased power — mark-to-market (Note 13)

1 unchanged sentence

FERC transmission true up 2027 21,471 35,159

Income taxes — investment tax credit basis adjustment 2056 34,834 34,230

Deferred compensation 2036 33,108 33,972

Deferred property taxes 2027 15,349 23,918

1 unchanged sentence

2046 8,582 20,611

Power supply adjustor - interest 2025 11,525 19,416

Active Union Medical Trust (f) 9,673 12,747

Mead-Phoenix transmission line contributions in aid of construction (“CIAC”) 2050 8,384 8,716

Navajo coal reclamation 2026 7,905 10,883

Mead-Phoenix transmission line — contributions in aid of construction 2050 8,052 8,384

PSA - interest 2026 5,679 11,525

Loss on reacquired debt 2038 5,653 6,682

Tax expense adjustor mechanism (b) 2031 4,534 5,190

Four Corners cost deferral 2024 — 7,922

Active union medical trust (e) 3,696 9,673

Navajo coal reclamation 2026 2,516 7,905

Other Various 3,353 3,522

Total regulatory assets (d) $ 1,810,458 $ 2,016,036

Total regulatory assets (f) $ 1,749,366 $ 1,810,458

current regulatory assets $ 286,009 $ 420,969

1 unchanged sentence

(a) This asset represents the future recovery of pension benefit obligations and expense through retail rates.

If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.

As a result of the 2019 Rate Case decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates.

If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income/loss and result in lower future revenues.

The 2022 Rate Case decision allows for the full return on the pension asset in rate base.

See Note 9 for further discussion.

(b) See “Cost Recovery Mechanisms” discussion above.

(d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.

FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

(e) See “Four Corners SCR Cost Recovery” discussion above.

(f) Collected in retail rates.

(g) Amortization periods vary based on specific terms of lease contract.

(b) This asset relates to the acquisition of previously leased interest in Palo Verde Unit 2.

(d) Subject to a carrying charge.

(e) Collected in retail rates.

(f) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.

FERC rates are set using a formula rate as described in “Transmission Rates, TCA, and Other Transmission Matters.”

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The detail of regulatory liabilities is as follows (dollars in thousands):

Amortization Through 2024 2023

Amortization Through December 31,

2025 December 31,

Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a) 2046 $ 847,572 $ 888,896

Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a) 2058 200,161 207,400

Asset retirement obligations and removal costs (d) 358,403 486,751

AROs and removal costs (b) 286,907 358,403

Other postretirement benefits (c) 233,952 238,113

Four Corners coal reclamation 2038 97,988 77,532

Renewable energy standard (b) 2025 68,523 60,667

Income taxes — deferred investment tax credit 2056 81,949 66,327

Income taxes — change in rates 2054 56,260 59,133

Spent nuclear fuel 2027 26,818 33,154

Demand side management (b) 2025 23,927 14,374

RES (d) 2026 54,551 68,523

DSM (d) 2025 26,228 23,927

Sundance maintenance 2031 25,668 23,086

TCA Balancing Account (b) 2026 14,834 3,425

Property tax deferral 2027 4,785 10,850

Tax expense adjustor mechanism (b) 2032 4,343 4,835

Spent nuclear fuel 2027 20,492 26,818

TCA Balancing Account (d) 2027 4,860 14,834

TEAM (d) 2032 3,738 4,343

Deferred fuel and purchased power — mark-to-market (Note 13)

Other Various 3,063 4,898

2 unchanged sentences

Total non-current regulatory liabilities $ 1,736,121 $ 1,855,278

(a) For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.

(b) See “Cost Recovery Mechanisms” discussion above.

(a) For purposes of presentation on the Statements of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.

(b) In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.

(d) In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.

The tax effect of these differences is recorded as deferred taxes.

We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations.

The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.

The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $ 23 million of investment tax credits from the BCE Los Alamitos project for $ 21 million.

See Note 20 for more information about the BCE Sale.

As a part of the Inflation Reduction Act of 2022 (“IRA”), a new PTC for nuclear energy produced by existing nuclear energy plants (“Nuclear PTC”) was enacted.

Energy produced and sold by APS from Palo Verde between 2024 and 2032 is eligible for this credit subject to a credit phase out based upon APS’s gross receipts from nuclear sales.

The Company continues to await guidance from the U.S.

Treasury Department related to the definition of “gross receipts from nuclear sales” for purposes of the credit phase-out.

Without such guidance, the Company is unable to accurately determine the benefit the Nuclear PTC may provide.

Due to the lack of guidance, no income tax benefits have been recognized related to the Nuclear PTC as of December 31, 2024.

Net income associated with the Captive and Palo Verde sale leaseback VIEs is not subject to tax.

As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income.

See Note 17 for additional details related to Palo Verde sale leaseback VIEs.

Pinnacle West Consolidated APS Consolidated

2024 2023 2022 2024 2023 2022

Total unrecognized tax benefits, January 1 $ 44,274 $ 43,097 $ 45,086 $ 44,274 $ 43,097 $ 45,086

Additions for tax positions of the current year 1,271 1,473 1,399 1,271 1,473 1,399

Additions for tax positions of prior years 2,031 419 2,069 2,031 419 2,069

Reductions for tax positions of prior years for:

Changes in judgment ( 2,043 ) 661 ( 3,495 ) ( 2,043 ) 661 ( 3,495 )

Settlements with taxing authorities — — — — — —

Lapses of applicable statute of limitations ( 1,184 ) ( 1,376 ) ( 1,962 ) ( 1,184 ) ( 1,376 ) ( 1,962 )

Total unrecognized tax benefits, December 31 $ 44,349 $ 44,274 $ 43,097 $ 44,349 $ 44,274 $ 43,097

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

2024 2023 2022 2024 2023 2022

Tax positions, that if recognized, would decrease our effective tax rate $ 27,899 $ 28,762 $ 28,246 $ 27,899 $ 28,762 $ 28,246

As of the balance sheet date, the tax year ended December 31, 2021, and all subsequent tax years remain subject to examination by the IRS.

With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2020.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.

The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

2024 2023 2022 2024 2023 2022

Unrecognized tax benefit interest expense/(benefit) recognized

$ 2,743 $ 452 $ ( 139 ) $ 2,743 $ 452 $ ( 139 )

Pinnacle West Consolidated APS Consolidated

2024 2023 2022 2024 2023 2022

Unrecognized tax benefit interest accrued $ 4,376 $ 1,633 $ 1,181 $ 4,376 $ 1,633 $ 1,181

Additionally, as of December 31, 2024, we have recognized approximately $ 2.1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of income tax expense are as follows (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

Year Ended December 31, Year Ended December 31,

2024 2023 2022 2024 2023 2022

Federal $ 137,342 $ 21,272 $ 35,617 $ 165,653 $ 26,405 $ 103,349

State 2,392 2,854 1,950 26,054 1,027 161

Total current 139,734 24,126 37,567 191,707 27,432 103,510

Federal ( 53,228 ) 37,273 23,693 ( 69,075 ) 44,922 ( 31,860 )

State 24,023 15,513 13,567 4,361 21,830 19,150

Total deferred ( 29,205 ) 52,786 37,260 ( 64,714 ) 66,752 ( 12,710 )

Income tax expense/(benefit) $ 110,529 $ 76,912 $ 74,827 $ 126,993 $ 94,184 $ 90,800

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

Year Ended December 31, Year Ended December 31,

2024 2023 2022 2024 2023 2022

Federal income tax expense at statutory rate $ 154,677 $ 125,095 $ 120,887 $ 165,090 $ 138,337 $ 132,920

Increases (reductions) in tax expense resulting from:

State income tax net of federal income tax benefit 24,218 18,024 17,740 25,639 19,832 19,000

State income tax credits net of federal income tax benefit ( 3,349 ) ( 3,513 ) ( 5,482 ) ( 1,611 ) ( 1,775 ) ( 3,744 )

Excess deferred income taxes — Tax Cuts and Jobs Act ( 36,559 ) ( 36,558 ) ( 36,241 ) ( 36,559 ) ( 36,558 ) ( 36,241 )

Allowance for equity funds used during construction (Note 1)

( 2,545 ) ( 5,964 ) ( 4,629 ) ( 2,545 ) ( 5,964 ) ( 4,629 )

Palo Verde VIE noncontrolling interest (Note 17)

( 3,617 ) ( 3,617 ) ( 3,617 ) ( 3,617 ) ( 3,617 ) ( 3,617 )

Investment tax credit amortization ( 9,425 ) ( 9,495 ) ( 5,608 ) ( 9,425 ) ( 9,495 ) ( 5,608 )

Federal production tax credit ( 15,206 ) ( 8,441 ) ( 3,146 ) ( 12,110 ) ( 5,460 ) —

Other federal income tax credits ( 3,881 ) ( 3,453 ) ( 7,721 ) ( 1,551 ) ( 2,803 ) ( 7,721 )

Other 6,216 4,834 2,644 3,682 1,687 440

Income tax expense/(benefit) $ 110,529 $ 76,912 $ 74,827 $ 126,993 $ 94,184 $ 90,800

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net deferred income tax liability were as follows (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

December 31, December 31,

2024 2023 2024 2023

DEFERRED TAX ASSETS

Risk management activities $ 14,539 $ 31,411 $ 14,539 $ 31,411

Regulatory liabilities:

Excess deferred income taxes — Tax Cuts and Jobs Act 271,004 283,161 271,004 283,161

Asset retirement obligation and removal costs 81,308 113,312 81,308 113,312

Unamortized investment tax credits 66,327 68,521 66,327 68,521

Other postretirement benefits 58,862 56,070 58,862 56,070

Other 47,671 39,857 47,671 39,857

Operating lease liabilities 400,771 316,067 400,442 315,670

Pension liabilities 39,070 33,294 36,100 29,918

Coal reclamation liabilities 42,391 45,505 42,391 45,505

Renewable energy incentives 14,571 17,261 14,571 17,261

Credit and loss carryforwards 7,682 43,940 — 3,031

Employee benefit liabilities 57,853 49,222 56,561 48,551

Other 44,412 28,643 44,412 29,314

Total deferred tax assets 1,146,461 1,126,264 1,134,188 1,081,582

DEFERRED TAX LIABILITIES

Plant-related ( 2,562,990 ) ( 2,572,495 ) ( 2,562,990 ) ( 2,572,495 )

Risk management activities ( 4,089 ) ( 1,682 ) ( 4,089 ) ( 1,682 )

Pension and other postretirement assets ( 83,401 ) ( 78,853 ) ( 82,925 ) ( 78,297 )

Other special use funds ( 55,146 ) ( 56,550 ) ( 55,146 ) ( 56,550 )

Operating lease right-of-use assets ( 400,771 ) ( 316,067 ) ( 400,443 ) ( 315,670 )

Regulatory assets:

Allowance for equity funds used during construction ( 47,694 ) ( 46,754 ) ( 47,694 ) ( 46,754 )

Deferred fuel and purchased power ( 84,393 ) ( 149,078 ) ( 84,393 ) ( 149,078 )

Pension benefits ( 185,641 ) ( 172,239 ) ( 185,641 ) ( 172,239 )

Ocotillo deferral ( 28,372 ) ( 31,812 ) ( 28,372 ) ( 31,812 )

SCR deferral ( 20,548 ) ( 22,128 ) ( 20,548 ) ( 22,128 )

Retired power plant costs ( 16,904 ) ( 20,659 ) ( 16,904 ) ( 20,659 )

Other ( 57,602 ) ( 38,320 ) ( 57,602 ) ( 38,320 )

Other ( 43,383 ) ( 36,107 ) ( 7,378 ) ( 7,595 )

Total deferred tax liabilities ( 3,590,934 ) ( 3,542,744 ) ( 3,554,125 ) ( 3,513,279 )

Deferred income taxes — net $ ( 2,444,473 ) $ ( 2,416,480 ) $ ( 2,419,937 ) $ ( 2,431,697 )

As of December 31, 2024, Pinnacle West consolidated deferred tax assets for credit and loss carryforwards relate to federal and state credit carryforwards, net of federal benefit, of $ 12 million, which first begin to expire in 2029.

Pinnacle West consolidated credit and loss carryforwards amount above has been reduced by $ 4 million of unrecognized tax benefits.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2024, APS consolidated does not have any deferred tax assets for credit and loss carryforwards relating to federal or state carryforwards due to APS utilizing all available federal and state credits in 2024.

Lines of Credit and Short-Term Borrowings

The table below presents the consolidated credit and term loan facilities and the amounts available and outstanding (dollars in thousands):

December 31, 2024 December 31, 2023

Pinnacle West APS Total Pinnacle West APS Total

Commitments under Credit and Term Loan Facilities $ 400,000 $ 1,650,000 $ 2,050,000 $ 200,000 $ 1,250,000 $ 1,450,000

Outstanding short-term borrowings ( 228,550 ) ( 339,900 ) ( 568,450 ) ( 76,650 ) ( 532,850 ) ( 609,500 )

Amount of Credit and Term Loan Facilities Available $ 171,450 $ 1,310,100 $ 1,481,550 $ 123,350 $ 717,150 $ 840,500

Weighted-Average Commitment Fees 0.225 % 0.175 % 0.170 % 0.120 %

Pinnacle West

On August 2, 2024, Pinnacle West amended its $ 200 million revolving credit facility, extending the maturity date from April 10, 2028 to April 10, 2029, and providing a mechanism to either update the Sustainability Table (as defined in the Pinnacle West revolving credit facility), which provides for a sustainability-linked pricing feature, or, in certain circumstances, terminate the sustainability-linked pricing feature for the final year.

Pinnacle West has the option to increase the amount of the facility up to a total of $ 300 million upon the satisfaction of certain conditions and with the consent of the lenders.

Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives.

At December 31, 2024, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under its credit facility, and $ 29 million of outstanding commercial paper borrowings.

The weighted-average interest rate for the outstanding borrowings on December 31, 2024, was 4.58 %.

On December 5, 2024, Pinnacle West entered into an agreement with a new 364 -day $ 200 million term loan facility that matures on December 4, 2025.

Borrowings under the facility bear interest at SOFR plus 0.95 % per annum.

On December 20, 2024, Pinnacle West drew the full amount of $ 200 million.

On December 20, 2024, Pinnacle West repaid $ 200 million of the Pinnacle West term loan which matured in December 2024.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On August 2, 2024, APS amended its $ 1.25 billion revolving credit facility, extending the maturity date from April 10, 2028 to April 10, 2029, and providing a mechanism to either update the Sustainability Table (as defined in the APS revolving credit facility), which provides for a sustainability-linked pricing feature, or, in certain circumstances, terminate the sustainability-linked pricing feature for the final year.

APS has the option to increase the amount of the facility by up to a maximum of $ 400 million , for a total of $ 1.65 billion, upon the satisfaction of certain conditions and with the consent of the lenders.

Interest rates are based on APS’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives.

The facility is available to support APS’s general corporate purposes, including support for APS’s commercial paper program, which was incr eased from $ 750 million to $ 1 billion on April 10, 2023, for bank borrowings or for issuances of letters of credit.

At December 31, 2024, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $ 340 million of outstanding commercial paper borrowings.

The weighted-average interest rate for the outstanding borrowings on December 31, 2024, was 4.62 %.

On December 12, 2023, APS entered into an agreement for a new 364 -day $ 350 million term loan facility that matured on December 10, 2024.

Borrowings under the facility boar interest at SOFR plus 1.0 % per annum.

On February 9, 2024, APS drew the full amount of $ 350 million, which APS subsequently paid off in full on June 10, 2024.

On December 5, 2024, APS entered into a $ 400 million 364 -Day Term Loan Agreement that matures on December 4, 2025.

Borrowings under the facility bear interest at SOFR plus 0.90 % per annum.

As of the date of this report, APS has not drawn on this term loan.

See “Financial Assurances” in Note 10 for a discussion of other outst anding letters of credit.

Debt Provisions

See Note 6 for additional long-term debt provisions .

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt and Liquidity Matters

All of Pinnacle West’s and APS’s debt is unsecured.

The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding (dollars in thousands):

Maturity Interest December 31,

Dates (a) Rates 2024 2023

Pollution control bonds:

Variable 2029 (b) $ 163,975 $ 163,975

Total pollution control bonds 163,975 163,975

Senior unsecured notes 2025-2050 2.20 %- 6.88 %

7,380,000 7,180,000

Unamortized discount ( 14,252 ) ( 14,197 )

Unamortized premium 9,955 11,162

Unamortized debt issuance cost ( 48,800 ) ( 49,049 )

Total APS long-term debt 7,490,878 7,291,891

Less current maturities 300,000 250,000

Total APS long-term debt less current maturities 7,190,878 7,041,891

Pinnacle West

Senior unsecured notes 2025-2027 1.30 %- 4.75 %

1,025,000 500,000

Floating rate note 2026 (c) 350,000 —

Term loans 2024 (d) — 625,000

Unamortized discount ( 5 ) ( 15 )

Unamortized debt issuance cost ( 7,225 ) ( 1,254 )

Total Pinnacle West long-term debt 1,367,770 1,123,731

Less current maturities 500,000 625,000

Total Pinnacle West long-term debt less current maturities 867,770 498,731

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES

$ 8,058,648 $ 7,540,622

(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b) The weighted-average interest rate for the variable rate pollution control bonds was 4.01 % at December 31, 2024, and 4.11 % at December 31, 2023.

See additional details below.

(d) The weighted-average interest rate was not applicable at December 31, 2024, and was 6.20 % at December 31, 2023.

See additional details below.

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The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):

Year Pinnacle West Consolidated APS Consolidated

2025 $ 800,000 $ 300,000

2026 600,000 250,000

2027 825,000 300,000

2029 568,975 568,975

Thereafter 6,125,000 6,125,000

Total $ 8,918,975 $ 7,543,975

Debt Fair Value

Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy.

The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

As of December 31, 2024 As of December 31, 2023

Amount Fair Value Carrying

Amount Fair Value

Pinnacle West $ 1,367,770 $ 1,393,744 $ 1,123,731 $ 1,095,935

APS 7,490,878 6,525,248 7,291,891 6,459,718

Total $ 8,858,648 $ 7,918,992 $ 8,415,622 $ 7,555,653

Credit Facilities and Debt and Equity Issuances

Pinnacle West

On December 16, 2022, Pinnacle West entered into a $ 175 million term loan facility that matured on December 16, 2024.

The proceeds were received on January 6, 2023, and used for general corporate purposes.

We recognized the term loan facility as long-term debt upon settlement on January 6, 2023.

On June 10, 2024 Pinnacle West repaid the full $ 175 million term loan, that matured on December 16, 2024.

On February 28, 2024, Pinnacle West entered into equity forward sale agreements (the “February 2024 Forward Sale Agreements”), which may be settled with Pinnacle West common stock or cash.

In December 2024, Pinnacle West partially settled the 2024 Forward Sale Agreements by issuing 5,377,115 shares of common stock and receiving net proceeds of $ 345 million .

The proceeds were recorded in equity.

At December 31, 2024, Pinnacle West could have settled the remaining February 2024 Forward Sale Agreements with the issuance of 5,863,486 shares of common stock, which would have provided cash liquidity to Pinnacle West of approximately $ 377 million.

On November 8, 2024, Pinnacle West entered into an equity forward sale agreement under the ATM program (the “November 2024 ATM Forward Sale Agreement”), which may be settled with Pinnacle West common stock or cash.

At December 31, 2024, Pinnacle West could have settled the November 2024 ATM Forward Sale Agreement with the issuance of 552,833 shares of common stock, which would have provided cash liquidity to Pinnacle West of approximately $ 50 million.

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Convertible Senior Notes.

In June 2024, Pinnacle West issued $ 525 million of 4.75 % convertible senior notes due 2027 (the “Convertible Notes”), which are senior unsecured obligations of Pinnacle West, and will mature on June 15, 2027.

The Convertible Notes bear interest at a fixed rate of 4.75 % per year, payable semiannually in arrears on June 15 and December 15 of each year, beginning on December 15, 2024.

Proceeds from the Convertible Notes were used to repay APS’s 364 -day $ 350 million term loan facility that matured on December 10, 2024 and commercial paper borrowings.

Prior to March 15, 2027, the holders of the Convertible Notes may elect at their option to convert all or any portion of their Convertible Notes under the following limited circumstances:

• during any calendar quarter (and only during such calendar quarter), if the sale price of Pinnacle West common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter, is greater than or equal to 130 % of the conversion price on each applicable trading day;

• during the five business day period after any 10 consecutive trading day period (“Measurement Period”) in which the trading price per $1,000 principal amount of Convertible Notes for each trading day of the Measurement Period was less than 98 % of the product of the last reported sale price of Pinnacle West common stock and the conversion rate on such trading day;

• upon the occurrence of certain corporate events, as defined in the Convertible Notes’ indenture.

On or after March 15, 2027, until the maturity date, the holders of the Convertible Notes may elect at their option to convert all or any portion of their notes.

Upon conversion, Pinnacle West will pay cash up to the aggregate principal amount of the Convertible Notes converted and at Pinnacle West’s sole discretion, pay or deliver cash, shares of Pinnacle West common stock or a combination of both, in respect to the remainder, if any, of Pinnacle West’s conversion obligation in excess of the aggregate principal amount of the Convertible Notes being converted.

The initial conversion rate, which is subject to certain adjustments as set forth in the indenture, is 10.8338 shares of common stock per $1,000 principal amount of Convertible Notes, which is equivalent to an initial conversion price of approximately $ 92.30 per share of Pinnacle West’s common stock.

The conversion rate is not subject to adjustment for any accrued and unpaid interest.

If Pinnacle West undergoes a fundamental change, as defined in the Convertible Notes’ indenture, then, subject to certain conditions, holders of the Convertible Notes may require Pinnacle West to repurchase for cash all or any portion of its Convertible Notes at a repurchase price equal to 100 % of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.

As of December 31, 2024, the conditions allowing holders to convert their Convertible Notes were not met, and as a result, the Convertible Notes were classified as long term debt on Pinnacle West’s Consolidated Balance Sheets with a carrying amount of $ 525 million, including unamortized debt issuance costs of $ 8 million.

The estimated fair value of the Convertible Notes as of December 31, 2024 was $ 552 million (Level 2 within the fair value hierarchy).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2024, based on Pinnacle West’s average stock price and the relevant terms of the Convertible Notes, there were no shares of Pinnacles West’s common stock included in basic or diluted EPS relating to the potential conversion of the Convertible Notes.

Floating Rate Notes.

In June 2024, Pinnacle West completed the sale of $ 350 million Floating Rate Notes due 2026 (the “Floating Rate Notes”).

The Floating Rate Notes are senior unsecured obligations of Pinnacle West and will mature on June 10, 2026.

The Floating Rate Notes bear a variable interest rate of Compounded SOFR (as defined in the Fifth Supplemental Indenture dated as of June 10, 2024) plus 82 basis points per year.

Proceeds were used to repay a portion of Pinnacle West’s $ 450 million term loan that matured in December 2024 and the full amount of Pinnacle West’s $ 175 million term loan that matured in December 2024.

On June 10, 2024, Pinnacle West repaid $ 250 million of its $ 450 million term loan which matured in December 2024.

On December 20, 2024, Pinnacle West repaid the remaining $ 200 million of the term loan.

On June 10, 2024 Pinnacle West repaid the full $ 175 million term loan, that matured on December 16, 2024.

APS was previously authorized to receive up to $ 150 million annually in equity infusions from Pinnacle West without seeking ACC approval.

In 2023, APS sought approval for an additional $ 500 million in equity infusions and received approval in early 2024.

Subsequently, APS requested and the ACC issued a new financing order that approved a limit on yearly equity infusions equal to 2.5 % of APS’s total assets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus 50 basis points.

On June 12, 2024, Pinnacle West contributed $ 450 million into APS in the form of an equity infusion.

APS used this contribution to repay short-term indebtedness.

On December 23, 2024, Pinnacle West contributed $ 345 million into APS in the form of an equity infusion.

APS used this contribution to repay a portion of commercial paper borrowings and for other general corporate purposes.

On May 9, 2024, APS issued $ 450 million of 5.7 % senior unsecured notes that mature August 15, 2034.

The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper and for general corporate purposes.

On June 17, 2024, APS repaid its $ 250 million 3.35 % senior unsecured notes at maturity from commercial paper borrowings.

See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for the development of a 31 megawatt (“MW”) solar and 20 megawatt hour (“MWh”) battery storage project in Los Alamitos, California (“Los Alamitos”).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

agreement consisted of an equity bridge loan facility, a non-recourse construction facility, a letter of credit facility, and a related interest rate swap.

On August 4, 2023, Pinnacle West entered into a purchase and sale agreement with Ameresco, Inc.

(“Ameresco”), pursuant to which we agreed to sell all our equity interest in BCE to Ameresco (the “BCE Sale”).

As a part of the BCE Sale closing, the $ 36 million construction facility, the letter of credit facility, and the interest rate swap were transferred to Ameresco.

On August 4, 2023, concurrent with the BCE Sale, Pinnacle West paid in full the outstanding $ 31 million equity bridge loan balance.

As of December 31, 2024, there is no outstanding balance on our Consolidated Balance Sheets relating to this credit agreement.

On April 18, 2023, and on December 29, 2023, Pinnacle West issued performance guarantees in connection with BCE’s Kūpono Solar investment project financing.

BCE held an equity method investment relating to the Kūpono Solar project that was included in the BCE Sale relating to the stage of the BCE Sale that closed on January 12, 2024.

The performance guarantees did not transfer in the BCE Sale, and Pinnacle West continues to retain these performance guarantees.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.

Pinnacle West and APS comply with this covenant.

For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65 %.

At December 31, 2024, the ratio was approximately 59 % for Pinnacle West and 49 % for APS.

See further discussion of “cross-default” provisions below.

However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.

All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements.

Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

On April 19, 2024, APS submitted an application to the ACC requesting to increase the long-term debt limit from $ 8.0 billion to $ 9.5 billion and to increase Pinnacle West’s permitted yearly equity infusions to equal up to 2.5 % of APS’s consolidated assets each calendar year on a three-year rolling average basis.

On December 17, 2024, the ACC issued a financing order approving the increase of the long-term debt limit to $ 9.5 billion and the permitted yearly equity infusions to equal to 2.5 % of APS’s total assets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

remaining below the most recently approved rate case capital structure plus 50 basis points.

See Note 5 for additional short-term debt provisions.

(d) See “Cost Recovery Mechanisms” discussion above.

Retirement Plans and Other Postretirement Benefits

9 unchanged sentences

Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.

For the medical insurance plan, retirees make contributions to cover a portion of the plan costs.

For the medical

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

insurance plan, retirees make contributions to cover a portion of the plan costs.

For the life insurance plan, retirees do not make contributions.

7 unchanged sentences

Our retail rates provide for the inclusion of annual benefit expense, which allows for recovery or return of this regulatory asset/liability.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

The following table provides detail of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

Pension Plans Other Benefits Plans

15 unchanged sentences

In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits.

We have been amortizing these prior-serviced credits since 2015 with the last full-year amortization occurring in 2024.

We have been amortizing these prior-serviced credits since 2015, and they became fully amortized as of January 31, 2025.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):

7 unchanged sentences

Actuarial (gain) loss 79,363 ( 91,800 ) 7,759 ( 71,952 )

Other plan changes 6,752 — — —

Benefit obligation at December 31 2,850,810 2,792,309 367,982 360,090

9 unchanged sentences

Fair value of plan assets — —

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Pinnacle West Capital Corporation Retirement Plan is more than 100 % funded on an accumulated benefit obligation basis at December 31, 2024, and December 31, 2023, therefore, the only pension plan with an accumulated benefit obligation in excess of plan assets in 2024 and 2023 is a non-qualified supplemental excess benefit retirement plan.

The Pinnacle West Capital Corporation Retirement Plan is more than 100 % funded on an accumulated benefit obligation basis at December 31, 2025, and December 31, 2024, therefore, the only pension plan with an accumulated benefit obligation in excess of plan assets in 2025 and 2024 is the non-qualified supplemental excess benefit retirement plan.

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):

3 unchanged sentences

The Pinnacle West Capital Corporation Retirement Plan, on a projected benefit obligation basis, was 98 % funded at December 31, 2025, and 99 % funded at December 31, 2024.

For 2024, we included both the projected benefit obligation and the fair value of plan assets for our qualified pension plan and a non-qualified supplemental excess benefit retirement plan.

In 2023, the only plan that was underfunded was the non-qualified supplemental excess benefit retirement plan.

In the table above, we included both the projected benefit obligation and the fair value of plan assets for our qualified pension plan and our non-qualified supplemental excess benefit retirement plan.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):

9 unchanged sentences

Net actuarial loss (gain) $ 760,502 $ 793,421 $ ( 234,958 ) $ ( 237,889 )

Prior service credit — — ( 1,265 ) ( 39,054 )

Prior service cost (credit) 6,752 — — ( 1,265 )

APS’s portion recorded as a regulatory (asset) liability ( 723,042 ) ( 750,976 ) 233,952 238,113

1 unchanged sentence

Accumulated other comprehensive loss (gain) $ 33,283 $ 32,091 $ ( 303 ) $ ( 430 )

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:

11 unchanged sentences

Number of years to ultimate trend rate (pre-65 participants) 7 6 6 4 5

Initial healthcare cost trend rate (post-65 participants) 1.00 % 2.00 % 2.00 % 2.00 % 2.00 %

Ultimate healthcare cost trend rate (post-65 participants) — % 2.00 % 2.00 % 2.00 % 2.00 %

Initial healthcare cost trend rate (post-65 participants) (a) N/A 1.00 % 1.00 % 2.00 % 2.00 %

Ultimate healthcare cost trend rate (post-65 participants) (a) N/A — % N/A 2.00 % 2.00 %

Interest crediting rate – cash balance pension plans 4.51 % 4.66 % 4.66 % 4.54 % 4.50 %

(a) The Company has decided and has communicated to retirees that the increase in 2026 will be 1 % with no further indexation in future years.

Therefore, no assumption is being made for the Post-65 HRA subsidy trend rate.

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan.

For 2026, we are assuming a 6.90 % long-term rate of return for pension assets and 7.00 % (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.

11 unchanged sentences

Long-term fixed income assets may also include interest rate swaps, and other instruments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Return-seeking assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.

15 unchanged sentences

Alternative investments 4 %

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The pension plan IPS does not provide for a specific mix of long-term fixed income assets but does expect the average credit quality of such assets to be investment grade.

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Fixed income securities issued by the U.S.

Treasury held directly by the plans are valued using quoted active market

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

prices and are classified as Level 1.

Treasury held directly by the plans are valued using quoted active market prices and are classified as Level 1.

Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity, and credit quality.

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as of December 31, 2025, approximately $ 38 million of these commitments have been funded.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value.

1 unchanged sentence

These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2025, by asset category, are as follows (dollars in thousands):

36 unchanged sentences

Pension Plan:

Cash and cash equivalents $ 9,055 $ — $ — $ 9,055

Fixed income securities:

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Other Benefits:

Cash and cash equivalents $ 840 $ — $ — $ 840

Fixed income securities:

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The expected minimum required cash contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2026, 2027 or 2028;

however, we continue to evaluate and assess our ongoing contribution strategy.

With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2025 or 2024 and do not expect to make any contributions in 2026, 2027 or 2028.

The Company was reimbursed $ 27 million in 2024, $ 23 million in 2023, and $ 26 million in 2022 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

For retiree medical claims from the other postretirement benefit plan trust assets, there was

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

not a reimbursement received in 2025.

The Company was reimbursed $ 27 million in 2024, and $ 23 million in 2023 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

Estimated Future Benefit Payments

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Pinnacle West recorded expenses for this plan of approximately $ 14 million for 2025, $ 14 million for 2024, and $ 12 million for 2023.

We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates.

APS also has certain purchased power and energy storage agreements that qualify as lease arrangements.

Our leases have remaining terms that expire in 2025 through 2073.

Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.

These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.

As the primary beneficiary, APS consolidated these lessor trust entities.

The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.

See Note 17 for a discussion of VIEs.

APS has purchased power lease agreements that allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements.

As APS only has rights to use the assets during certain periods of each year, the leases have non-consecutive periods of use.

APS does not operate or maintain the leased assets.

APS controls the dispatch of the leased assets during the months of use and is required to pay a fixed monthly capacity payment during these periods of use.

For these types of leased assets, APS has elected to combine both the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation.

In addition to the fixed monthly capacity payments, APS must also pay variable charges based on the actual production volume of the assets.

The variable consideration is not included in the measurement of our lease obligation.

APS has executed various energy storage purchased power lease agreements that allow APS the right to charge and discharge energy storage facilities.

APS pays a fixed monthly capacity price for rights to use the lease assets.

The agreements generally have 20 -year lease terms and provide APS with the exclusive use of the energy storage assets through the lease term.

APS does not operate or maintain the energy storage facilities and has no purchase options or residual value guarantees relating to these lease assets.

For this class of energy storage lease assets, APS has elected to separate the lease and non-lease components.

These leases are accounted for as operating leases, with lease terms that commenced between September 2023 and August 2024.

The following table provides information related to our lease costs (dollars in thousands):

Year Ended December 31,

2024 2023 2022

Operating Lease Cost - Purchased Power & Energy Storage Lease Contracts $ 147,313 $ 126,655 $ 104,001

Operating Lease Cost - Land, Property, and Other Equipment 20,120 19,235 18,061

Total Operating Lease Cost 167,433 145,890 122,062

Variable Lease Cost (a) 144,108 135,007 122,040

Short-term Lease Cost 20,653 21,530 9,928

Total Lease Cost $ 332,194 $ 302,427 $ 254,030

(a) Primarily relates to purchased power lease contracts.

Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income.

Lease costs relating to purchased power and energy storage lease contracts are recorded in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES.

The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES.

Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts.

Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets.

Certain of our lease agreements have lease terms with non-consecutive periods of use.

For these agreements, we recognize lease costs during the periods of use.

Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheets.

Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key employees, and non-officer members of the Board of Directors.

Awards granted under the 2021 Long-Term Incentive Plan, as amended (“2021 Plan”), may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.

The 2021 Plan authorizes up to 4.3 million common shares to be available for grant.

As of December 31, 2025, 2.5 million common shares were available for issuance under the 2021 Plan.

During 2025, 2024 and 2023, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares.

Awards granted from 2012 to May 2021 were issued under the 2012 Long-Term Incentive Plan (“2012 Plan”), and awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”).

No new awards may be granted under the 2012 or 2007 Plans.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):

December 31, 2024

Year Purchased Power & Energy Storage Lease Contracts Land, Property & Equipment Leases Total

2025 $ 158,363 $ 16,834 $ 175,197

2026 172,087 14,830 186,917

Stock-Based Compensation Expense and Activity

Compensation cost included in net income for stock-based compensation plans was $ 27 million in 2025, $ 24 million in 2024, and $ 17 million in 2023.

The compensation cost capitalized is immaterial for all years.

Income tax benefits related to stock-based compensation arrangements were $ 12 million in 2025, $ 6 million in 2024, and $ 3 million in 2023.

As of December 31, 2025, there were approximately $ 42 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements.

We expect to recognize these costs over a weighted-average period of 2 years.

The total fair value of shares vested was $ 27 million in 2025, $ 24 million in 2024, and $ 24 million in 2023.

The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last 3 years:

Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b)

2025 2024 2023 2025 2024 2023

Units granted 204,886 261,808 192,295 164,220 225,516 202,562

Weighted-average grant date fair value $ 90.25 $ 71.10 $ 74.32 $ 97.72 $ 72.89 $ 79.61

(a) The units granted do not include awards that will be cash settled in 2025, 2024 or 2023.

See below for additional information on restricted stock unit grants.

(b) Reflects the target payout level.

The following table shows the change of nonvested awards:

Restricted Stock Units, Stock Grants, and Stock Units Performance Shares

Shares Weighted-Average

Fair Value Shares (b) Weighted-Average

Nonvested at December 31, 2024

460,791 $ 71.72 390,551 $ 77.29

Granted 204,886 90.25 164,220 97.72

Vested ( 186,883 ) 73.77 ( 169,682 ) 77.94

Forfeited (c) ( 15,856 ) 79.59 ( 13,535 ) 85.01

Nonvested at December 31, 2025

462,938 (a) 78.82 371,554 83.48

Vested Awards Outstanding at December 31, 2025

76,758 169,682

Thereafter 1,140,971 61,855 1,202,826

Total lease commitments 2,076,973 122,824 2,199,797

Less imputed interest 536,948 41,605 578,553

Total lease liabilities $ 1,540,025 $ 81,219 $ 1,621,244

We recognize lease assets and liabilities upon lease commencement.

At December 31, 2024, we have various lease arrangements that have been executed, but have not yet commenced.

We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $ 16.7 billion over the terms of the agreements.

These arrangements primarily relate to energy storage assets.

We expect lease commencement dates ranging from March 2025 through June 2028, with lease terms expiring through June 2048.

The lease commencement dates for certain arrangements have experienced delays.

As a result of these delays and other events, APS has received cash proceeds from certain lessors prior to lease commencement.

Proceeds received from lessors relating to energy storage PPA leases are accounted for as lease incentives on our Consolidated Balance Sheets, and upon lease commencement are amortized over the associated lease term.

For regulatory purposes, the proceeds received by APS relating to these PPA leases are treated as a reduction to fuel and purchased power costs through the PSA in the period proceeds are received.

(a) Includes no awards that will be cash settled.

(b) The performance shares are reflected at target payout level.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide other additional information related to operating lease liabilities (dollars in thousands):

Year Ended December 31,

2024 2023 2022

Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:

$ 143,950 $ 123,472 $ 118,463

Right-of-use operating lease assets obtained in exchange for operating lease liabilities:

393,702 (a) 602,301 (b) 16,990

December 31, 2024 December 31, 2023

Weighted average remaining lease term 11 years 10 years

Weighted average discount rate (c) 4.90 % 4.53 %

(a) Primarily relates to the three new energy storage operating lease agreements that commenced in 2024.

(b) Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.

For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities.

We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment.

We use the implicit rate when it is readily determinable.

Share-based liabilities paid relating to restricted stock units were $ 14 million, $ 8 million, and $ 6 million in 2025, 2024 and 2023, respectively.

This includes cash used to settle restricted stock units of $ 1 million, $ 2 million, and $ 3 million in 2025, 2024 and 2023, respectively.

Restricted stock units that are cash settled are classified as liability awards.

All performance shares are classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees and typically vest and settle in equal annual installments over a 4 -year period after the grant date.

Vesting is typically dependent upon continuous service during the vesting period.

Beginning in 2022, restricted stock unit awards are issued in stock.

Awards include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date.

If the award is forfeited the employee is not entitled to the accrued reinvested dividends on those shares.

Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, awardees typically elected to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

Awards included a dividend equivalent feature that accrued dividend rights from the date of grant until the applicable vesting date, plus interest compounded quarterly.

If the award was forfeited, the employee was not entitled to the accrued dividends on those shares.

Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date.

Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price and remeasured at each balance sheet date.

Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company’s closing stock price on the date of grant.

Compensation cost is recognized over the requisite service period based on the fair value of the award.

Stock grants are issued to non-officer members of the Board of Directors.

They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant.

Beginning in 2023, payments for stock units are issued in stock and include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date.

Prior to 2023, members of the Board of Directors who elected to defer could elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

The stock units prior to 2023 included a dividend equivalent feature that accrues dividend rights from the date of grant to the date of payment, plus interest compounded quarterly.

Performance Share Awards

Performance share awards are granted to officers and key employees.

The awards contain separate performance metric criteria that affect the number of shares that may be received if, after the end of a 3 -year performance period, the performance criteria are met.

Beginning in 2022, performance share awards contain three separate, unrelated performance criteria.

The first performance criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

relation to the TSR of other companies in a specified utility index (i.e., the TSR component).

The second performance criteria is based upon Pinnacle West’s earnings per share (“EPS”) performance relative to an approved target (i.e., the EPS component).

The third performance criteria is based upon APS’s clean MW installed of renewable or other carbon free resources compared to the approved target (i.e., the Clean component).

The exact number of shares issued is calculated separately for each performance component and can vary from 0 % to 200 % of the target award for each separate performance criteria.

Shares received include a dividend equivalent feature that treats accrued dividends as reinvested, from the date of grant until the date of payment, equal to the number of vested performance shares.

If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, performance share awards had two performance criteria.

The first performance criteria was based upon non-financial performance metrics (i.e., the Metric component).

The second performance criteria was based upon Pinnacle West’s TSR in relation to the TSR of other companies in a specified utility index (i.e., the TSR component).

The exact number of shares issued will vary from 0 % to 200 % of the target award.

Shares received included a dividend equivalent feature that allows accrued dividend rights from the date of grant until the date of payment, plus interest compounded quarterly, equal to the number of vested performance shares.

If the award was forfeited, the employee was not entitled to the accrued dividends on those shares.

Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.

Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date.

Compensation cost relating to the EPS and Clean metric component of the respective awards is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest.

Management evaluates the probability of meeting the EPS and Clean metric component at each balance sheet date.

If the EPS and Clean metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the EPS and Clean metric component, and any previously recognized compensation cost is reversed.

Compensation cost relating to the TSR component of the respective awards is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Jointly-Owned Facilities

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Four Corners Generating Station 63.0 % 1,941,053 747,931 19,378

Cholla Common Facilities (c) 50.5 % 301,035 231,170 1,743

Transmission facilities:

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Kyrene — Knox System 50.0 % 578 359 —

Agua Fria Switchyard 10.0 % — — 82

(a) See Note 17.

(a) See Note 12 for information related to the Palo Verde sale leaseback purchases.

(b) Weighted-average of interests.

Cholla Unit 4 was retired on December 24, 2020.

The common facilities at Cholla are jointly-owned.

Variable Interest Entities

Pinnacle West

Captive Insurance Cell VIE

To support our overall insurance program, Pinnacle West established a captive insurance cell to insure certain risks of Pinnacle West and our subsidiaries.

The Captive is a protected separate cell captive insurance company sponsored by Energy Insurance Services, Inc (“EISI”).

EISI is owned by Energy Insurance Mutual Limited Company and allows participating member sponsoring organizations, such as Pinnacle West, to insure risks using captive entities.

Pinnacle West, through its contractual rights, has a controlling financial interest in the separate protected Captive cell’s assets.

Pinnacle West obtains all the

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benefits from the Captive and makes all the primary controlling decisions that economically impact the Captive.

As a separate protected cell, Pinnacle West is the Captive’s only participant.

The Captive is a VIE for which Pinnacle West is the primary beneficiary.

Accordingly, Pinnacle West consolidates the Captive.

Under a mutual business program participation agreement between the Captive and EISI, EISI will issue policies, make claim disbursements, claim expenses and other underwriting fees on behalf of the Captive, as necessary.

The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability.

The Captive policies exclude nuclear liability at Palo Verde.

See Note 14 for details regarding nuclear liability insurance.

Claim payments to the insureds can only be made up to the amount of the Captive’s available assets.

In the event that claims exceed the Captive’s available assets, Pinnacle West may be required to provide additional funding to the Captive.

In addition to policies obtained through the Captive, Pinnacle West also has commercial and mutual insurance policies purchased through third-party insurers that may provide coverage if a loss event occurs.

As a result of consolidation, we eliminate intercompany transactions between Pinnacle West and the Captive and record the Captive’s assets, liabilities and third-party operating activities.

In consolidation, the Captive’s insurance premium revenues derived from Pinnacle West policies are eliminated against the insurance premium expense recorded by Pinnacle West and our subsidiaries relating to insurance policy coverage provided by the Captive.

Consolidation primarily resulted in Pinnacle West reflecting the Captive’s investment holdings on its Consolidated Balance Sheets, and the Captive’s investment gains and losses reflected through earnings on Pinnacle West’s Consolidated Statements of Income.

Consolidation of the Captive resulted in an increase in Pinnacle West net income of the year ended December 31, 2025, 2024, and 2023 of $ 5 million, $ 5 million, and zero , respectively.

These amounts are fully attributable to Pinnacle West shareholders.

Consolidation impacts Pinnacle West Consolidated Income Statement’s operations and maintenance expense, other income and other expense line items.

Pinnacle West’s Consolidated Balance Sheets as of December 31, 2025 and 2024 include $ 40 million and $ 34 million of assets relating to the Captive that is reported within the other special use funds line item.

See Notes 17 and 18 for additional details on these investment holdings.

APS’s financial statements are not impacted by Pinnacle West’s consolidation of the Captive VIE.

Palo Verde Sale Leaseback VIEs

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.

As further described below, in September 2025, APS purchased two of the three leased interests, the two related lease agreements were terminated and VIE consolidation treatment was discontinued for those two leases.

As of December 31, 2025, one VIE lease arrangement remains in effect.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In June 2025, APS executed purchase agreements relating to two of the three VIE lease arrangements and subsequently submitted filings with FERC requesting authorization of the acquisitions.

On September 10, 2025, FERC issued an order authorizing the APS acquisition of these leased interests.

On September 22, 2025, all closing conditions were satisfied and APS acquired the two leased Palo Verde interests from the VIE noncontrolling interest lessor owners for a combined total of approximately $ 199 million.

The two related lease agreements were terminated, and APS no longer has payment obligations to these two VIE noncontrolling interest lessors.

As a result of the acquisition and lease terminations, effective September 22, 2025, APS no longer holds a variable interest in these lessor trust entities and therefore no longer consolidates these two lessor VIEs.

In accordance with GAAP, the purchase is accounted for as the acquisition of the VIE’s noncontrolling interests.

As a result of the purchases, APS’s Consolidated Balance Sheet as of September 30, 2025, included $ 47 million of property, plant and equipment, net of accumulated depreciation, that was reclassified from the Palo Verde sale leaseback asset line item.

The remaining $ 152 million of the $ 199 million purchase price represents the incremental market value above the VIE’s net book value included in the consideration to acquire the noncontrolling interest.

The $ 152 million was recorded as a new regulatory asset on the APS Consolidated Balance Sheet as of September 30, 2025.

As a result of these September 2025 purchases, APS’ Consolidated Balance Sheets as of December 31, 2025, includes $ 47 million of property, plant, and equipment, net of accumulated depreciation;

and a $ 152 million regulatory asset.

In the 2025 Rate Case, APS has requested to recover the acquisition of the leased interests in future customer rates as an investment in plant assets, seeking a full cost of capital return on the $ 199 million investment.

APS did not recognize a gain or loss as a result of deconsolidating these two VIE entities;

accordingly, for the year ended December 31, 2025, the acquisition of the VIE leased interests had no impact on the APS Consolidated Statements of Income.

As of December 31, 2025, APS owns these previously leased interests, providing APS a total ownership interest in Palo Verde Unit 2 of 23.9 %.

APS’s remaining leased interest in Palo Verde Unit 2 as of December 31, 2025, is approximately 5.2 %.

The VIE lease agreement that was not subject to the purchase agreements remains in effect and is not impacted by the purchase transactions.

Under the current remaining lease in effect, APS will retain the leased asset through 2033 and will be required to make payments relating to the lease in total of approximately $ 9 million annually for the period 2026 through 2033.

At the end of the lease period, APS will have the option to purchase the leased asset at its fair market value, extend the lease for up to two years , or return the asset to the lessor.

The lease terms give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIE that most significantly impact the VIE’s economic performance.

Predominantly due to the lease terms, APS has been deemed the primary beneficiary of this VIE and therefore consolidates the VIE.

As a result of consolidation of the VIEs, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $ 15 million in 2025 and $ 17 million for each of 2024 and 2023.

The increase in net income is entirely attributable to the noncontrolling interests.

Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our Consolidated Balance Sheets include the following amounts relating to these VIEs (dollars in thousands):

December 31, 2025 December 31, 2024 (a)

Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 32,035 $ 82,556

Equity — Noncontrolling interests 40,617 103,167

(a) Includes the two VIEs subject to the September 2025 purchase transactions described above.

Assets of the VIE are restricted and may only be used for payment to the noncontrolling interest holders.

These assets are reported on our Consolidated Financial Statements.

APS is exposed to losses relating to the VIE upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.

Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIE’s noncontrolling equity participants and take title to the leased Unit 2 interest, which, if appropriate, may be required to be written-down in value.

If such an event were to occur during the lease period, APS may be required to pay the noncontrolling equity participant approximately $ 177 million in 2026 and up to $ 267 million over the lease term.

For regulatory ratemaking purposes, the lease agreement continues to be treated as an operating lease, and as a result, we have recorded a regulatory asset relating to the arrangement.

Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates.

Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options, and swaps.

As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas.

Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.

The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.

Derivative instruments are also entered into for economic hedging purposes.

While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.

Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the Consolidated Balance Sheets as an asset or liability and are measured at fair value.

See Note 17 for a discussion of fair value measurements.

Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery, and the quantities represent those transacted in the normal course of business.

Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 16 for details relating to Pinnacle West’s equity forward sale agreements and convertible notes.

These equity-linked transactions are indexed to Pinnacle West common stock and qualify for a derivative scope exception and as such are not subject to mark-to-market accounting and are excluded from the derivative disclosures below.

Energy Derivatives

For its regulated operations, APS defers for future rate treatment 100 % of the unrealized gains and losses on energy derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.

Realized gains and losses on energy derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate.

Gains and losses from energy derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position):

Commodity Unit of Measure December 31, 2025 December 31, 2024

Power Gigawatt-hour 542 1,051

Gas Billion cubic feet 211 235

Gains and Losses from Energy Derivative Instruments

For the years ended December 31, 2025, 2024 and 2023, APS had no energy derivative instruments in designated accounting hedging relationships.

The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):

Financial Statement Year Ended December 31,

Commodity Contracts Location 2025 2024 2023

Net Loss Recognized in Income

Fuel and purchased power (a) $ ( 50,566 ) $ ( 88,522 ) $ ( 370,145 )

(a) Amounts are before the effect of PSA deferrals.

Energy Derivative Instruments in the Consolidated Balance Sheets

Our energy derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.

Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.

Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets.

Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We do not offset a counterparty’s current energy derivative contracts with the counterparty’s non-current energy derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.

These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).

These types of transactions are excluded from the offsetting tables presented below.

The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.

These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Consolidated Balance Sheets (dollars in thousands):

As of December 31, 2025 Gross

Derivatives Other

Balance Sheets

Current assets $ 12,640 $ ( 9,395 ) $ 3,245 $ 5 $ 3,250

Investments and other assets 6,707 ( 1,570 ) 5,137 — 5,137

Total assets 19,347 ( 10,965 ) 8,382 5 8,387

Current liabilities ( 41,970 ) 9,395 ( 32,575 ) ( 2,566 ) ( 35,141 )

Deferred credits and other ( 3,065 ) 1,570 ( 1,495 ) — ( 1,495 )

Total liabilities ( 45,035 ) 10,965 ( 34,070 ) ( 2,566 ) ( 36,636 )

Total $ ( 25,688 ) $ — $ ( 25,688 ) $ ( 2,561 ) $ ( 28,249 )

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) No cash collateral has been provided to or received by counterparties, that is subject to offsetting.

Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.

Includes cash collateral received from counterparties of $ 2,566 thousand and cash margin provided to counterparties of $ 5 thousand.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2024 Gross

Derivatives Other

Balance Sheets

Current assets $ 13,718 $ ( 3,158 ) $ 10,560 $ 18 $ 10,578

Investments and other assets 6,610 ( 630 ) 5,980 — 5,980

Total assets 20,328 ( 3,788 ) 16,540 18 16,558

Current liabilities ( 52,527 ) 3,158 ( 49,369 ) ( 2,971 ) ( 52,340 )

Deferred credits and other ( 10,076 ) 630 ( 9,446 ) — ( 9,446 )

Total liabilities ( 62,603 ) 3,788 ( 58,815 ) ( 2,971 ) ( 61,786 )

Total $ ( 42,275 ) $ — $ ( 42,275 ) $ ( 2,953 ) $ ( 45,228 )

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) No cash collateral has been provided to or received by counterparties, that is subject to offsetting.

Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.

Includes cash collateral received from counterparties of $ 2,971 thousand and cash margin provided to counterparties of $ 18 thousand.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties.

As of December 31, 2025, we have four counterparties for which our exposure represents approximately 73 % of Pinnacle West’s $ 8.4 million of net risk management assets.

This exposure relates to ISDA master agreements with the respective counterparties.

The ISDA counterparties have an investment grade credit rating by either Standard & Poor’s and/or Moody’s.

Our risk management process assesses and monitors the financial exposure of all counterparties.

Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated results of operations for a given period.

Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.

We maintain credit policies that we believe minimize overall credit risk within acceptable limits.

Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.

To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our energy derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.

Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.

For those energy derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):

December 31, 2025

Aggregate fair value of derivative instruments in a net liability position $ 45,035

Additional collateral in the event credit-risk related contingent features were fully triggered (a) 11,171

(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

As of December 31, 2025, we also have energy related non-derivative instrument contracts, with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $ 710 million if our debt credit ratings were to fall below investment grade.

Commitments and Contingencies

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The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.

On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011.

On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs paid by Palo Verde during the period January 1, 2007, through June 30, 2011.

In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025.

APS has recovered costs for ten claims pursuant to the terms of the August 15, 2014 settlement agreement, for ten separate time periods during July 1, 2011, through October 31, 2023.

APS is currently evaluating a proposed extension to the settlement to cover costs paid through December 31, 2028.

APS has recovered costs for eleven claims pursuant to the terms of the August 15, 2014 settlement agreement, for eleven separate time periods during July 1, 2011, through October 31, 2024.

The DOE has approved and paid approximately $ 174.3 million for these claims (APS’s share is approximately $ 50.7 million).

The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income.

In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers.

On October 31, 2024, APS filed its eleven th claim pursuant to the terms of the August 15, 2014, settlement agreement in the amount of approximately $ 18 million (APS’s share is approximately $ 5.3 million).

In accordance with the ACC’s decision from the 2017 rate case, this regulatory liability is being refunded to customers.

On October 31, 2025, APS submitted its twelfth claim pursuant to the terms of the settlement agreement in the amount of approximately $ 15.4 million (APS’s share is approximately $ 4.5 million).

In February 2026, the DOE approved approximately $ 15.4 million of this claim.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

This insurance limit is subject to an adjustment every five years based upon the aggregate percentage change in the Consumer Price Index.

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Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $ 144.9 million, with a maximum annual retrospective premium of approximately $ 21.6 million.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $ 2.8 billion.

APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units.

The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”).

The property damage, decontamination, and accidental outage insurance are provided by NEIL.

APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumul ated funds.

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The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits, and exclusions.

Nuclear Wage Class Action Lawsuit

On July 11, 2025, APS, together with all 25 other U.S.

nuclear power plant operators, was named in a class action lawsuit brought in the U.S.

District Court in Maryland.

The lawsuit alleges the country’s nuclear operators have violated antitrust laws by agreeing to exchange compensation information and suppress compensation.

The class action complaint has been brought on behalf of all persons employed in nuclear power generation in the U.S.

from May 1, 2003 until the present and alleges violations of the Sherman Act.

We are unable at this time to predict the outcome of this matter and whether it will have a material impact on our financial position, results of operations, or cash flows.

Captive Insurance Cell

Pinnacle West has established a captive insurance program to supplement third-party insurance coverage for certain risks.

Pinnacle West has established a captive insurance program to supplement commercial and mutual insurance coverage for certain risks.

These coverages may be supplemented with third-party insurance policies.

These coverages may be supplemented with commercial and mutual insurance coverage.

The Captive policies exclude nuclear liability at Palo Verde.

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The Captive is a VIE, and Pinnacle West is the primary beneficiary of the VIE and consolidates the assets and liabilities of the Captive.

In addition to the policies obtained through the Captive, Pinnacle West also has commercial and mutual

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

insurance policies purchased through third-party insurers that may provide coverage if a loss event occurs.

See Note 12 for additional details.

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APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2026 and 2054 that include required purchase provisions.

APS estimates the contract requirements to be approximately $ 1,540 million in 2025;

As of December 31, 2025, APS estimates the contract requirements to be approximately $ 1,811 million in 2026;

$ 1,988 million in 2027;

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and $ 32.2 billion thereafter.

Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation.

Purchase obligations may include commitments for capital expenditures and other obligations.

However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

These amounts include estimated commitments relating to purchased power lease contracts.

In January 2026, certain purchased power lease contracts were modified resulting in an additional $ 694 million of purchase obligations, primarily relating to periods after 2030.

Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions.

The current coal contracts with take-or-pay provisions have terms expiring through 2031.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):

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These amounts do not include purchases of renewable energy credits that are bundled with energy.

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Coal Mine Reclamation Obligations

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$ 22 million in 2027;

$ 23 million in 2028;

and $ 2 million thereafter.

and $ 23 million in 2028.

These funds are held in an escrow account and will be distributed to certain coal providers under the terms of the applicable coal supply agreements.

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Superfund and Other Related Matters

The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.

Those who released, generated, transported to or disposed of hazardous substances at a

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contaminated site are among the parties who are potentially responsible (each a “PRP”).

CERCLA establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.

Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”).

PRPs may be strictly, jointly, and severally liable for clean-up.

On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona.

On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, OU3, in Phoenix, Arizona.

APS has facilities that are within this Superfund site.

APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.

In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”).

In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and man agement of the site-wide groundwater RI/FS.

The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022.

EPA notified APS that the RI/FS was approved on September 11, 2024.

APS’s estimated costs related to this investigation and study is approximately $ 3 million.

APS anticipates incurring additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

In connection with APS’s status as a PRP for OU3, since 2013 APS and at least two dozen other parties have been defendants in various CERCLA lawsuits stemming from allegations that contamination from OU3 and elsewhere has impacted groundwater wells operated by the Roosevelt Irrigation District (“RID”).

On September 25, 2025, EPA executed a final ROD adopting the OU3 remedies proposed in the approved RI/FS OU3.

APS’s expenditures related to this investigation and study are approximately $ 3 million.

APS anticipates it may incur additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS and ROD are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated;

however, APS does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

At this time, only one active lawsuit remains pending in the U.S.

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On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona.

In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site.

The SIBW Superfund site includes the APS Ocotillo power plant site.

In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing PFAS at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash Superfund site.

The South Indian Bend Wash Superfund site includes the

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APS Ocotillo power plant site.

APS filed its response to this information request on April 29, 2022.

On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years.

On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the South Indian Bend Wash site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years.

APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $ 1.7 million.

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Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs.

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and GHG, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs.

These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.

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The following proposed and final rules could involve material compliance costs to APS.

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Coal Combustion Waste

On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash.

The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions.

On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCRs, such as fly ash and bottom ash.

The rule regulates CCR as a non-hazardous waste under Subtitle D of the RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions.

These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements.

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The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

• Following the passage of the Water Infrastructure Improvements for the Nation (“WIIN”) Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands.

At this time, Arizona Department of Environmental Quality (“ ADEQ”) has taken steps to develop a CCR permitting program and plans to propose state regulations governing CCR permitting over the summer of 2024.

It remains unclear when EPA would approve that permitting program pursuant to the WIIN Act.

• Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands.

ADEQ has taken steps to develop a CCR permitting program and proposed state regulations governing CCR permitting in the summer of 2024.

On April 1, 2025, the Arizona Governor’s Regulatory Review Council approved ADEQ’s proposed rulemaking governing CCR permitting.

ADEQ will submit an approval package to

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EPA, which will have to approve the entire state program before it is operational.

It remains unclear when EPA would approve that permitting program pursuant to the Water Infrastructure Improvements for the Nation Act.

On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits, which would impact facilities like Four Corners located on the Navajo Nation.

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Apart from a subsequent proposal issued on August 14, 2019 to add a specific health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

• With respect to APS’s Cholla facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020.

While EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending.

If granted, this application would allow the continued disposal of CCR within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025.

This application will be subject to public comment and, potentially, judicial review.

We expect to have a proposed decision from EPA regarding Cholla in 2025.

We cannot predict the outcome of these regulatory proceedings or when EPA will take final action on those matters that are still pending.

Depending on the eventual outcome, the costs associated with

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APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

On April 25, 2024, EPA took final action on a proposal to expand the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015.

This new class of CCR management units (“CCRMUs”), which contain at least 1,000 tons of CCR, broadly encompass any location at an operating coal-fired power plant where CCR would have been placed on land.

This new class of CCRMUs, which contain at least 1,000 tons of CCR, broadly encompass any location at an operating coal-fired power plant where CCRs would have been placed on land.

As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications of CCR beneficial use (with exceptions for historical roadbed and embankment applications).

Existing CCR regulatory requirements for groundwater monitoring, corrective action, closure, post-closure care, and other requirements will be imposed on such CCRMUs.

At this time, APS is still evaluating the impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2026 and final site investigation reports to be finalized by February 2027.

Based on the information available to APS at this time, APS cannot reasonably estimate the fair value of the entire CCRMU asset retirement obligation.

Depending on the outcome of those evaluations and site investigations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners.

Under EPA’s legacy 2024 CCRMU rule, initial CCRMU site surveys originally due to be completed by February 2026 and final site investigation reports by February 2027.

On February 10, 2026, EPA published a final rule extending multiple compliance deadlines applicable to CCRMUs established under the prior rule.

The final rule extends the deadline for completing Parts One and Two of Facility Evaluation Reports by one year to February 2027 and February 2028, respectively.

EPA also extended associated compliance deadlines for groundwater monitoring and certain closure requirements.

On February 9, 2026, EPA sent to the Office of Management and Budget for review a rule proposal that is anticipated to provide more substantive changes to certain aspects of the legacy 2024 CCRMU rule.

APS is still in the process of evaluating the impacts of these CCRMU regulations on its business and cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at changing the current EPA CCRMU rules.

Based on the information available to APS at this time, APS cannot reasonably estimate the cost of the entire CCRMU asset retirement obligation.

Depending on the outcome of the pending legacy 2024 CCRMU rule amendments and APS’s evaluations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Four Corners.

The Navajo Plant disposed of CCR only in a dry landfill storage area.

Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

The Cholla Plant disposed of CCR in ash ponds and dry storage areas prior to ceasing coal-fired operations.

Additionally, the CCR rule requires ongoing,

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phased groundwater monitoring.

As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring.

APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action.

In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure as of April 11, 2021 (except for those disposal units subject to alternative closure).

In addition, under the current regulations, all such dispo sal units must have ceased operating and initiated closure as of April 11, 2021 (except for those disposal units at Cholla that had been subject to alternative closure, which initiated closure work on June 30, 2025).

APS completed the assessments of corrective measures on June 14, 2019;

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In addition, APS has also solicited input from the public and hosted public hearings as part of this process.

APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations.

APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations, and Removal Costs within Regulatory Liabilities.

As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change.

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Starting on August 3, 2015, EPA finalized the Clean Power Plan, which was the agency’s first effort at such regulation through system-wide generation dispatch shifting.

Those regulations were subsequently repealed by the EPA on June 19, 2019 and replaced by the Affordable Clean Energy (“ACE”) regulations, which were a far narrower set of rules.

Those regulations were subsequently repealed by EPA on June 19, 2019 and replaced by the Affordable Clean Energy regulations, which were a far narrower set of rules.

While the U.S.

Court of Appeals for the D.C.

Circuit subsequently vacated the ACE regulations on January 19, 2021, and ordered a remand for EPA to develop replacement regulations consistent with the original 2015 Clean Power Plan, the U.S.

Circuit subsequently vacated the Affordable Clean Energy regulations on January 19, 2021, and ordered a remand for EPA to develop replacement regulations consistent with the original 2015 Clean Power Plan, the U.S.

Supreme Court subsequently reversed that decision on June 30, 2022, holding that the Clean Power Plan exceeded EPA’s authority under the Clean Air Act.

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In the final regulations governing power plant carbon dioxide emissions, released April 25, 2024, EPA issued emission standards and guidelines for various subcategories of new and existing power plants.

In the latest final regulations governing power plant carbon dioxide emissions, released April 25, 2024, EPA issued emission standards and guidelines for various subcategories of new and existing power plants.

Unlike EPA’s Clean Power Plan regulations from 2015, which took a broad, system-wide approach to regulating carbon emissions from electric utility fossil-fuel burning power plants, these new federal regulations are limited to measures that can be installed at individual power plants to limit planet-warming carbon-dioxide emissions.

As such, for new natural gas-fired combustion turbine power plants, EPA is proposing that carbon emission performance standards apply based on the annual capacity factors.

For the highest utilization combustion turbines, EPA is therefore proposing that such facilities be retrofitted for carbon capture and sequestration or utilization controls (“CCS”) by 2032.

For intermediate or low-load natural gas fired combustion turbines, those with 40% or less capacity factors, EPA’s regulations would not require add-on pollution controls.

Instead, natural gas-fired combustion turbines with capacity factors of up to 20% would be effectively unregulated, while such turbines with capacity factors over 20% and up to 40% would be subject to carbon dioxide emission rate limitations.

EPA did not finalize standards for existing natural gas-fired combustion turbines but has indicated that it will propose a new set of standards, initiating a separate rulemaking, for these existing gas-fired power plants within the next year.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA has finalized subcategories based on planned retirement dates.

This means that facilities retiring before 2032 are effectively exempt from regulation, those that retire between 2032 and 2038 must co-fire with natural gas starting in 2030, and those that retire in 2039 or later must install CCS controls by 2032.

Under current rules, carbon emission performance standards apply based on the annual capacity factors for new natural gas-fired combustion turbine power plants.

The highest utilization combustion turbines must be retrofitted for CCS by 2032.

Intermediate or low-load natural gas fired combustion turbines with 40% or less capacity factors do not require add-on pollution controls.

Instead, natural gas-fired combustion turbines with capacity factors of up to 20% are effectively unregulated, while turbines with capacity factors over 20% and up to 40% are subject to carbon dioxide emission rate limitations.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA finalized subcategories based on planned retirement dates.

Facilities retiring before 2032 are effectively exempt from regulation;

those that retire between 2032 and 2038 must co-fire with natural gas starting in 2030;

and those that retire in 2039 or later must install CCS controls by 2032.

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As of May 10, 2024, several states, electric utility companies, affiliated trade associations, and other entities filed petitions for review of these regulations in the D.C.

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APS is participating in that litigation as part of an ad hoc coalition of electric utility companies, independent power producers, and trade groups, called Electric Generators for a Sensible Transition.

We cannot predict the outcome of the litigation challenging EPA’s latest carbon emission standards for power plants.

In addition, the Trump administration has stated that it intends to reverse or substantially revise these standards.

On February 5, 2025, EPA filed an unopposed motion requesting that the D.C.

Circuit Court of Appeals hold the GHG regulations case in abeyance for 60 days and withhold issuing an opinion while the new leadership at EPA evaluates the rule and determines how it wishes to proceed.

On February 19, 2025, the Court granted EPA’s motion.

EPA subsequently filed a second motion asking the Court to keep the GHG regulations case in abeyance for an indefinite period of time given EPA’s anticipated reconsideration of the rules, with EPA providing status reports every 90 days.

Circuit granted EPA’s motion for an indefinite abeyance on April 25, 2025.

We cannot predict the outcome of the litigation challenging EPA’s current carbon emission standards for power plants.

If the current regulations were to remain in effect, they would likely lead to a material increase in APS’s costs to build, operate, and maintain new, frequently operated gas-fired power plants.

The regulatory deadlines in 2032 by which new, frequently operated gas-fired power plants must install CCS and achieve 90% capture efficiency may not be feasible.

Future resource plans and procurement efforts implicating the development of such new generation remain pending and, as such, at this time APS is not able to quantify the financial impact associated with EPA’s existing GHG regulations for power plants.

On June 11, 2025, EPA put forth a proposed rule with two scenarios for repealing the GHG regulations finalized in 2024.

EPA’s primary proposal entails a full repeal of the GHG regulations based on a finding that GHG emissions from fossil fuel-fired power plants do not present a “significant contribution” to dangerous air pollution, thereby eliminating the 2024 GHG power plant regulations in their entirety.

Under EPA’s alternative proposal, only certain portions of the 2024 GHG regulations would be repealed based on a finding that they are unlawful, including the section 111(d) emission guidelines for existing fossil fuel-fired steam generating units (coal-fired power plants), the CCS-based standards for coal-fired steam generating units undertaking a large modification, and the CCS-based standards for new base-load stationary combustion turbines (i.e., those operating at greater than 40% annual capacity factors).

This targeted approach would eliminate the CCS and natural gas co-firing technology-based pollution limits that would apply to both existing coal-fired power plants and new gas-fired combustion turbine power plants.

However, efficiency-based standards for new combustion turbines would remain in place under this alternative proposal.

EPA’s proposed rule to repeal the 2024 GHG regulations was published in the Federal Register on June 17, 2025.

Comments were due by August 7, 2025.

We cannot predict the outcome of future rulemaking or other regulatory proceedings aimed at changing or eliminating the current EPA emission standards for power plants.

If this regulation remains in effect, it will likely lead to a material increase in APS’s costs to build, operate, and maintain new, frequently operated gas-fired power plants.

The regulatory deadlines in 2032 by which new, frequently operated gas-fired power plants must install carbon capture and sequestration and achieve 90% capture efficiency may not be feasible.

Future resource plans and procurement efforts implicating the development of such new generation remains pending and, as such, at this time APS is not able to quantify the financial impact associated with EPA’s GHG regulations for power plants.

Further changes to these regulations may also face judicial review.

APS cannot predict the outcome of any such litigation.

Effluent Limitation Guidelines

EPA published effluent limitation guidelines (“ELG”) on October 13, 2020, and, based off those guidelines, APS completed a National Pollutant Discharge Elimination System (“NPDES”) permit modification for Four Corners on December 1, 2023.

EPA published ELG on October 13, 2020, and, based off those guidelines, APS completed a NPDES permit modification for Four Corners on December 1, 2023.

The ELG standards finalized in October 2020 relaxed the “zero discharge” standard for bottom ash transport waters EPA finalized in September 2015.

However, on April 25, 2024, EPA finalized new ELG regulations that once again require “zero discharge” standards for flows of bottom ash transport water at power plants like Four Corners.

Nonetheless, for power plants that permanently cease operations by December 31, 2034, such facilities can continue to comply with the 2020 ELG standards.

APS is currently evaluating its

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compliance options for Four Corners based on the ELG regulations finalized in April 2024 and is assessing what impacts the new standards will have on our financial condition, results of operations, or cash flows.

“zero discharge” standards for flows of bottom ash transport water at power plants like Four Corners.

For power plants that permanently cease operations by December 31, 2034, such facilities can continue to comply with the 2020 ELG standards.

APS is currently evaluating its compliance options for Four Corners based on the ELG regulations finalized in April 2024 and is assessing what impacts the new standards will have on our financial condition, results of operations, or cash flows.

On December 31, 2025, EPA published a final rule extending by five years the compliance deadlines for achieving the 2024 zero-discharge standards for bottom ash transport wastewater from year-end 2029 to year-end 2034, among other changes to the 2024 rulemaking.

EPA is also collecting additional information on zero-discharge technologies, including cost and performance data, to inform future potential rulemakings to modify or relax the current zero-discharge ELG standards.

We cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at modifying the current ELG standards.

EPA Good Neighbor Proposal for Arizona

On March 15, 2023, EPA issued its final Good Neighbor Plan for 23 states in order to ensure that the cross-state transport of ozone forming emissions does not interfere with downwind state compliance with the National Ambient Air Quality Standards (“NAAQS”).

Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for nitrogen oxide (“NOx”) emissions.

Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for NOx emissions.

While Arizona was not among the 23 states subject to EPA’s March 2023 final action, EPA announced on January 23, 2024, that it was proposing to add Arizona and New Mexico (along with two other additional states) to EPA’s NOx emission allowance trading program finalized last year.

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In addition, on December 19, 2024, EPA announced that it was withdrawing its proposal to add Arizona (along with other western states) to the federal Good Neighbor Plan.

As such, while EPA may elect to resume work on and finalize this proposal in the future, it is unlikely to do so over a near-term horizon.

APS cannot predict the outcome of any future EPA efforts to add Arizona to the federal Good Neighbor Plan (which depends on action disapproving the Arizona State Implementation Plan) or whether the Good Neighbor Plan itself will remain in effect pending the outcome of judicial review in the D.C.

Circuit Court of Appeals.

Should the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have material impact on both the costs to operate current APS power plants and APS’s ability to develop new thermal generation to serve load.

On March 12, 2025, EPA announced its intention to reconsider the Good Neighbor Plan and on January 30, 2026, EPA published a proposed rule in the Federal Register that would approve Arizona’s and New Mexico’s State Implementation Plans concerning the cross-state transport of ozone forming emissions.

Such approval, if finalized as proposed, would remove APS’s operations in Arizona and New Mexico from the scope of future efforts to regulate such emissions.

APS cannot predict the outcome of this pending regulatory action nor when EPA may take final action on this proposal.

If finalized as proposed, this action would then be subject to judicial review and APS cannot predict the outcome of such litigation, if any arises.

In addition, APS cannot predict the outcome of any future EPA efforts to add Arizona or New Mexico to a future federal program addressing the cross-state transport of ozone-forming emissions.

Should a federal program like the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have material impact on both the costs to operate current APS power plants and APS’s ability to develop new thermal generation to serve load.

At this time, APS cannot predict the impact on the Company’s financial condition, results of operations, or cash flows.

Revised Mercury and Air Toxics Standard (“MATS”) Proposal.

On April 25, 2024, EPA finalized revisions to the existing MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants.

The final regulations increase the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and require the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing).

These final regulations will take effect for existing coal-fired power plants, such as Four Corners, within three years of publication in the Federal Register.

Based on APS’s assessment of the revised MATS regulations, this final rule is unlikely to have a material impact on plant operations or require significant capital expenditures to ensure compliance.

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Revised Mercury and Air Toxics Standard Proposal

On February 20, 2026, EPA issued a final rule repealing the 2024 revisions to MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants.

The repeal of the 2024 amendment means that MATS regulations revert to the pre-existing framework for MATS emission limits established in 2012.

As a result, the 2024 revisions that would have increased the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and required the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing) will not take effect for existing coal-fired power plants, such as Four Corners.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.

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The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.

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APS would seek recovery in rates for the book value of any remaining investments in the plants, as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit

The latest NPDES permit for Four Corners was issued on September 30, 2019.

Based upon a November 1, 2019, filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit.

The EAB denied the environmental group petition on September 30, 2020.

While on January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S.

Court of Appeals for the Ninth Circuit, the parties to the litigation (including APS) finalized a settlement on May 2, 2022.

This settlement requires investigation of thermal wastewater discharges from Four Corners, administratively closes the litigation filed in January 2021, and APS does not expect the outcome to have a material impact on its financial condition, results of operations, or cash flows.

BCE Kūpono Solar

BCE and Ameresco jointly owned a special purpose entity that sponsored the Kūpono Solar Project.

This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that supplies energy and capacity under a 20 -year power purchase agreement with Hawaiian Electric Company, Inc.

The Kūpono Solar Project achieved commercial operations in June 2024.

On April 18, 2023, the Kūpono special purpose entity entered into a $ 140 million non-recourse construction financing agreement.

On August 14, 2024, the construction financing converted into long-term financing in the form of a sale-leaseback.

In connection with the project financing, Pinnacle West issued performance guarantees relating to the Kūpono Solar Project.

Investments in the Kūpono Solar Project were included in the BCE Sale which closed on January 12, 2024, and as a result of the BCE Sale, Pinnacle West holds no equity or ownership interest in the Kūpono Solar Project.

As of December 31, 2024, Pinnacle West continues to maintain performance guarantees relating to the Kūpono Solar Project sale-leaseback financing (see additional information below regarding these guarantees).

See Note 20 for information relating to the BCE Sale.

APS would seek recovery in rates for the book value of an y remaining investments in the plants, as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Financial Assurances

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These instruments support commodity contract collateral obligations and other transactions.

As of December 31, 2024, standby letters of credit totaled approximately $ 18 million and surety bonds totaled approximately $ 23 million;

both will expire through 2025.

As of December 31, 2025, standby letters of credit totaled approximately $ 30.4 million and will expire through 2026, and surety bonds totaled approximately $ 23.3 million and will expire through 2028.

The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable.

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We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.

Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.

Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be

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reasonably estimated.

Most significantly, APS has agreed to indemnify the equity participants and other parties in the remaining Palo Verde sale leaseback transaction with respect to certain tax matters.

Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.

Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2024.

In connection with the sale of 4C Acquisition, LLC’s 7 % interest to Navajo Transitional Energy Corporation (“NTEC”), Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners.

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material as of December 31, 2025.

In connection with the sale of Pinnacle West’s wholly-owned subsidiary, 4C Acquisition, LLC’s 7 % interest in Units 4 and 5 of Four Corners to NTEC, Pinnacle West guaranteed certain obligations that NTEC has to the other owners of Four Corners.

Pinnacle West has not needed to perform under this guarantee.

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however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with PNW Power’s investments in minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has guaranteed the obligations of PNW Power to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”).

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In connection with PNW Power’s investments in minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has guaranteed the obligations of PNW Power to make PTC funding payments to borrowers of the projects (the “PTC Guarantees”).

The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements.

As of December 31, 2024, there is approximately $ 29 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2031.

Pinnacle West has issued various performance guarantees in connection with the Kūpono Solar Project investment financing and is exposed to losses relating to these guarantees upon the occurrence of certain events that we consider to be remote.

Subsequent to the BCE Sale, Pinnacle West continues to maintain these guarantees.

As of December 31, 2025, there is approximately $ 26.3 million remaining relating to these PTC Guarantees that are expected to terminate by 2031.

Pinnacle West issued various performance guarantees in connection with a joint venture project, the Kūpono Solar Project, by Pinnacle West’s BCE subsidiary.

BCE was sold to Ameresco in 2024 (the “BCE Sale”).

Subsequent to the BCE Sale, Pinnacle West continues to maintain these Kūpono Solar Project investment financing guarantees and is exposed to losses relating to these guarantees upon the occurrence of certain events that we consider to be remote.

Under the Kūpono Solar Project sale-leaseback financing, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events, such as uninsured loss events.

Ameresco, the owner of the Kūpono Solar Project, has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030.

Pinnacle West has not needed to perform under these guarantees.

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We consider the fair value of these guarantees, including expected credit losses, to be immaterial.

The details of the guarantees are as follows:

• Pinnacle West committed to certain performance guarantees tied to the Kūpono Solar Project achieving certain construction and operation milestones.

These performance guarantees expired in August 2024.

Pinnacle West has no on-going exposure under these construction-related guarantees.

• Under the Kūpono Solar Project sale-leaseback financing, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events, such as uninsured loss events.

Ameresco has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030.

Asset Retirement Obligations

In 2024 , the Company revised its cost estimates for existing AROs for the following:

• Cholla coal-fired power plant related to the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $ 63 million, primarily due to cost estimates associated with the CCR Rule.

• Four Corners coal-fired power plant, which resulted in an increase of approximately $ 82 million, primarily due to cost estimates associated with the CCR Rule.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• Navajo, a decommissioned coal-fired power plant, which resulted in an increase of approximately $ 8 million.

• Palo Verde nuclear plant, which resulted in an increase of approximately $ 1 million.

• Solar, which resulted in a decrease to the ARO of approximately $ 11 million, primarily due to the reduced cost of solar panel disposal.

APS has also recorded the initial investigation and assessment costs related to the newly signed EPA rule for Legacy Impoundments and CCRMUs.

At this time, APS is still estimating the financial impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2026 and final site investigation reports to be finalized by February 2027.

Based on the information available to APS at this time, APS cannot reasonably estimate the fair value of the entire CCRMU asset retirement obligation.

In 2023 , the Company revised its cost estimates for existing ARO for the following:

• Cholla coal-fired power plant related to the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $ 71 million, primarily due to changes in the planned pond closure methodology and increased corrective action cost estimates associated with the CCR Rule.

• Four Corners coal-fired power plant, which resulted in a decrease of approximately $ 7 million.

• Navajo coal-fired plant, a decommissioned coal-fired power plant, which resulted in an increase of approximately $ 8 million.

• Palo Verde received a new decommissioning study, which resulted in an increase to the ARO in the amount of $ 63 million, an increase in the plant in service of $ 59 million and a decrease in the regulatory liability of $ 4 million.

See additional details in Notes 3 and 10 .

The following table shows the change in our asset retirement obligations (dollars in thousands):

Asset retirement obligations at the beginning of year

Other Income and Other Expense

The following table provides detail of Pinnacle West’s consolidated other income and other expense for the years ended 2025, 2024, and 2023 (dollars in thousands):

2025 2024 2023

Changes attributable to:

Accretion expense 56,143 44,269

Settlements ( 18,379 ) ( 14,039 )

Estimated cash flow revisions 142,821 135,323

Newly incurred obligation — 2,686

Asset retirement obligations at the end of year

Other income:

Interest income $ 18,037 $ 24,322 (a) $ 27,242 (a)

Investment gain — net (b) 26,720 — —

Gain on sale of BCE (Note 22)

— 22,988 6,205

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.

See Note 3 for detail of regulatory liabilities.

Miscellaneous 4,649 1,304 219

Total other income $ 49,406 $ 48,614 $ 33,666

Other expense:

Non-operating costs $ ( 21,332 ) $ ( 27,370 ) (c) $ ( 15,260 )

Investment losses — net — ( 1,418 ) ( 3,402 )

Miscellaneous ( 8,933 ) ( 5,348 ) ( 6,394 )

Total other expense $ ( 30,265 ) $ ( 34,136 ) $ ( 25,056 )

(a) 2023 and 2024 Interest income is primarily related to PSA interest.

(b) Investment gain is primarily related to El Dorado’s equity investment in SAI.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides detail of APS’s other income and other expense for the years ended 2025, 2024, and 2023 (dollars in thousands):

2025 2024 2023

Other income:

Interest income $ 15,933 $ 21,088 (a) $ 26,853 (a)

Miscellaneous 281 6 219

Total other income $ 16,214 $ 21,094 $ 27,072

Other expense:

Non-operating costs $ ( 19,650 ) $ ( 26,588 ) (b) $ ( 14,070 )

Miscellaneous ( 6,732 ) ( 3,110 ) ( 4,194 )

Total other expense $ ( 26,382 ) $ ( 29,698 ) $ ( 18,264 )

(a) 2023 and 2024 Interest income is primarily related to PSA interest.

(b) The 2024 Non-operating cost is primarily related to corporate giving.

Common Stock Equity and Earnings Per Share

At-the-Market Program

On November 8, 2024, Pinnacle West opened its ATM Program, pursuant to which Pinnacle West may sell, from time to time, up to $ 900 million of its common stock through an at-the-market equity distribution program, which includes the ability to enter into forward sale agreements.

Approximately $ 700 million of common stock is available to be sold under the ATM Program, which takes into account the forward sale agreements in effect as of December 31, 2025.

As of December 31, 2025, Pinnacle West had four outstanding forward sale agreements under its ATM Program (collectively, the “ATM Forward Sale Agreements”).

These agreements relate to approximately $ 200 million of common stock and may be settled at Pinnacle West’s discretion by issuing shares at the applicable forward sales price or, alternatively, by delivering cash in lieu of shares.

Pinnacle West also entered into a contract to begin a fifth ATM forward sale agreement in December 2025, transacting a total of $ 10.7 million with an effective date of January 5, 2026, and a maturity date of July 2, 2027.

The following table presents information about the outstanding ATM Forward Sale Agreements, including details of the outstanding forward sale agreements as of December 31, 2025:

ATM Forward Sale Agreements Maturity Date Number of Shares Forward Sales Price Per Share (a) Aggregate Value

(in thousands)

November 2024 June 30, 2026 552,833 $ 89.73 $ 49,606

March 2025 September 14, 2026 544,959 $ 90.83 $ 49,499

August 2025 February 16, 2027 543,001 $ 91.21 $ 49,527

September 2025 February 22, 2027 558,622 $ 88.69 $ 49,544

2,199,415 $ 90.10 (b) $ 198,176

(a) Subject to certain adjustments.

(b) Weighted-average price for the total ATM Program.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Non-ATM February 2024 Forward Sale Agreements

In addition to the ATM Forward Sale Agreements, Pinnacle West also has Forward Sale Agreements that were entered into on February 28, 2024 (the “February 2024 Forward Sales Agreements”).

These agreements may be settled at Pinnacle West’s discretion by issuing shares of Pinnacle West common stock and receiving cash, if any, at the then-applicable forward sales price.

The terms of the February 2024 Forward Sale Agreements also allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.

The February 2024 Forward Sale Agreements were partially settled in December 2024, September 2025, and December 2025.

In August 2025, APS amended the February 2024 Forward Sale Agreements with Wells Fargo Bank, National Association, to extend the maturity date of those forward confirmations to December 31, 2026.

The following table presents information about the outstanding February 2024 Forward Sale Agreements as of December 31, 2025 (dollars in thousands, except price per share):

February 2024 Forward Sale Agreements Number of Shares Forward Sales Price Per Share Aggregate Value

Initial Price 11,240,601 $ 64.51 (a) $ 725,131

December 23, 2024 5,377,115 (b) $ 64.17 $ 345,049 (c)

September 4, 2025 243,186 (b) $ 63.12 $ 15,350 (c)

December 18, 2025 1,193,950 (b) $ 62.82 $ 75,004 (c)

(a) Subject to certain adjustments.

(b) Physical delivery.

Convertible Notes

In June 2024, Pinnacle West issued $ 525 million of 4.75 % Convertible Senior Notes due 2027, which are senior unsecured obligations of Pinnacle West and will mature on June 15, 2027.

Interest is payable semiannually in arrears on June 15 and December 15 of each year, beginning on December 15, 2024.

Prior to March 15, 2027, the holders of the Convertible Notes may elect at their option to convert all or any portion of their Convertible Notes under the following limited circumstances:

• during the five business day period after any 10 consecutive trading day period (“Measurement Period”) in which the trading price per $1,000 principal amount of Convertible Notes for each

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

trading day of the Measurement Period was less than 98 % of the product of the last reported sale price of Pinnacle West common stock and the conversion rate on such trading day;

• upon the occurrence of certain corporate events, as defined in the Convertible Notes’ indenture.

On or after March 15, 2027, until the maturity date, the holders of the Convertible Notes may elect at their option to convert all or any portion of their notes.

The conversion rate is not subject to adjustment for any accrued and unpaid interest.

As of December 31, 2025, the conditions allowing holders to convert their Convertible Notes were not met, and as a result, the Convertible Notes were classified as long term debt on Pinnacle West’s Consolidated Balance Sheets with a carrying amount of $ 525 million, net of $ 4 million in unamortized debt issuance costs.

The estimated fair value of the Convertible Notes as of December 31, 2025 was $ 561 million (Level 2 within the fair value hierarchy).

As of December 31, 2025, based on Pinnacle West’s average stock price and the relevant terms of the Convertible Notes, there were no shares of Pinnacles West’s common stock included in basic or diluted EPS relating to the potential conversion of the Convertible Notes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted EPS (dollars in thousands, except earnings per share amounts):

As of December 31,

2025 2024 2023

Net income attributable to common shareholders

$ 616,531 $ 608,806 $ 501,557

Weighted average common shares outstanding — basic 119,687 113,846 113,442

Net effect of dilutive securities:

Contingently issuable performance shares and restricted stock units 568 480 362

Dilutive shares related to equity forward sale agreements (a) 1,716 1,906 —

Total contingently issuable shares 2,284 2,386 362

Weighted average common shares outstanding — diluted 121,971 116,232 113,804

Earnings per weighted-average common share outstanding

Net income attributable to common shareholders — basic

$ 5.15 $ 5.35 $ 4.42

Net income attributable to common shareholders — diluted

$ 5.05 $ 5.24 $ 4.41

(a) For the years ended December 31, 2025, 2024 and 2023 the diluted weighted-average common shares excludes 148,098 , 1,038,463 and 0 shares, respectively relating to the ATM Program and the Convertible Notes.

These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.

Pinnacle West’s forward sale agreements are classified as equity transactions and are not recorded on the Pinnacle West Consolidated Balance Sheets until shares are settled.

Delivery of shares to settle equity forward agreements will result in dilution to basic EPS upon settlement.

Prior to settlement, the potentially issuable shares are reflected in our diluted EPS calculations using the treasury stock method.

Under this method, the number of shares, if any, that would be issued upon settlement is reduced by the number of shares that could be purchased by Pinnacle West in the market with the proceeds received from issuance (based on the average market price during the reporting period).

Share dilution occurs when the average market price of our stock during the reporting period is higher than the adjusted forward sale price as of the end of the reporting period.

On May 21, 2025, Pinnacle West shareholders approved an amendment to the Company’s Articles of Incorporation to increase the number of authorized shares of common stock from 150,000,000 to 300,000,000 .

This amendment was subsequently filed with the ACC on May 22, 2025.

Fair Value Measurements

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Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities;

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See Note 7 for fair value discussion of plan assets held in our retirement and other benefit plans.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Equivalents

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We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.

These include valuation adjustments for liquidity and credit risks.

These include valuation adjustments for

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

liquidity and credit risks.

The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged.

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These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fixed Income Securities

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A primary price source is identified based on asset type, class, or issue of securities.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S.

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The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds.

We may transact in these commingled funds on a semi-monthly basis at the NAV.

We may transact in these commingled funds on a daily basis at the NAV.

The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.

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Fair Value Tables

The following table presents the fair value at December 31, 2024, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

The following table presents the fair value as of December 31, 2025 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1 Level 2 Level 3 Other Total

Cash equivalents $ 23 $ — $ — $ — $ 23

Risk management activities — derivative instruments:

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Other special use funds:

Cash equivalents 25,000 — — — (d) $ 25,000

Equity securities 24,962 — — 2,851 (b,d) 27,813

Equity securities 62,573 — — 3,199 (b) 65,772

Treasury debt 369,055 — — — 369,055

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(d) All amounts relate to APS, with the exception of $ 34.2 million related to Pinnacle West’s Captive investments that are classified within Level 1, $ 25.0 million in cash equivalents and $ 9.2 million related to equity securities.

(d) All amounts relate to APS, with the exception of $ 40.3 million related to Pinnacle West’s Captive investments that are classified within Level 1 equity securities.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Other special use funds:

Equity securities 40,991 — — 2,196 (b) 43,187

Cash equivalents 25,000 — — — (d) 25,000

Equity securities 24,962 — — 2,851 (b) (d) 27,813

Treasury debt 355,544 — — — 355,544

Subtotal other special use funds 360,585 — — 2,196 362,781

Subtotal other special use funds (d) 405,506 — — 2,851 408,357

Total assets $ 784,784 $ 490,338 $ 7,176 $ 425,485 $ 1,707,783

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Fair Value Measurements Classified as Level 3

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however, significant changes in these inputs could also result in higher or lower fair value measurements.

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2024, and December 31, 2023:

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments as of December 31, 2025 and December 31, 2024 (dollars in thousands):

December 31, 2025

Fair Value (thousands) Valuation Significant Weighted-Average

Fair Value Valuation Significant Weighted-Average

Commodity Contracts Assets Liabilities Technique Unobservable Input Range (b)

Electricity Forward Contracts (a) $ — $ 21,913 Discounted cash flows Electricity forward price (per MWh) $ 41.51

Natural Gas Forward Contracts (a) 6,468 325 Discounted cash flows Natural gas forward price (per MMBtu) $( 0.89 )

Natural Gas Forward Contracts (a) — 1,797 Discounted cash flows Natural gas forward price (per Million British Thermal Units (“MMBtu”)) $( 0.07 )

Total $ — $ 23,710

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December 31, 2024

Fair Value (thousands) Valuation Significant Weighted-Average

Fair Value Valuation Significant Weighted-Average

Commodity Contracts Assets Liabilities Technique Unobservable Input Range (b)

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Financial Instruments Not Carried at Fair Value

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy.

The carrying values of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy.

See Note 6 for our long-term debt fair values.

Common Stock Equity and Earnings Per Share

On November 8, 2024, Pinnacle West entered into an equity distribution sales agreement, pursuant to which Pinnacle West may sell, from time to time, up to $ 900 million of its common stock through an ATM program, which includes the ability to enter into forward sale agreements.

As of December 31, 2024 , approximately $ 850 million of common stock is available to be issued under the ATM Program, which takes into account the forward sale agreement in effect as of December 31, 2024 .

As of December 31, 2024 , Pinnacle West had an outstanding forward sale agreement under the ATM program relating to approximately $ 50 million of common stock (the “November 2024 ATM Forward Sale Agreement”).

The November 2024 ATM Forward Sale Agreement may be settled at Pinnacle West’s discretion no later than June 30, 2026.

On a given settlement date, Pinnacle West will issue shares of common at the then-applicable forward sales price.

The terms of the November 2024 ATM Forward Sale Agreement also allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.

The initial forward sales price for the November 2024 ATM Forward Sale Agreement was approximately $ 89.73 , subject to certain adjustments.

On December 31, 2024 , Pinnacle West could have settled the outstanding November 2024 ATM Forward Sale Agreement with the physical delivery of 552,833 shares of Pinnacle West common stock in exchange for cash of approximately $ 50 million .

As of December 31, 2024 , Pinnacle West has not received any proceeds relating to the November 2024 Forward

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Sale Agreement.

Pinnacle West will receive proceeds, if any, when settlement occurs, and will record the proceeds, if any, in equity.

Non-ATM February 2024 Forward Sale Agreements

On February 28, 2024, Pinnacle West executed equity forward sale agreements, relating to 11,240,601 shares of Pinnacle West common stock (“February 2024 Forward Sale Agreements”).

The February 2024 Forward Sale Agreements may be settled at our discretion no later than September 4, 2025, and were not issued under the ATM program discussed above.

On a settlement date, Pinnacle West will issue shares of Pinnacle West common stock and receive cash, if any, at the then-applicable forward sales price.

The terms of the February 2024 Forward Sale Agreements also allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.

The initial forward sales price for the February 2024 Forward Sale Agreements was initially, approximately $ 64.51 per share and is subject to adjustment based on the terms of the agreements.

In December 2024, Pinnacle West partially settled the February 2024 Forward Sale Agreements with the issuance of 5,377,115 shares of common stock and received net proceeds of $ 345 million.

The proceeds were recorded in equity.

At December 31, 2024, Pinnacle West could have settled the remaining February 2024 Forward Sale Agreements with the issuance of 5,863,486 shares of common stock in exchange for cash of $ 377 million.

We will not receive any additional proceeds, if any, from the February 2024 Forward Sale Agreements until settlement occurs.

Convertible Notes

In June 2024, Pinnacle West issued $ 525 million of 4.75 % convertible senior notes that will mature on June 15, 2027.

The Convertible Notes conversion options are indexed to Pinnacle West’s common stock.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted EPS (in thousands, except per share amounts):

2024 2023 2022

Net income attributable to common shareholders $ 608,806 $ 501,557 $ 483,602

Weighted average common shares outstanding — basic 113,846 113,442 113,196

Net effect of dilutive securities:

Contingently issuable performance shares and restricted stock units 480 362 220

Dilutive shares related to equity forward sale agreements (a) 1,906 — —

Total contingently issuable shares 2,386 362 220

Weighted average common shares outstanding — diluted 116,232 113,804 113,416

Earnings per weighted-average common share outstanding

Net income attributable to common shareholders — basic $ 5.35 $ 4.42 $ 4.27

Net income attributable to common shareholders — diluted $ 5.24 $ 4.41 $ 4.26

(a) For the years ended December 31, 2024, 2023 and 2022, diluted weighted average common shares excludes 1,038,463 , 0 and 0 shares, respectively, relating to the Convertible Notes and the ATM equity forward.

These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.

The November 2024 ATM Forward Sale Agreements and the February 2024 Forward Sale Agreements are classified as equity transactions, and are not recorded on the Pinnacle West Consolidated Balance Sheets.

Delivery of shares to settle equity forward agreements result in dilution to basic earnings per share (EPS) upon settlement.

Prior to settlement, the potentially issuable shares are reflected in our diluted EPS calculations using the treasury stock method.

Under this method, the number of shares, if any, that would be issued upon settlement less that number of shares that could be purchased by Pinnacle West in the market with the proceeds received from issuance (based on the average market price during the reporting period).

Share dilution occurs when the average market price of our stock during the reporting period is higher than the adjusted forward sale price as of the end of the reporting period.

Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key employees, and non-officer members of the Board of Directors.

The 2021 Plan authorizes up to 4.3 million common shares to be available for grant.

As of December 31, 2024, 2.9 million common shares were available for issuance under the 2021 Plan.

During 2024, 2023 and 2022, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares.

No new awards may be granted under the 2012 or 2007 Plans.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation Expense and Activity

Compensation cost included in net income for stock-based compensation plans was $ 24 million in 2024, $ 17 million in 2023, and $ 16 million in 2022.

The compensation cost capitalized is immaterial for all years.

Income tax benefits related to stock-based compensation arrangements were $ 6 million in 2024, $ 3 million in 2023, and $ 2 million in 2022.

As of December 31, 2024, there were approximately $ 38 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements.

We expect to recognize these costs over a weighted-average period of two years.

The total fair value of shares vested was $ 24 million in 2024, $ 24 million in 2023, and $ 25 million in 2022.

The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years:

Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b)

2024 2023 2022 2024 2023 2022

Units granted 261,808 192,295 174,791 225,516 202,562 208,736

Weighted-average grant date fair value $ 71.10 $ 74.32 $ 69.66 $ 72.89 $ 79.61 $ 77.63

(a) The Units granted does not include awards that will be cash settled in 2024, 2023 or 2022.

See below for additional information on restricted stock unit grants.

(b) Reflects the target payout level.

The following table shows the change of nonvested awards:

Restricted Stock Units, Stock Grants, and Stock Units Performance Shares

Shares Weighted-Average

Fair Value Shares (b) Weighted-Average

Nonvested at December 31, 2023

374,367 $ 73.29 347,283 $ 77.29

Granted 261,808 71.10 225,516 72.89

Vested ( 155,345 ) 74.54 ( 165,194 ) 76.55

Forfeited (c) ( 20,039 ) 71.32 ( 17,054 ) 75.69

Nonvested at December 31, 2024

460,791 (a) 71.72 390,551 77.29

Vested Awards Outstanding at December 31, 2024

70,851 165,194

(a) Includes 11,750 of awards that will be cash settled.

(b) The performance shares are reflected at target payout level.

Share-based liabilities paid relating to restricted stock units were $ 8 million, $ 6 million, and $ 3 million in 2024, 2023 and 2022, respectively.

This includes cash used to settle restricted stock units of $ 2

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million, $ 3 million, and $ 3 million in 2024, 2023 and 2022, respectively.