What changed in this filing

/stocks — the workspaceLOADING

Item 8. Financial Statements and Supplementary Data

2025-02-25 compared with 2024-02-27 · 797 added, 680 removed, 2398 unchanged (38% of the section changed)

26 unchanged sentences

Fair Value Measurements

Earnings Per Share

Common Stock Equity and Earnings Per Share

Stock-Based Compensation

1 unchanged sentence

Other Income and Other Expense

Palo Verde Sale Leaseback Variable Interest Entities

Variable Interest Entities

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

54 unchanged sentences

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.

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:

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) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

1 unchanged sentence

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.

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 regulatory environment changes, and recent rate orders specific to APS and to other regulated entities in the same jurisdiction.

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.

Management judgments also include assessing the impact of potential ACC-ordered refunds to customers on regulatory liabilities.

8 unchanged sentences

• 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 and compared to management’s recorded regulatory assets and liabilities for completeness.

• We observed the ACC Open Meeting during which the Recommended Order and Opinion regarding the 2022 Retail Rate Case was amended and approved and read the approved 2022 Rate Case Recommended Order and Opinion as amended.

We obtained and evaluated management’s internally prepared analysis regarding impacts of the approved 2022 Rate Case Recommended Order and Opinion as amended to rates and recorded balances.

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 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.

/s/ Deloitte & Touche LLP

14 unchanged sentences

Taxes other than income taxes 227,395 224,013 220,370

Other expenses 1,913 2,494 6,393

Other expense 2,389 1,913 2,494

Total 4,112,852 3,871,351 3,592,474

OPERATING INCOME

1,012,063 824,640 731,911

OTHER INCOME (DEDUCTIONS)

14 unchanged sentences

INCOME BEFORE INCOME TAXES

736,559 595,693 575,653

INCOME TAXES (Note 4)

110,529 76,912 74,827

NET INCOME 518,781 500,826 635,944

626,030 518,781 500,826

Net income attributable to noncontrolling interests (Note 17)

1 unchanged sentence

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS

$ 608,806 $ 501,557 $ 483,602

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC 113,846 113,442 113,196

2 unchanged sentences

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

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

4 unchanged sentences

2024 2023 2022

NET INCOME $ 518,781 $ 500,826 $ 635,944

$ 626,030 $ 518,781 $ 500,826

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX

Derivative instruments:

Net unrealized gain, net of tax expense of $ 234 , $ 615 , and $ 360

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

( 891 ) 713 1,873

2 unchanged sentences

Total other comprehensive income (loss)

2,202 ( 1,709 ) 23,426

COMPREHENSIVE INCOME

628,232 517,072 524,252

Comprehensive income attributable to noncontrolling interests

17,224 17,224 17,224

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS

$ 611,008 $ 499,848 $ 507,028

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

9 unchanged sentences

Materials and supplies (at average cost) 469,022 444,344

Fossil fuel (at average cost) 49,203 40,155

Income tax receivable (Note 4)

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

Assets from risk management activities (Note 15)

145 unchanged sentences

Short-term borrowings and (repayments) — net ( 241,050 ) 241,900 48,720

Short-term debt repayments under revolving credit facility — — ( 19,000 )

Short-term debt borrowings under term loan facility 550,000 — —

Short-term debt repayments under term loan facility ( 350,000 ) — —

Dividends paid on common stock ( 394,663 ) ( 386,486 ) ( 378,881 )

Common stock equity issuance and purchases — net 341,429 ( 4,093 ) ( 2,653 )

Distributions to noncontrolling interests ( 21,255 ) ( 21,255 ) ( 21,255 )

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

Net cash provided by financing activities 322,690 486,675 371,468

10 unchanged sentences

113,014,528 $ 2,702,743 ( 87,608 ) $ ( 6,401 ) $ 3,264,719 $ ( 54,861 ) $ 115,260 $ 6,021,460

Net income — — 618,720 — 17,224 635,944

— — 483,602 — 17,224 500,826

Other comprehensive income

9 unchanged sentences

113,247,189 2,724,740 ( 73,613 ) ( 5,005 ) 3,360,347 ( 31,435 ) 111,229 6,159,876

Net income — — 483,602 — 17,224 500,826

Other comprehensive income

— — 501,557 — 17,224 518,781

Other comprehensive loss

— — — ( 1,709 ) — ( 1,709 )

Dividends on common stock ($ 3.49 per share)

7 unchanged sentences

113,537,689 2,752,676 ( 113,272 ) ( 8,185 ) 3,466,317 ( 33,144 ) 107,198 6,284,862

Net income — — 501,557 — 17,224 518,781

Other comprehensive loss

— — 608,806 — 17,224 626,030

Other comprehensive income

— — — 2,202 — 2,202

Dividends on common stock ($ 3.55 per share)

— — ( 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

(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.

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

68 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 and compared to management’s recorded regulatory assets and liabilities for completeness.

We obtained and evaluated management’s internally prepared analysis regarding impacts of the approved 2022 Rate Case Recommended Order and Opinion as amended to rates and recorded balances.

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 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.

/s/ Deloitte & Touche LLP

17 unchanged sentences

OPERATING INCOME

1,018,848 839,931 744,941

OTHER INCOME (DEDUCTIONS)

14 unchanged sentences

INCOME BEFORE INCOME TAXES

786,142 658,745 632,953

INCOME TAXES (Note 4)

126,993 94,184 90,800

NET INCOME 564,561 542,153 649,503

Net income attributable to noncontrolling interests

659,149 564,561 542,153

Net income attributable to noncontrolling interests (Note 17)

17,224 17,224 17,224

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER

$ 641,925 $ 547,337 $ 524,929

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

4 unchanged sentences

2024 2023 2022

NET INCOME $ 564,561 $ 542,153 $ 649,503

$ 659,149 $ 564,561 $ 542,153

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX

2 unchanged sentences

Total other comprehensive income (loss)

3,103 ( 1,623 ) 19,284

COMPREHENSIVE INCOME

662,252 562,938 561,437

Comprehensive income attributable to noncontrolling interests

17,224 17,224 17,224

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER

$ 645,028 $ 545,714 $ 544,213

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

70 unchanged sentences

Current maturities of long-term debt (Note 6)

300,000 250,000

Accounts payable 481,955 433,229

75 unchanged sentences

Issuance of long-term debt 445,842 496,025 524,852

Repayment of long-term debt ( 250,000 ) — —

Short-term borrowings and (repayments) — net ( 192,950 ) 180,970 46,300

Short-term debt borrowings under term loan facility 350,000 — —

Short-term debt repayments under term loan facility ( 350,000 ) — —

Dividends paid on common stock ( 401,400 ) ( 393,600 ) ( 385,800 )

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

Noncontrolling interests ( 21,255 ) ( 21,255 ) ( 21,255 )

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

Net cash provided by financing activities 375,237 412,140 314,097

11 unchanged sentences

Equity infusion from Pinnacle West — 150,000 — — — 150,000

Net income — — 632,279 — 17,224 649,503

— — 524,929 — 17,224 542,153

Other comprehensive income

2 unchanged sentences

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

Other — — 1 — 1 2

Balance, December 31, 2022

1 unchanged sentence

Equity infusion from Pinnacle West — 150,000 — — — 150,000

Net income — — 524,929 — 17,224 542,153

Other comprehensive income

— — 547,337 — 17,224 564,561

Other comprehensive loss

— — — ( 1,623 ) — ( 1,623 )

Dividends on common stock — — ( 395,500 ) — — ( 395,500 )

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

Other — — ( 2 ) — — ( 2 )

Balance, December 31, 2023

1 unchanged sentence

Equity infusion from Pinnacle West — 795,000 — — — 795,000

Net income — — 547,337 — 17,224 564,561

Other comprehensive loss

— — 641,925 — 17,224 659,149

Other comprehensive income

— — — 3,103 — 3,103

Dividends on common stock — — ( 408,800 ) — — ( 408,800 )

17 unchanged sentences

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:

APS, El Dorado, BCE and PNW Power.

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”).

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

5 unchanged sentences

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

See Note 17 for additional information.

We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE.

As of December 31, 2023, the captive cell’s activities are insignificant to our consolidated financial statements.

Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

Accounting Records and Use of Estimates

1 unchanged sentence

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.

Actual results could differ from

Actual results could differ from those estimates.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

those estimates.

To conform with the current year’s disaggregated presentation of significant changes in assets and liabilities and the aggregation of less significant changes in assets and liabilities, we made certain reclassifications for the year ended December 31, 2022, within the operating activities section of our Consolidated Statements of Cash Flows.

Regulatory Accounting

APS is regulated by the ACC and the FERC.

APS is regulated by the ACC and FERC.

The accompanying financial statements reflect the rate-making policies of these commissions.

20 unchanged sentences

We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Certain cost recovery mechanisms may qualify as alternative revenue programs.

1 unchanged sentence

See Notes 2 and 3 for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Allowance for Doubtful Accounts

2 unchanged sentences

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.

See Note 2 for additional information.

Property, Plant and Equipment

12 unchanged sentences

Plant in service and held for future use 25,860,950 24,211,167

24,211,167 22,452,146

Accumulated depreciation and amortization ( 9,027,426 ) ( 8,408,040 )

15,803,127 14,522,268

Net 16,833,524 15,803,127

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

4 unchanged sentences

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.

1 unchanged sentence

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

See Note 11 for additional information.

16 unchanged sentences

The Palo Verde ARO primarily relates to final plant decommissioning.

This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.

This obligation is based on the NRC’s requirements for disposal of irradiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.

The non-nuclear generation AROs primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures.

6 unchanged sentences

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.

Both the debt and equity

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

components of AFUDC are non-cash amounts within the Consolidated Statements of Income.

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

AFUDC was calculated by using a composite rate of 6.23 % for 2024, 6.29 % for 2023, and 5.75 % for 2022.

22 unchanged sentences

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.

When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

information, or prices provided by other external sources.

When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.

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.

16 unchanged sentences

Unless otherwise required by GAAP, legal fees are expensed as incurred.

The Captive’s contingent losses may include an amount for losses incurred but not reported (“IBNR”).

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.

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

Retirement Plans and Other Postretirement Benefits

3 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

13 unchanged sentences

See Note 4 for additional discussion.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash and Cash Equivalents

8 unchanged sentences

Accrued capital expenditures $ 257,494 $ 206,269 $ 114,999

Dividends declared but not paid 99,813 97,895 95,988

Dividends accrued but not yet paid 106,592 99,813 97,895

BCE Sale non-cash consideration (Note 20)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):

6 unchanged sentences

Accrued capital expenditures $ 257,494 $ 206,269 $ 116,533

Dividends declared but not paid 99,800 97,900 96,000

Dividends accrued but not yet paid 107,200 99,800 97,900

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets.

We have separately disclosed intangible assets on Pinnacle West’s Consolidated Balance Sheets.

The intangible assets relate primarily to APS’s internal-use software.

We have no goodwill recorded.

The intangible assets are amortized over their finite useful lives.

4 unchanged sentences

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 20 % ownership and no significant influence).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PNW Power holds investments in equity securities.

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 20 % ownership and no significant influence).

Our investments in the nuclear decommissioning trusts, coal reclamation escrow accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities.

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.

5 unchanged sentences

To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement.

Our incremental borrowing rate is based on the rate of interest we

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments.

8 unchanged sentences

Business Segments

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

All other segment activities are insignificant.

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.

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.

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):

Year Ended December 31,

2024 2023 2022

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

Operating Revenues $ 5,125 $ — $ 5,125 $ 4,696 $ — $ 4,696 $ 4,324 $ — $ 4,324

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 )

Taxes other than income taxes ( 227 ) — ( 227 ) ( 224 ) — ( 224 ) ( 220 ) — ( 220 )

Pension and other postretirement non-service credits, net 49 — 49 42 ( 1 ) 41 99 ( 1 ) 98

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 )

Income Taxes ( 127 ) 16 ( 111 ) ( 94 ) 17 ( 77 ) ( 91 ) 16 ( 75 )

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

Net Income (loss) $ 642 $ ( 33 ) $ 609 $ 547 $ ( 45 ) $ 502 $ 525 $ ( 41 ) $ 484

(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.

December 31, 2024 December 31, 2023

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

Total Assets $ 25,988 $ 115 $ 26,103 $ 24,516 $ 145 $ 24,661

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Preferred Stock

At December 31, 2023, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, no ne 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, no ne of which was outstanding.

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.

Sources of Revenue

9 unchanged sentences

Total Operating Revenues $ 5,124,915 $ 4,695,991 $ 4,324,385

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retail Electric Revenue.

15 unchanged sentences

Revenues from contracts with customers also include wholesale and transmission activities.

Our revenues from contracts with customers for the years ended December 31, 2023, 2022 and 2021 were $ 4,651 million, $ 4,302 million, and $ 3,760 million, respectively.

Our revenues from contracts with customers for the year ended December 31, 2024, 2023 and 2022 were $ 5,073 million, $ 4,651 million, and $ 4,302 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.

For the years ended December 31, 2023, 2022 and 2021, our revenues that do not qualify as revenue from contracts with customers were $ 45 million, $ 22 million and $ 44 million, respectively.

For the year ended December 31, 2024, 2023, and 2022 our revenues that do not qualify as revenue from contracts with customers were $ 52 million, $ 45 million, and $ 22 million, respectively.

This amount includes revenues related to certain regulatory cost recovery mechanisms that are considered alternative revenue programs.

3 unchanged sentences

See Note 3 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Consolidated Balance Sheets as of December 31, 2023 and December 31, 2022.

Allowance for Doubtful Accounts

1 unchanged sentence

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

2 unchanged sentences

2024 2023 2022

Allowance for doubtful accounts, balance at beginning of period $ 23,778 $ 25,354 $ 19,782

Balance at beginning of period $ 22,433 $ 23,778 $ 25,354

Bad debt expense 35,799 23,399 17,006

Actual write-offs ( 33,383 ) ( 24,744 ) ( 18,582 )

Allowance for doubtful accounts, balance at end of period $ 22,433 $ 23,778 $ 25,354

Balance at end of period $ 24,849 $ 22,433 $ 23,778

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 the date rates become effective (“Day 1”) of a net $ 460 million.

This Day 1 net impact represents a total base revenue deficiency of $ 772 million offset by proposed adjustor transfers of cost recovery to annual retail rates and adjustor mechanism modifications.

The average annual customer bill impact of APS’s request on Day 1 is an increase of 13.6 %.

The principal provisions of APS’s application were:

• a test year comprised of twelve months ended June 30, 2022, adjusted as described below;

• an original cost rate base of $ 10.5 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 48.07 % 3.85 %

Common stock equity 51.93 % 10.25 %

Weighted-average cost of capital 7.17 %

• 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 $ 0.038321 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);

• modification of its adjustment mechanisms including:

▪ eliminate the Environmental Improvement Surcharge (“EIS”) and collect costs through base rates,

▪ eliminate the Lost Fixed Cost Recovery (“LFCR”) mechanism and collect costs through base rates and the Demand Side Management Adjustment Charge (“DSMAC”),

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

▪ maintain as inactive the Tax Expense Adjustor Mechanism (“TEAM”),

▪ maintain the Transmission Cost Adjustment (“TCA”) mechanism,

▪ modify the performance incentive in the DSMAC, and

▪ modify the Renewable Energy Adjustment Charge (“REAC”) to include recovery of capital carrying costs of APS owned renewable and storage resources;

• changes to its limited-income program, including a second tier to provide an additional discount for customers with greater need;

• twelve months of post-Test Year plant investments to reflect used and useful projects that will be placed into service prior to July 1, 2023.

On June 5, 2023, and June 15, 2023, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC.

The ACC Staff recommends, among other things, (i) a $ 251 million revenue increase or, as an alternative, a $ 312 million revenue increase, (ii) a 9.6 % return on equity, (iii) a 0.0 % fair value increment or, as an alternative, a 0.75 % fair value increment, and (iv) a continuation of a 12-month post-test year plant.

RUCO recommends, among other things, (i) an $ 84.9 million revenue increase, (ii) an 8.2 % return on equity or, as an alternative, an 8.7 % return on equity if the ACC imputes a hypothetical capital structure with a 46 % equity layer, (iii) a fair value increment of 0.0 %, and (iv) a reduction of post-test year plant to six months.

On July 12, 2023, APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies.

The principal provisions of APS’s rebuttal testimony are:

• reducing the revenue requirement increase to $ 383.1 million, which reduced the average annual customer bill impact to an increase of 11.3 %;

• maintaining a return on equity request of 10.25 %;

• reducing the increment of fair value rate base return to 0.5 % from 1.0 %;

• maintaining a post-test year plant request of 12 months, plus the Four Corners Effluent Limitation Guidelines (“ELG”) project;

• withdrawing the Payment Fee Removal Proposal (net reduction) which was originally requested in APS’s initial application;

• maintaining the LFCR mechanism and DSMAC as separate adjustors;

• increasing the Power Supply Adjustment (“PSA”) annual rate change limit from $ 0.004 /kWh to $ 0.006 /kWh;

• proposing a new System Reliability Benefit (“SRB”) recovery mechanism;

• maintaining the REAC in its current state;

• maintaining adjustor base transfers and elimination of EIS;

• maintaining the request to recover Coal Community Transition (“CCT”) funding.

On July 26, 2023, the ACC Staff, RUCO and other intervenors filed their surrebuttal testimony with the ACC.

The ACC Staff adjusted their initial recommendations to, among other things, (i) a $ 281.9 million revenue increase, (ii) a 9.68 % return on equity, (iii) a 0.5 % fair value increment, (iv) a continuation of a 12-month post-test year plant that includes the Four Corners ELG project, and (v) support of an increase to the annual PSA increase limit to $ 0.006 /kWh.

RUCO maintained their direct position and also recommended further review of the PSA in a second phase of the 2022 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”).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On August 4, 2023, APS filed rejoinder testimony addressing the ACC Staff and intervenors’ surrebuttal testimonies.

APS’s rejoinder testimony included final post-Test Year Plant values, reducing the revenue requirement increase to $ 377.7 million from $ 383.1 million, which reduced the average annual customer bill impact to an increase of 11.2 %.

All other major provisions from APS’s rebuttal testimony were maintained in its rejoinder testimony.

On November 6, 2023, and November 21, 2023, APS and stakeholders filed briefs in the 2022 Rate Case.

APS’s briefs included the reduction of the total revenue requirement increase to $ 376.2 million and a resulting average annual customer bill impact increase of 11.1 %.

All other major provisions from APS’s rejoinder testimony were maintained in its briefs.

ACC Staff’s briefs included a proposed total revenue requirement increase from $ 281.9 million to $ 282.7 million and also included their support of APS’s SRB mechanism, contingent on increased stakeholder outreach.

On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order 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-test year plant and the inclusion of the Four Corners ELG project, (vi) the approval of APS’s SRB proposal with certain procedural and other modifications, (vii) no additional 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 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 (“RFP”), and (viii) recovery of all DSM costs through the DSMAC rather than through base rates.

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.

The ACC is expected to issue the final order for the 2022 Rate Case in March 2024 with the new rates to become effective for all service rendered on or after March 8, 2024.

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.

All other applications for rehearing were denied.

A limited rehearing was held October 28 through November 1.

Following the limited rehearing, an Administrative Law Judge issued a ROO (the “Limited Rehearing ROO”) on December 3, 2024.

The Limited Rehearing ROO recommended affirming the GAC as just and reasonable and that the GAC is not discriminatory to solar customers and the absence of a GAC is not discriminatory to non-solar customers.

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.

APS cannot predict the outcome of these proceedings.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 unchanged sentence

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 Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021.

The 2019 Rate Case ROO recommended, among other things, (i) a $ 111 million decrease in annual revenue requirements, (ii) a return on equity of 9.16 %, (iii) a 0.30 % return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.03 % reduction to return on equity resulting in an effective fair value rate of return of 4.95 %, (iv) the nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners Power Plant (“Four Corners”) selective catalytic reduction (“SCR”) project (see “Four Corners SCR Cost Recovery” below for additional in formation), (v) the recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral, (vi) a 15 % disallowance of annual amortization of the Navajo Generating Station (the “Navajo Plant”) regulatory asset recovery related to the closure of the Navajo Plant (see “Navajo Plant” below), (vii) the denial of the request to defer, until APS’s next general rate case, the increase or decrease in its Arizona property taxes attributable to tax rate changes, and (viii) a collaborative process to review and recommend revisions to APS’s adjustment mechanisms within 12 months after the date of the decision.

The 2019 Rate Case ROO also recommended that the CCT plan related to the closure or future closure of coal-fired generation facilities include the following components:

(i) $ 50 million that will be paid over 10 years to the Navajo Nation, (ii) $ 5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant (“Cholla”), and (iii) $ 1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant.

These amounts would be recoverable from APS’s customers through the Arizona Renewable Energy Standard and Tariff (“RES”) adjustment mechanism.

APS filed exceptions on September 13, 2021, regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO, among other issues.

On October 6, 2021, and October 27, 2021, the ACC voted on various amendments to the 2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70 %, which includes a 20 -basis point penalty, (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project, with the exception of $ 215.5 million (see “Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components:

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;

These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m.

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.

On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021.

In addition, the ACC ordered extensive compliance and reporting obligations.

APS completed the implementation of the new on-peak hours for residential customers before the September 1, 2022, deadline.

Additionally, consistent with the 2019 Rate Case decision, as of February 2024, APS completed the following payments that will be recoverable through rates related to the CCT:

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;

5 unchanged sentences

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

The ACC has also authorized $ 1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation.

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 $ 1.25 million for electrification of homes and businesses is planned to be finalized after discussions with the Navajo Nation and the Hopi Tribe are completed.

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.

On November 24, 2021, APS filed an application for rehearing of the 2019 Rate Case with the ACC and the application was deemed denied on December 15, 2021, as the ACC did not act upon it.

On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $ 215.5 million of Four Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20 -basis-point penalty reduction to the return on equity, among other things.

On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action.

The Arizona Court of Appeals heard oral arguments on November 30, 2022.

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-point 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.

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.

The ACC requested an extension of the 30-day deadline to appeal the matter to the Arizona Supreme Court, and the Arizona Supreme Court granted the extension of the deadline to May 8, 2023.

The ACC filed an appeal on May 8, 2023, and on May 15, 2023, requested a suspension of the case to allow for settlement discussions between the parties, which was approved by the Court.

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 point 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 of 2021 and June 20, 2023.

On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through the Court Resolution Surcharge (“CRS”) mechanism, which became effective on July 1, 2023.

See “Court Resolution Surcharge” below for more information.

On July 18, 2023, the Sierra Club filed an application for rehearing of the ACC’s decision.

However, t he ACC did not act upon the application within 20 days,

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

and it was therefore denied by operation of law.

Subsequently, the Sierra Club did not file a notice of appeal to the Arizona Court of Appeals, and the time for an appeal has expired.

Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities

On September 28, 2022, ACC Staff filed their staff report in the Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities.

APS and other interested parties filed comments on the report.

On October 21, 2022, ACC Staff filed a revised report and proposed order.

The revised report and proposed order recommended that funds for CCT shall not be collected from rate payers.

On December 8, 2022, the ACC voted against ACC Staff’s proposed order, and on April 17, 2023, the ACC closed the docket.

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

Information Technology ACC Investigation

On December 16, 2021, the ACC opened an investigation into various matters related to APS’s Information Technology department, including information about technology projects, costs, vendor management leadership and decision making.

APS is cooperating with the investigation.

APS cannot predict the outcome of this matter.

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

See “Court Resolution Surcharge” below for more information.

Regulatory Lag Docket

On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules.

The ACC requested comments from utilities and interested parties on ways to reduce regulatory lag, including alternative ratemaking structures such as future test years and hybrid test years.

APS filed comments on June 1, 2023.

The ACC requested comments and held two workshops exploring ways to reduce regulatory lag, including alternative ratemaking structures such as future test years, hybrid test years, and formula rates.

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.

APS cannot predict the outcome of this matter.

4 unchanged sentences

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 solar, wind, biomass, biogas and geothermal technologies.

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.

In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.

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 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

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 IRP, and seek cost recovery in a rate process.

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

On January 26, 2022, the ACC reversed its prior

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

decision and declined to send the final draft energy rules through the rulemaking process.

Instead, the ACC opened a new docket to consider all-source RFP requirements and the IRP 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.

3 unchanged sentences

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 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.

On September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group.

APS proposed a small, pilot-scale program size of up to 140 MW that would be selected through a competitive RFP.

The ACC has not yet ruled on the proposal.

However, on November 10, 2022, the ACC approved a bifurcated community solar process, directing ACC Staff to develop a statewide policy through additional stakeholder involvement and establishing a separate evidentiary hearing to define other policy components.

On March 23, 2023, the ACC approved a policy statement that included information on how statewide community solar and storage programs should be structured, their location, and inclusion in RFPs.

The remainder of the community solar program policy components were deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar.

APS cannot predict the outcomes of these future activities.

On May 18, 2022, the ACC approved the 2022

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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

5 unchanged sentences

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

APS cannot predict the outcome of this proceeding.

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

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.

Demand Side Management Adjustor Charge .

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

The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan annually 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;

1 unchanged sentence

See below for discussion of the LFCR.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

2 unchanged sentences

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

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

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

4 unchanged sentences

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.

The ACC has not yet ruled on the 2024 DSM 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.

11 unchanged sentences

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

Twelve Months Ended

Beginning balance $ 460,561 $ 388,148

Deferred fuel and purchased power costs — current period 549,877 291,992

Year Ended December 31,

Balance at beginning of period $ 463,195 $ 460,561

Deferred fuel and purchased power costs 250,288 549,877

Amounts charged to customers

Ending balance $ 463,195 $ 460,561

( 425,886 ) ( 547,243 )

Balance at end of period $ 287,597 $ 463,195

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

3 unchanged sentences

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 contains 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 finds that APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity are reasonable and appropriate.

The report includes 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.

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.

To address the growing under-collected PSA balance, APS also requested that one of three different options be adopted, including a temporary or permanent increase of the annual cap to $ 0.006 per kWh.

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.

APS is also required to notify the ACC when the PSA balancing account approaches $ 0.5 million.

In its 2022 Rate Case, APS proposed a permanent increase in the annual PSA adjustor rate cap, which would increase the amount the rate can change in any given year from the currently effective $ 0.004 per kWh to $ 0.006 per kWh.

On February 22, 2024, the ACC voted to approve this request.

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 this time.

In accordance with the PSA Plan of Administration, APS is required to seek ACC approval to recover costs related to third-party energy storage systems through its PSA adjustment mechanism.

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.

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

The rate became effective on March 8, 2024.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2023, nine energy storage PPAs and their respective costs have been approved for recovery through the PSA.

In 2022, one energy storage PPA and its costs was approved for recovery through the PSA.

In 2021, four energy storage PPAs and their respective costs were approved for recovery through the PSA.

However, one energy storage PPA that was approved in 2021 was later terminated by APS due to project delays.

Environmental Improvement Surcharge (“EIS”).

The EIS permits 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.

A filing is made on or before February 1 each year for qualified environmental improvements since the prior rate case test year, and the new charge becomes effective April 1 unless suspended by the ACC.

The EIS includes an overall cap of $ 0.0005 per kWh (approximately $ 13 million to $ 15 million per year).

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

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

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.

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;

On February 1, 2024, APS filed an application requesting an increase in the charge to $ 15.3 million, or $ 11.3 million over the prior-period charge.

The 2022 Rate Case ROO has recommended eliminating the EIS.

On February 22, 2024, the ACC approved the elimination of the EIS as recommended in the 2022 Rate Case ROO.

With the elimination of the EIS, the surcharge will no longer be in effect.

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

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters .

In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.

A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”).

In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.

Under the terms of the settlement agreement entered into in 2012 regarding APS’s rate case (“2012 Settlement Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year.

APS’s retail transmission charges’ formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year.

Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.

3 unchanged sentences

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

On March 17, 2020, APS submitted a filing to make modifications to its annual transmission formula to provide additional transparency for excess and deficient accumulated deferred income taxes resulting from the Tax Cuts and Job Act (the “Tax Act”), as well as for future local, state, and federal

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

statutory tax rate changes.

APS amended its March 17, 2020, filing on April 28, 2020, September 29, 2021, and October 27, 2021.

In January 2022, FERC approved APS’s modifications to its annual transmission formula.

Effective June 1, 2021, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $ 4 million for the 12-month period beginning June 1, 2021, in accordance with the FERC-approved formula.

Of this net amount, wholesale customer rates decreased by approximately $ 3.2 million and retail customer rates would have increased by approximately $ 7.2 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 $ 28.4 million, resulting in reductions 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, 2021.

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.

4 unchanged sentences

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 and commercial rates.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and commercial rates.

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

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 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.

Lost Fixed Cost Recovery Mechanism .

The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays.

The fixed costs recoverable by the LFCR mechanism were 2.50 cents for both lost residential and non-residential kWh as set forth in the settlement agreement in the 2017 rate case (the “2017 Settlement Agreement”).

The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential kWh and 2.68 cents for lost non-residential kWh as set forth in the 2019 Rate Case decision.

The adjustment to the LFCR has a year-over-year cap of 1 % of retail revenues.

2 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On February 15, 2021, APS filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR recovery amount be increased to $ 38.5 million (an $ 11.8 million increase from previous levels).

On April 13, 2021, the ACC voted not to approve the requested $ 11.8 million increase to the annual LFCR adjustment;

thus, the previously approved rates continued to remain intact and the $ 11.8 million increase was reflected in APS’s 2022 filing in accordance with the compliance requirements.

As a result of the 2019 Rate Case decision, APS’s annual LFCR adjustor rate will be dependent on an annual earnings test filing, which will compare APS’s previous year’s rate of return with the related authorized rate of return.

If the actual rate of return is higher than the authorized rate of return, the LFCR rate for the subsequent year is set at zero.

APS determined that the changes to the LFCR mechanism, as a result of the 2019 Rate Case decision effective on December 1, 2021, did not materially impact its results of operations and financial statements for the year ended December 31, 2021.

However, as a result of certain changes made to the LFCR mechanism in the 2019 Rate Case decision, the mechanism no longer qualified for alternative revenue program accounting treatment, which impacts the future timing of related revenue recognition.

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 the $ 11.8 million balance from the 2021 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.

6 unchanged sentences

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

Upon conclusion of discovery, ACC Staff will provide a Memorandum and Proposed Order that the parties will have an opportunity to respond to.

The ACC has not yet ruled on this application.

As a result of Decision No.

79293 in the 2022 Rate Case, APS transferred $ 27.1 million from the LFCR to base rates.

On March 8, 2024, APS filed conforming LFCR schedules to incorporate changes required as a result of Decision No.

79293 in the 2022 Rate Case.

On April 9, 2024, the ACC approved the 2023 annual LFCR adjustment, with new rates effective in the first billing cycle of May 2024.

On June 5, 2024, APS filed a revised LFCR Plan of Administration in accordance with Decision No.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Tax Expense Adjustor Mechanism .

As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to 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 enable 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, the TEAM rates were reset to zero beginning December 31, 2021.

The TEAM was retained in the 2022 Rate Case to address potential changes in tax law that may be enacted prior to a decision in a subsequent APS rate case.

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.

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.

The CRS went into effect on July 1, 2023, at

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

a rate of $ 0.00175 per kWh.

The rate is designed to recover $ 59.6 million in revenue lost by APS between December of 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates.

The current CRS will be recalculated on the effective date of the 2022 Rate Case to remove the effects of the prospective recovery related to the allowable return on equity difference.

The portion of the CRS representing the recovery of the $ 59.6 million of lost revenue between December of 2021 and June 20, 2023, $ 9.4 million of which has been collected as of December 31, 2023, will cease upon full collection of the lost revenue.

Finally, recovery of ongoing costs related to the SCR investments will continue until the Company’s next rate case in which they can be incorporated therein.

On February 22, 2024, the ACC approved the 2022 Rate Case ROO, as amended.

The CRS tariff is currently being recalculated to reflect the final decision in that case.

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

The rate is designed to recover $ 59.6 million in revenue lost by APS between December 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates.

The portion of the CRS representing the recovery of the $ 59.6 million of lost revenue between December 2021 and June 20, 2023, $ 26.2 million of which has been collected as of December 31, 2024, will cease upon full collection of the lost revenue.

Additionally, the CRS tariff was updated to remove the return on equity component and account for SCR-related depreciation and deferral adjustments approved in Decision No.

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 distributed generation (“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.

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.

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

The ACC is no longer pursuing development of a forecasted avoided cost methodology as an option for utilities in place of the RCP.

Commercial customers, grandfathered residential solar customers, and residential customers with DG systems other than solar facilities continue to qualify for net metering.

In addition, the ACC made the following determinations in the Value and Cost of Distributed Generation docket:

• RCP customers who have interconnected a DG system or submitted an application for interconnection for DG systems will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility (for APS residential customers, as of September 1, 2017, based on APS’s 2017 Rate Case Decision);

• customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes;

• once an initial export price is set for utilities, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only.

The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1 unchanged sentence

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.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 will conduct discovery to investigate the issues related to this matter.

A status conference will be held on March 20, 2024, to determine if ACC Staff is prepared to present a recommendation on this matter at that time.

The amounts the Company pays customers for solar exports under its RCP rate rider could be affected by this docket.

APS cannot predict the outcome of this matter.

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.

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 to begin on this matter.

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.

APS and other interested parties have filed comments about the ACC Staff reports.

APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop triennial 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe.

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.

The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged.

5 unchanged sentences

As a result, APS filed its 2023 IRP on November 1, 2023.

On January 31, 2024, stakeholders filed comments regarding the IRP and APS has until May 31, 2024, to respond to the stakeholders’ comments.

APS cannot predict the outcome of this matter.

On January 31, 2024, stakeholders filed comments regarding the IRP, and APS filed its response to stakeholder comments on May 31, 2024.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Equity Infusions

On October 27, 2023, APS filed a notice of intent to increase Pinnacle West’s equity in APS in 2024.

APS is currently authorized to receive up to $ 150 million annually in equity infusions from Pinnacle West without seeking ACC approval.

APS sought approval under Arizona Administrative Code provision R14-2-803 to receive from Pinnacle West in 2024 up to $ 500 million in additional equity infusions above the currently authorized limit of $ 150 million annually.

On January 9, 2024, the ACC approved the increased equity infusion limit for 2024.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

2 unchanged sentences

“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.

During calendar year 2020, APS entered into two 18 -year PPAs with qualified facilities, each for 80 MW solar facilities.

In March 2021, the ACC approved these agreements.

On July 19, 2023, the agreements for these two PPAs were terminated due to project delays.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.

On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period June 1 through October 15 (“Summer Disconnection Moratorium”).

During the Summer Disconnection Moratorium, APS could not charge late fees and interest on amounts that were past due from customers.

Customer deposits must also be used to pay delinquent amounts before disconnection can occur.

In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019.

In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes.

The ACC further ordered that each regulated utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection.

The ACC Staff and ACC proposed draft amendments to the customer service disconnections rules.

On April 14, 2021, the ACC voted to send to the formal rulemaking process a draft rules package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar method (June 1 – October 15) for disconnection moratoriums.

On November 2, 2021, the ACC approved the final rules, and on November 23, 2021, the rules were submitted to the Arizona Office of the Attorney General for final review and approval.

The new rules became effective on April 18, 2022.

In accordance with the ACC service disconnection rules, APS now uses the calendar-based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”).

Customers with past due balances of $ 75 or greater as of the end of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements.

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”).

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.

2 unchanged sentences

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retail Electric Competition Rules

4 unchanged sentences

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.

The ACC continues to discuss matters related to retail electric competition, including the potential for additional buy-through programs or other pilot programs.

In April 2022, the Arizona Legislature passed, and the Governor signed, a bill that repealed the electric deregulation law that had been in place in Arizona since 1998.

APS cannot predict what impact, if any, this change will have on APS.

On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in Arizona.

Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and Tucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories.

APS opposes Green Mountain Energy’s application.

On November 3, 2021, the ACC submitted questions to the Arizona Attorney General requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates of convenience and necessity.

On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided insights on the applicable law.

As the ACC’s questions pertained to the retail competition law subsequently repealed in April 2022, the Attorney General has not responded to the ACC’s request and the questions are now moot.

No action has been taken by the ACC regarding this application since that time.

However, on May 17, 2023, the Retail Energy Supply Association filed a motion with the ACC requesting it to re-open the generic docket to re-examine the ACC’s electric competition rules.

No action has been taken by the ACC regarding this motion.

APS cannot predict the outcome of these matters.

On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200 to 300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier.

The letter also states that similar programs should be designed for other Arizona regulated electric utilities.

APS cannot predict the outcome of these future activities .

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

4 unchanged sentences

The hearing for this matter occurred in September 2018.

At the hearing, APS accepted ACC Staff’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recommendation of a lower annual revenue impact of approximately $ 58.5 million.

The Administrative Law Judge issued a Recommended Opinion and Order 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.

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.

7 unchanged sentences

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 United States Environmental Protection Agency (“EPA”) approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules.

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.

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.

5 unchanged sentences

APS has been recovering a return on and of the net book value of the unit in base rates.

Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $ 32.7 million as of December 31, 2023, in addition to a return on its investment.

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

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.

In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

5 unchanged sentences

The disallowed recovery of 15 % of the annual amortization does not have a material impact on APS financial statements.

Fire Mitigation

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 unchanged sentence

The detail of regulatory assets is as follows (dollars in thousands):

S December 31,

Amortization Through 2024 2023

3 unchanged sentences

Ocotillo deferral 2034 114,775 128,636

Deferred fuel and purchased power — mark-to-market (Note 16) 2026 120,214 —

SCR deferral (e) 2038 83,123 89,477

Lease incentives (g) 70,541 46,615

Retired power plant costs 2033 68,380 83,536

Lease incentives (Note 8) (g) 46,615 —

Deferred fuel and purchased power — mark-to-market (Note 15)

2027 42,275 120,214

FERC Transmission true up 2026 35,159 616

Income taxes — investment tax credit basis adjustment 2056 34,834 34,230

5 unchanged sentences

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 8,716 9,048

Loss on reacquired debt 2038 6,682 7,965

Four Corners cost deferral 2024 7,922 15,999

Tax expense adjustor mechanism (b) 2031 4,534 5,190

Lost fixed cost recovery (b) 2023 — 9,547

Four Corners cost deferral 2024 — 7,922

Other Various 3,522 3,912

5 unchanged sentences

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.

The approved 2022 Rate Case ROO, as amended, allows for the full return on the pension asset in rate base.

The 2022 Rate Case decision allows for the full return on the pension asset in rate base.

See Note 7 for further discussion.

3 unchanged sentences

FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(e) See “Four Corners SCR Cost Recovery” discussion above.

1 unchanged sentence

(g) Amortization periods vary based on specific terms of lease contract.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The detail of regulatory liabilities is as follows (dollars in thousands):

2 unchanged sentences

Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a) 2058 207,400 214,667

Asset retirement obligations 2057 392,383 354,002

Other postretirement benefits (d) 226,726 270,604

Removal costs (c) 94,368 106,889

Income taxes — deferred investment tax credit 2056 68,521 48,035

Income taxes — change in rates 2051 60,667 64,806

Asset retirement obligations and removal costs (d) 358,403 486,751

Other postretirement benefits (c) 238,113 226,726

Four Corners coal reclamation 2038 77,532 68,521

Renewable energy standard (b) 2025 68,523 60,667

Income taxes — deferred investment tax credit 2056 66,327 55,917

Income taxes — change in rates 2053 59,133 43,251

Spent nuclear fuel 2027 26,818 33,154

Sundance maintenance 2031 19,989 16,893

Demand side management (b) 2025 23,927 14,374

Property tax deferral (e) 2024 10,850 15,521

Sundance maintenance 2031 23,086 19,989

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

FERC transmission true up (b) 2025 1,869 22,895

Deferred fuel and purchased power — mark-to-market (Note 15)

2026 — 96,367

Other Various 113 2,317

4 unchanged sentences

(b) See “Cost Recovery Mechanisms” discussion above.

(c) In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.

(d) See Note 7.

(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.

2 unchanged sentences

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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.

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.

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

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.

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 the Palo Verde sale leaseback VIEs.

See Note 17 for additional details related to Palo Verde sale leaseback VIEs.

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):

21 unchanged sentences

Unrecognized tax benefit interest expense/(benefit) recognized

Following are the total amount 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):

$ 2,743 $ 452 $ ( 139 ) $ 2,743 $ 452 $ ( 139 )

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

1 unchanged sentence

Unrecognized tax benefit interest accrued $ 4,376 $ 1,633 $ 1,181 $ 4,376 $ 1,633 $ 1,181

Additionally, as of December 31, 2023, we have recognized less than $ 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.

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):

18 unchanged sentences

State income tax credits net of federal income tax benefit ( 3,349 ) ( 3,513 ) ( 5,482 ) ( 1,611 ) ( 1,775 ) ( 3,744 )

Net operating loss carryback tax benefit — — ( 5,915 ) — — —

Excess deferred income taxes — Tax Cuts and Jobs Act ( 36,559 ) ( 36,558 ) ( 36,241 ) ( 36,559 ) ( 36,558 ) ( 36,241 )

26 unchanged sentences

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

10 unchanged sentences

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 )

5 unchanged sentences

Pinnacle West consolidated credit and loss carryforwards amount above has been reduced by $ 4 million of unrecognized tax benefits.

As of December 31, 2023, APS consolidated deferred tax assets for credit and loss carryforwards relate to federal and state credit carryforwards, net of federal benefit, of $ 15 million, which first begin to expire in 2028.

APS consolidated credit and loss carryforwards amount above has been reduced by $ 12 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

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 facilities and the amounts available and outstanding (dollars in thousands):

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 Facilities $ 200,000 $ 1,250,000 $ 1,450,000 $ 200,000 $ 1,000,000 $ 1,200,000

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 Facilities Available $ 123,350 $ 717,150 $ 840,500 $ 184,280 $ 675,000 $ 859,280

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 April 10, 2023, Pinnacle West replaced its $ 200 million revolving credit facility that would have matured on May 28, 2026, with a new $ 200 million revolving credit facility that matures on April 10, 2028.

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.

1 unchanged sentence

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.

At December 31, 2023, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under t he credit facility, and $ 77 million of outstanding commercial paper borrowings.

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 April 10, 2023, APS replaced its two $ 500 million revolving credit facilities that would have matured on May 28, 2026, with a new $ 1.25 billion revolving credit facility that matures on April 10, 2028.

APS has the option to increase the amount of the facility 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.

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, 2023, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$ 533 million of outstanding commercial paper borrowings.

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 with a new 364 -day $ 350 million term loan facility that matures on December 10, 2024.

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.

On February 9, 2024, APS drew the full amount of $ 350 million.

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

On December 15, 2022, the ACC issued a financing order that, among other things, 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).

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 6 for additional long-term debt provisions .

16 unchanged sentences

Total APS long-term debt less current maturities 7,190,878 7,041,891

Los Alamitos equity bridge loan (d) (d) — 27,575

Los Alamitos construction facility (d) (d) — 23,110

Unamortized debt issuance cost — ( 135 )

Total BCE long-term debt — 50,550

Less current maturities — 50,685

Total BCE long-term debt less current maturities — ( 135 )

Pinnacle West

Senior unsecured notes 2025-2027 1.30 %- 4.75 %

Term loans 2024 (c) 625,000 450,000

1,025,000 500,000

Floating rate note 2026 (c) 350,000 —

Term loans 2024 (d) — 625,000

Unamortized discount ( 5 ) ( 15 )

7 unchanged sentences

(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) On August 4, 2023, concurrent with the BCE Sale, the construction facility was transferred to Ameresco and the equity bridge loan was paid in full by Pinnacle West.

See Note 20 and discussion 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10 unchanged sentences

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

December 31, 2023 As of

December 31, 2022

As of December 31, 2024 As of December 31, 2023

Amount Fair Value Carrying

2 unchanged sentences

APS 7,490,878 6,525,248 7,291,891 6,459,718

BCE — — 50,550 50,685

Total $ 8,858,648 $ 7,918,992 $ 8,415,622 $ 7,555,653

Credit Facilities and Debt Issuances

Credit Facilities and Debt and Equity Issuances

Pinnacle West

On December 16, 2022, Pinnacle West entered into a $ 175 million term loan facility that matures December 16, 2024.

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.

APS is currently authorized to receive up to $ 150 million annually in equity infusions from Pinnacle West without seeking ACC approval.

On October 27, 2023, APS sought approval from the ACC to receive from Pinnacle West in 2024 up to an additional $ 500 million in equity infusions above the authorized limit of $ 150 million, and on January 9, 2024, the ACC approved the increased equity infusion limit for 2024.

On January 6, 2023, Pinnacle West contributed $ 150 million into APS in the form of an equity infusion.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2023, APS issued $ 500 million of 5.55 % unsecured senior notes that mature August 1, 2033.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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”).

The credit agreement consisted of an equity bridge loan facility, a non-recourse construction facility, a letter of credit facility, and a related interest rate swap.

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.

18 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

On December 15, 2022, the ACC issued a financing order approving APS’s application filed on April 6, 2022, requesting to increase the long-term debt limit from $ 7.5 billion to $ 8.0 billion and to exclude financing lease PPAs from the definition of long-term indebtedness for purposes of the ACC financing orders.

See Note 5 for additional short-term debt provisions.

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.

Retirement Plans and Other Postretirement Benefits

29 unchanged sentences

Prior service credit (a) — — — ( 37,789 ) ( 37,789 ) ( 37,789 )

Net actuarial (gain)/loss 38,420 17,515 15,948 ( 9,614 ) ( 12,835 ) ( 10,093 )

Net periodic benefit cost/(benefit) $ 48,504 $ ( 5,295 ) $ ( 26,878 ) $ ( 59,813 ) $ ( 62,705 ) $ ( 54,933 )

Portion of cost/(benefit) charged to expense $ 27,029 $ ( 16,431 ) $ ( 32,743 ) $ ( 43,408 ) $ ( 45,042 ) $ ( 38,657 )

Net actuarial loss (gain)

41,915 38,420 17,515 ( 8,676 ) ( 9,614 ) ( 12,835 )

Net periodic benefit costs (credits)

$ 45,548 $ 48,504 $ ( 5,295 ) $ ( 61,175 ) $ ( 59,813 ) $ ( 62,705 )

Portion of costs (credits) charged to expense

$ 23,652 $ 27,029 $ ( 16,431 ) $ ( 45,557 ) $ ( 43,408 ) $ ( 45,042 )

(a) Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits.

14 unchanged sentences

Fair value of plan assets at January 1 2,835,549 2,829,485 696,494 652,287

Actual return/(loss) on plan assets 199,098 ( 787,874 ) 67,317 ( 193,807 )

Actual return on plan assets 4,518 199,098 32,816 67,317

Benefit payments ( 200,205 ) ( 193,034 ) ( 27,118 ) ( 23,110 )

1 unchanged sentence

Funded (Underfunded) Status at December 31 $ ( 152,447 ) $ ( 72,514 ) $ 342,102 $ 266,060

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):

2 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.

3 unchanged sentences

Fair value of plan assets 2,639,862 —

The Pinnacle West Capital Corporation Retirement Plan is more than 100 % funded on a projected benefit obligation basis at December 31, 2023, and December 31, 2022, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2023 and 2022 is a non-qualified supplemental excess benefit retirement plan.

The Pinnacle West Capital Corporation Retirement Plan, on a projected benefit obligation basis, was 99 % funded at December 31, 2024 and 102 % funded at December 31, 2023.

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.

The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):

27 unchanged sentences

Number of years to ultimate trend rate (pre-65 participants) 6 5 4 5 3

Initial and ultimate healthcare cost trend rate (post-65 participants) 2.00 % 2.00 % 2.00 % 2.00 % 2.00 %

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 %

Interest crediting rate – cash balance pension plans 4.66 % 4.54 % 4.54 % 4.50 % 4.50 %

43 unchanged sentences

Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade and are classified as Level 1.

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

securities issued by the U.S.

Treasury held directly by the plans are valued using quoted active market prices and are classified as Level 1.

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.

19 unchanged sentences

Pension Plan:

Cash and cash equivalents $ 9,055 $ — $ — $ 9,055

Fixed income securities:

7 unchanged sentences

Real estate — — 127,397 127,397

Short-term investments and other (e) — — 65,740 65,740

Other (e) — — 60,611 60,611

Total $ 748,033 $ 1,459,087 $ 432,742 $ 2,639,862

Other Benefits:

Cash and cash equivalents $ 840 $ — $ — $ 840

Fixed income securities:

7 unchanged sentences

Real estate — — 19,474 19,474

Short-term investments and other (e) 21,146 — 5,476 26,622

Other (e) 19,145 — 6,161 25,306

Total $ 337,359 $ 199,020 $ 165,813 $ 702,192

4 unchanged sentences

(d) These funds invest in international common stock equities.

(e) This category includes plan receivables and payables.

(e) Primarily relates to short-term investment funds and includes plan receivables and payables.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2 unchanged sentences

Pension Plan:

Cash and cash equivalents $ 1,252 $ — $ — $ 1,252

Fixed income securities:

7 unchanged sentences

Real estate — — 140,613 140,613

Partnerships — — 13,359 13,359

Short-term investments and other (e) — — 59,892 59,892

Other (e) — — 65,740 65,740

Total $ 885,721 $ 1,550,530 $ 399,298 $ 2,835,549

Other Benefits:

Cash and cash equivalents $ 204 $ — $ — $ 204

Fixed income securities:

7 unchanged sentences

Real estate — — 20,001 20,001

Short-term investments and other (e) 3,274 — 8,859 12,133

Other (e) 21,146 — 5,476 26,622

Total $ 391,019 $ 198,274 $ 107,201 $ 696,494

(a) These investments primarily represent assets valued using NAV as a practical expedient and have not been classified in the fair value hierarchy.

(b) This category consists primarily of debt securities issued by municipalities.

(b) This category consists primarily of debt securities issued by municipalities and asset backed securities.

2 unchanged sentences

and international common stock equities.

(e) This category includes plan receivables and payables.

(e) Primarily relates to short-term investment funds and includes plan receivables and payables.

Contributions

1 unchanged sentence

In 2024 and 2023, we did not make any contributions to our pension plan.

In 2021, we made contributions to our pension plan totaling $ 100 million.

The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2024, 2025, or 2026.

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 2025, 2026 or 2027.

With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2024 or 2023 and do not expect to make any contributions in 2025, 2026 or 2027.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Estimated Future Benefit Payments

24 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

non-consecutive periods of use.

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 lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation.

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.

In January 2023, APS modified two existing purchase power operating lease agreements.

Among other changes, the modifications extend the expiration dates of these contracts from October 2027 to October 2032 for one of the leases, and from September 2026 to October 2034 for the other lease.

These lease agreements previously commenced in 2020 and 2021.

APS has executed various energy storage purchased power lease agreements that allow APS the right to charge and discharge energy storage facilities.

The first of these energy storage leases commenced in September 2023, and is classified as an operating lease.

This agreement provides APS the use of the energy storage facility through May 2043.

APS pays a fixed monthly capacity price for rights to use the leased asset.

APS does not operate or maintain the energy storage facility, and has no purchase options or residual value guarantees relating to the lease asset.

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):

15 unchanged sentences

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 sheet.

Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15 unchanged sentences

These arrangements primarily relate to energy storage assets.

The lease commencement dates for these arrangements have experienced delays.

APS continues to work with the lessors to determine revised commencement dates.

We expect lease commencement dates ranging from April 2024 through June 2025, with lease terms expiring through May 2045.

As a result of these delays and other events, APS has received cash proceeds from the lessors prior to lease commencement.

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.

6 unchanged sentences

$ 143,950 $ 123,472 $ 118,463

Right-of-use operating lease assets obtained in exchange for operating lease liabilities 602,301 (a) 16,990 500,582

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 (b) 4.53 % 2.21 %

(a) Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.

(b) Most of our lease agreements do not contain an implicit rate that is readily determinable.

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.

19 unchanged sentences

Transmission facilities:

ANPP 500kV System 33.4 % (b) 136,145 58,252 4,801

Arizona Nuclear Power Project 500kV System 33.3 % (b) 134,713 60,174 7,174

Navajo Southern System 24.7 % (b) 88,528 38,797 626

24 unchanged sentences

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 submitted nine claims pursuant to the terms of the August 18, 2014 settlement agreement, for nine separate time periods during July 1, 2011 through October 31, 2022.

The DOE has approved and paid $ 138.2 million for these claims (APS’s share is $ 40.2 million).

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.

The DOE has approved and paid approximately $ 156.7 million for these claims (APS’s share is approximately $ 45.6 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, 2023, APS filed its ten th claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $ 18.46 million (APS’s share is $ 5.4 million).

In February 2024, the DOE approved $ 18.39 million of this claim.

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 February 2025, the DOE approved approximately $ 17.6 million of this claim.

Nuclear Insurance

16 unchanged sentences

The insurance coverage discussed in this, and the previous paragraph, is subject to certain policy conditions, sublimits, and exclusions.

Captive Insurance Cell

Pinnacle West has established a captive insurance program to supplement third-party insurance coverage for certain risks.

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.

These coverages may be supplemented with third-party insurance policies.

The Captive policies exclude nuclear liability at Palo Verde.

The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments, which in the event of an insured loss would be available to pay covered claims.

In the event of an insured loss event, Pinnacle West may be required to provide additional funding to the Captive.

The Captive is a VIE, and Pinnacle West is the primary beneficiary of the VIE and consolidates the assets and liabilities of the Captive.

See Note 17 for additional details.

Fuel and Purchased Power Commitments and Purchase Obligations

10 unchanged sentences

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):

Year Ended December 31,

2024 2025 2026 2027 2028 Thereafter

2025 2026 2027 2028 2029 Thereafter (b)

Coal take-or-pay commitments (a) $ 208,984 $ 214,090 $ 212,529 $ 217,820 $ 223,291 $ 463,752

(a) Total take-or-pay commitments are approximately $ 1.5 billion.

The total net present value of these commitments is approximately $ 1.4 billion.

The total net present value of these commitments using a 4.81 % discount rate is approximately $ 1.3 billion.

(b) Through 2031.

APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts.

3 unchanged sentences

Total purchases $ 237,821 $ 255,219 $ 305,502

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Renewable Energy Credits

18 unchanged sentences

$ 23 million in 2028;

and $ 2 million thereafter.

4 unchanged sentences

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 contaminated site are among the parties who are potentially responsible (each a “PRP”).

Those who released, generated, transported to or disposed of hazardous substances at a

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

contaminated site are among the parties who are potentially responsible (each a “PRP”).

PRPs may be strictly, jointly, and severally liable for clean-up.

4 unchanged sentences

The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022.

APS cannot predict the EPA’s timing with respect to this matter.

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 ultimate remediation requirements are not yet finalized by EPA, at the present time expenditures related to this matter cannot be reasonably estimated.

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”).

At this time, only one active lawsuit remains pending, which is on appeal to the U.S.

Court of Appeals for the Ninth Circuit based on a U.S.

District Court order dismissing cost recovery claims of approximately $ 20.7 million by a service provider for RID.

APS is unable to predict the outcome of any

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

further litigation related to this claim or APS’s share of liability related to that claim;

however, APS does not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

In addition, as part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.

APS responded to ADEQ on May 4, 2015.

Since that time, ADEQ has taken no action based on the information provided by APS.

At this time, only one active lawsuit remains pending in the U.S.

District Court for Arizona, which concerns $ 8.3 million in remediation legal expenses.

APS is unable to predict the outcome of any further litigation related to this claim or APS’s share of liability related to that claim;

however, APS does not expect the outcome to have a material impact on its financial position, results of operations or cash flows.

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.

2 unchanged sentences

APS filed its response to this information request on April 29, 2022.

On January 17, 2023, EPA contacted APS to inform the Company 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 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.

APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $ 1.7 million.

At the present time, we are unable to predict the outcome of this matter, and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project.

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 Note 3 for additional information regarding the Four Corners SCR cost recovery and the 2019 Rate Case.

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 coal combustion residuals (“CCRs”).

These laws and regulations can change from time to time, imposing new obligations on APS

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

resulting in increased capital, operating, and other costs.

These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.

Associated capital expenditures or operating costs could be material.

1 unchanged sentence

The following proposed and final rules could involve material compliance costs to APS.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Coal Combustion Waste .

7 unchanged sentences

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 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.

Although ADEQ has taken steps to develop a CCR permitting program, and new state legislation has been adopted providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect.

• 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.

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.

5 unchanged sentences

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

will be subject to public comment and, potentially, judicial review.

We expect to have a proposed decision from EPA regarding Cholla sometime in 2024.

• On May 18, 2023, EPA published a proposal that expands the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015.

EPA proposes to define a new class of CCR management units (“CCRMUs”) that broadly encompass any location at an operating coal-fired power plant where CCR 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.

EPA expects to finalize this proposal by spring of 2024.

We cannot at this time 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 APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

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.

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.

3 unchanged sentences

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 by April 11, 2021, at the latest (except for those disposal units subject to alternative closure).

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).

APS completed the assessments of corrective measures on June 14, 2019;

however, additional investigations and engineering analyses that will support the remedy selection are still underway.

In addition, APS will also solicit input from the public and host public hearings as part of this process.

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.

S ee Note 11 .

As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change.

Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, APS cannot predict any ultimate impacts to APS;

however, at this time APS does not believe that any potential changes to the cost estimate for Four Corners or Cholla would have a material impact on its financial condition, results of operations, or cash flows.

Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, we cannot predict any ultimate impacts to APS;

however, at this time APS does not believe that any potential changes to the cost estimate from the CCR rule’s corrective action assessment process for Four Corners or Cholla would have a material impact on its financial condition, results of operations, or cash flows.

EPA Power Plant Carbon Regulations.

6 unchanged sentences

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.

In the latest set of proposed rules, released on May 23, 2023, EPA contemplates emission standards and guidelines for various subcategories of new and existing power plants.

Unlike EPA’s Clean Power

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Plan regulations from 2015, which took a broad, system-wide approach to regulating carbon emissions from electric utility fossil-fuel burning power plants, the most recent proposal is limited to measures that can be installed at individual power plants to limit planet-warming emissions.

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.

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”) or varying levels of hydrogen gas (“H2”) co-firing.

As for existing natural gas-fired combustion turbines, EPA is imposing similar control requirements at large, high utilization generating units, but is otherwise not proceeding at this time with further regulation.

As such, under EPA’s proposal, this means that both new and existing peaking gas-fired combustion turbines (i.e., those with a 20% or less annual capacity factor) are effectively unregulated under the proposed regulations.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA has developed subcategories based on planned retirement dates.

This means that facilities retiring between 2030 and before 2040 must meet increasingly stringent emission limits up to natural-gas co-firing starting in 2030.

However, for those facilities with no planned retirement date prior to 2040, EPA is requiring those plants to be retrofitted with CCS controls by 2030.

EPA expects to take final action on this proposal by spring or summer of 2024.

At this time, APS cannot predict the outcome of this rulemaking or when EPA will take final action.

In addition, APS is continuing to evaluate this proposal and its potential impact on APS’s operations.

Depending on the eventual outcome, the costs associated with APS’s operation of its current and future thermal power plants could materially increase, which could affect our financial condition, results of operations, or cash flows.

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.

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.

Circuit Court of Appeals.

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.

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.

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.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

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.

That proposal involves adding these states to the Good Neighbor Plan and disapproving the corresponding provisions of each state’s State Implementation Plan.

Because APS operates thermal power plants within Arizona and those portions of the Navajo Nation within New Mexico, APS’s power plants would be subject to EPA’s Good Neighbor Plan upon finalization of this proposal.

EPA’s final Good Neighbor Plan is subject to ongoing judicial review in the D.C.

Circuit Court of Appeals.

On June 27, 2024, the U.S.

Supreme Court granted a motion to stay the effectiveness of EPA’s final Good Neighbor Plan pending the resolution of the litigation.

As such, APS will not be impacted by the Good Neighbor Plan until the outcome of this litigation is finalized.

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.

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.

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.

1 unchanged sentence

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

5 unchanged sentences

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 of 2021, and APS does not expect the outcome to have a material impact on our financial condition, results

of operations, or cash flows.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Four Corners — 4CA Matter

On July 6, 2016, 4CA purchased El Paso Electric Company’s 7 % interest in Four Corners.

NTEC purchased this 7 % interest on July 3, 2018, from 4CA.

NTEC purchased the 7 % interest at 4CA’s book value, approximately $ 70 million, and paid 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note, which was paid in full as of June 30, 2022.

In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC’s 7 % share of capital expenditures and operating and maintenance expenses.

Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

PNW Power Wind Projects

In October 2023, the Tenaska wind farm investments were reorganized such that they are no longer held by BCE, rather they are now held under the new Pinnacle West subsidiary, PNW Power.

See Notes 1 and 20 for more information.

Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system.

Tenaska Clear Creek Wind, LLC, filed complaints with FERC on this matter on May 21, 2021, and May 25, 2022, both of which FERC has denied.

In April 2023, Tenaska Clear Creek Wind, LLC filed Petitions for Review of the relevant FERC orders with the U.S.

Court of Appeals for the D.C.

Circuit, which are still pending.

Due to disputed system upgrades and curtailment issues, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors.

During the fourth quarter of 2022, due to these ongoing disputes, cost allocation uncertainties, and no probable favorable resolution, the equity method investment was fully impaired.

Prior to the impairment, the investment had a carrying value of $ 17.1 million, which was written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022.

Pinnacle West’s Consolidated Statement of Income for the year ended December 31, 2022, includes an after-tax loss of $ 12.8 million relating to this impairment.

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 is sponsoring the Kūpono Solar project.

This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a 20 -year power purchase agreement with Hawaiian Electric Company, Inc.

The Kūpono Solar project is expected to be completed in 2024.

On April 18, 2023, the Kūpono Solar special purpose entity entered into a $ 140 million non-recourse construction financing agreement.

The construction financing will convert into a sale leaseback agreement upon commercial operation of the project.

As of December 31, 2023, the construction financing agreement required $ 40 million of sponsor equity, which has been funded by the project’s equity participants and which is subject to adjustment under the construction financing agreement.

In connection with the financing, Pinnacle West has issued performance guarantees relating to the project.

Investments in the Kūpono Solar

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

project are included in the BCE Sale which closed on January 12, 2024.

Subsequent to the BCE Sale, Pinnacle West continues to maintain the performance guarantees relating to the Kūpono Solar project financing, see additional information below regarding these guarantees.

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.

3 unchanged sentences

These instruments support commodity contract collateral obligations and other transactions.

As of December 31, 2023, standby letters of credit totaled approximately $ 27 million and will expire in 2024.

As of December 31, 2023, surety bonds expiring through 2025 totaled approximately $ 20 million.

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.

The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable.

2 unchanged sentences

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 reasonably estimated.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 4CA’s 7 % interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners.

See “Four Corners — 4CA Matter” above for information related to this guarantee.

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 not needed to perform under this guarantee.

4 unchanged sentences

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 BCE’s Kūpono Solar project investment financing, and is exposed to losses relating to these guarantees upon the occurrence of certain events that we do not consider to be reasonably likely to occur.

Subsequent to the BCE Sale, Pinnacle West continues to maintain these performance guarantees.

As of December 31, 2023, these performance guarantees had no significant impact on our Consolidated Balance Sheets or Consolidated Statements of Income.

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.

Pinnacle West has not needed to perform under these guarantees.

Maximum obligations are not explicitly stated in the guarantees and cannot be reasonably estimated.

Ameresco is obligated to reimburse Pinnacle West for any payments made by Pinnacle West under such guarantees.

We consider the fair value of these guarantees, including expected credit losses, to be immaterial.

The details of the guarantees are as follows:

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• Upon the BCE Sale closing, which occurred on January 12, 2024, Pinnacle West committed to certain performance guarantees tied to the Kūpono project achieving certain construction and operation milestones.

These performance guarantees will expire when the Kūpono project achieves commercial operation, which is expected in 2024.

• When the Kūpono financing coverts to a sale leaseback agreement, which is expected to occur upon commercial operation of the project, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events (such as uninsured loss events).

• 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.

• Ameresco is obligated to reimburse Pinnacle West for any payments made by Pinnacle West under such guarantees.

Asset Retirement Obligations

In 2023, the Company revised its cost estimates for existing Asset Retirement Obligations (“ARO”) for the following:

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, which resulted in an increase of approximately $ 8 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.

In 2022, APS did not revise any cost estimates related to existing AROs, and no new AROs were necessary.

See additional details in Notes 3 and 10 .

The following table shows the change in our AROs (dollars in thousands):

The following table shows the change in our asset retirement obligations (dollars in thousands):

Asset retirement obligations at the beginning of year

$ 966,001 $ 797,762

Changes attributable to:

4 unchanged sentences

Asset retirement obligations at the end of year

$ 1,146,586 $ 966,001

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.

See detail of regulatory liabilities in Note 3.

See Note 3 for detail of regulatory liabilities.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17 unchanged sentences

We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”) as a practical expedient.

These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return.

These instruments are similar to mutual funds;

however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange.

Instruments valued using NAV as a practical expedient are included in our fair value disclosures;

4 unchanged sentences

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

Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Risk Management Activities — Energy Derivative Instruments

13 unchanged sentences

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.

Risk Management Activities — Interest Rate Derivatives

Our interest rate derivative instruments related to a BCE interest rate swap, which was valued using financial models that utilize observable inputs for similar instruments and was classified as Level 2.

The interest rate swap is no longer held as of December 31, 2023.

Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds

The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities.

Other special use funds include the coal reclamation escrow account and the active union employee medical account.

Other special use funds include the coal reclamation escrow account, the active union employee medical account, and the Captive.

See Note 18 for additional discussion about our investment accounts.

28 unchanged sentences

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):

Balance at December 31, 2023 Level 1 Level 2 Level 3 Other Total

Level 1 Level 2 Level 3 Other Total

Cash equivalents $ 23 $ — $ — $ — $ 23

1 unchanged sentence

Commodity contracts — 13,152 7,176 ( 3,770 ) (a) 16,558

Nuclear decommissioning trust:

Nuclear decommissioning trusts:

Equity securities 11,859 542 — 3,335 (b) 15,736

5 unchanged sentences

Other fixed income — 27,502 — — 27,502

Subtotal nuclear decommissioning trust 330,798 461,599 — 408,849 1,201,246

Subtotal nuclear decommissioning trusts 379,255 477,186 — 426,404 1,282,845

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

Municipal bonds — — — — —

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

4 unchanged sentences

(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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 2023, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Balance at December 31, 2022 Level 1 Level 2 Level 3 Other Total

Level 1 Level 2 Level 3 Other Total

Cash equivalents $ 10 $ — $ — $ — $ 10

Risk management activities — derivative instruments:

Commodity contracts — 1,881 6,616 ( 1,689 ) (a) 6,808

Interest rate swaps — 131 — — 131

Subtotal risk management activities - derivative instruments — 127,260 26,132 ( 21,163 ) 132,229

Nuclear decommissioning trust:

Nuclear decommissioning trusts:

Equity securities 11,064 — — ( 767 ) (b) 10,297

5 unchanged sentences

Other fixed income — 5,653 — — 5,653

Subtotal nuclear decommissioning trust 226,581 370,420 — 476,409 1,073,410

Subtotal nuclear decommissioning trusts 330,798 461,599 — 408,849 1,201,246

Other special use funds:

1 unchanged sentence

Treasury debt 319,594 — — — 319,594

Municipal bonds — 4,027 — — 4,027

Subtotal other special use funds 360,585 — — 2,196 362,781

2 unchanged sentences

Commodity contracts $ — $ ( 127,016 ) $ ( 1,695 ) $ 4,823 (a) $ ( 123,888 )

Interest rate swaps — ( 909 ) — — ( 909 )

Subtotal risk management activities - derivative instruments — ( 26,783 ) ( 31,020 ) 15,357 ( 42,446 )

Total liabilities $ — $ ( 26,783 ) $ ( 31,020 ) $ 15,357 $ ( 42,446 )

(a) Represents counterparty netting, margin, and collateral.

1 unchanged sentence

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements Classified as Level 3

2 unchanged sentences

Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.

6 unchanged sentences

Commodity Contracts Assets Liabilities Technique Unobservable Input Range (b)

Forward Contracts (a) $ 6,587 $ 658 Discounted cash flows Electricity forward price (per MWh) $ 37.79

Forward Contracts (a) 29 1,037 Discounted cash flows Natural gas forward price (per MMBtu) $ 0.00

Electricity Forward Contracts (a) $ 708 $ 21,890 Discounted cash flows Electricity forward price (per MWh) $ 25.25

Natural Gas Forward Contracts (a) 6,468 325 Discounted cash flows Natural gas forward price (per MMBtu) $( 0.89 )

Total $ 7,176 $ 22,215

4 unchanged sentences

Commodity Contracts Assets Liabilities Technique Unobservable Input Range (b)

Forward Contracts (a) $ 26,132 $ 1,759 Discounted cash flows Electricity forward price (per MWh) $ 37.79 - $ 310.69 $ 163.92

Forward Contracts (a) — 29,261 Discounted cash flows Natural gas forward price (per MMBtu) $( 11.81 ) - $ 0.00 $ ( 5.08 )

Electricity Forward Contracts (a) $ 6,587 $ 658 Discounted cash flows Electricity forward price (per MWh) $ 37.79 - $ 259.04 $ 158.08

Natural Gas Forward Contracts (a) 29 1,037 Discounted cash flows Natural gas forward price (per MMBtu) $ 0.00 - $ 0.08 $ 0.03

Total $ 6,616 $ 1,695

5 unchanged sentences

Commodity Contracts 2024 2023

Net derivative balance at beginning of period $ ( 4,888 ) $ ( 2,738 )

Total net gains (losses) realized/unrealized:

Balance at beginning of period $ 4,921 $ ( 4,888 )

Total net losses realized/unrealized:

Deferred as a regulatory asset or liability ( 60,965 ) ( 70,214 )

2 unchanged sentences

Transfers from Level 3 into Level 2 1,484 11,606

Net derivative balance at end of period $ 4,921 $ ( 4,888 )

Net unrealized gains included in earnings related to instruments still held at end of period $ — $ —

Balance at end of period $ ( 15,039 ) $ 4,921

Net unrealized gains/losses included in earnings related to instruments still held at end of period $ — $ —

Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

2 unchanged sentences

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 earnings per share (in thousands, except per share amounts):

The following table presents the calculation of Pinnacle West’s basic and diluted EPS (in thousands, except per share amounts):

2024 2023 2022

3 unchanged sentences

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

2 unchanged sentences

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.

Awards granted under the 2021 Long-Term Incentive Plan (“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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

authorizes up to 4.3 million common shares to be available for grant.

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, 2024, 2.9 million common shares were available for issuance under the 2021 Plan.

2 unchanged sentences

No new awards may be granted under the 2012 or 2007 Plans.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation Expense and Activity

10 unchanged sentences

Weighted-average grant date fair value $ 71.10 $ 74.32 $ 69.66 $ 72.89 $ 79.61 $ 77.63

(a) Units granted includes awards that will be cash settled of 0 in 2023, 0 in 2022, and 51,074 in 2021.

(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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the change of nonvested awards:

15 unchanged sentences

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 $ 3 million, $ 3 million, and $ 3 million in 2023, 2022 and 2021, 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.

Restricted stock units that are cash settled are classified as liability awards.

13 unchanged sentences

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

10 unchanged sentences

The first performance criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in 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 second performance criteria is based upon Pinnacle West’s earnings per share (“EPS”) performance relative to an

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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).

11 unchanged sentences

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, Clean and 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

expected to vest.

Management evaluates the probability of meeting the EPS, Clean and Metric component at each balance sheet date.

If the EPS, Clean and Metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the EPS, Clean and Metric component, and any previously recognized compensation cost is reversed.

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.

8 unchanged sentences

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheets as an asset or liability and are measured at fair value.

2 unchanged sentences

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.

See Note 13 for details relating to Pinnacle West’s equity forward sale agreements and Note 5 for Pinnacle West’s 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

6 unchanged sentences

Gas Billion cubic feet 235 200

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Gains and Losses from Energy Derivative Instruments

1 unchanged sentence

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

Financial Statement Year Ended December 31,

Commodity Contracts Location 2024 2023 2022

Net Gain (Loss) Recognized in Income Fuel and purchased power (a) $ ( 370,145 ) $ 307,287 $ 216,847

Net Gain (Loss) Recognized in Income

Fuel and purchased power (a) ( 88,522 ) ( 370,145 ) 307,287

(a) Amounts are before the effect of PSA deferrals.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Energy Derivative Instruments in the Consolidated Balance Sheets

6 unchanged sentences

These types of transactions are excluded from the offsetting tables presented below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

12 unchanged sentences

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) Includes cash collateral provided to counterparties of $ 9,200 thousand that is subject to offsetting.

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

1 unchanged sentence

Includes cash collateral received from counterparties of $ 2,971 thousand and cash margin provided to counterparties of $ 18 thousand.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2023:

10 unchanged sentences

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(b) Includes cash collateral provided to counterparties of $ 9,200 thousand that is subject to offsetting.

1 unchanged sentence

Includes cash collateral received from counterparties of $ 6,071 thousand and cash margin provided to counterparties of $ 5 thousand.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Interest Rate Derivatives

On October 19, 2022, Bright Canyon Energy entered into an interest rate swap to hedge the variable interest rate exposure relating to the credit agreement for the Los Alamitos project.

The transaction qualified and had been designated as a cash flow hedge.

The interest rate swap was included in the BCE Sale, and was assumed by Ameresco as part of the first stage of the closing.

Prior to being transferred in the BCE Sale, the interest rate swap was in an asset position valued at $ 0.2 million.

As of December 31, 2023, the interest rate swap has no impact on our Consolidated Balance Sheets.

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, 2023, we have no counterparties with positive exposures of greater than 10% of Pinnacle West’s risk management assets.

As of December 31, 2024, we have one counterparty for which our exposure represents approximately 26 % of Pinnacle West’s $ 16.6 million of risk management assets.

This exposure relates to an ISDA master agreement with the respective counterparty.

The counterparty is rated as investment grade by Standard & Poor’s.

Our risk management process assesses and monitors the financial exposure of all counterparties.

8 unchanged sentences

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):

1 unchanged sentence

Aggregate fair value of derivative instruments in a net liability position $ 62,603

Cash collateral posted 9,200

Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) 117,566

Additional collateral in the event credit-risk related contingent features were fully triggered (a) 32,728

(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $ 205 million if our debt credit ratings were to fall below investment grade.

We also have energy related non-derivative instrument contracts, including energy storage lease contracts, with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $ 416 million if our debt credit ratings were to fall below investment grade.

Other Income and Other Expense

2 unchanged sentences

Other income:

Interest income $ 27,242 (a) $ 7,326 $ 6,726

Interest income $ 24,322 (a) $ 27,242 (a) $ 7,326

Gain on sale of BCE (Note 20)

Debt return on Four Corners SCR deferral (Note 3)

Debt return on Ocotillo modernization project (Note 3)

22,988 6,205 —

Miscellaneous 1,304 219 590

1 unchanged sentence

Other expense:

Non-operating costs $ ( 15,260 ) $ ( 18,619 ) $ ( 13,008 )

Investment gains (losses) — net ( 3,402 ) ( 20,537 ) (b) ( 1,367 )

Miscellaneous ( 6,394 ) ( 13,229 ) (c) ( 11,021 )

Non-operating costs $ ( 27,370 ) (b) $ ( 15,260 ) $ ( 18,619 )

Investment losses — net ( 1,418 ) ( 3,402 ) ( 20,537 ) (c)

Miscellaneous ( 5,348 ) ( 6,394 ) ( 13,229 )

Total other expense $ ( 34,136 ) $ ( 25,056 ) $ ( 52,385 )

(a) The 2023 interest income is primarily related to PSA Interest.

(b) The 2022 investment loss is primarily related to an impairment of PNW Power’s Clear Creek wind farm investment.

Other Income and Other Expense - APS

(a) The 2023 and 2024 Interest income is primarily related to PSA Interest.

(b) The 2024 Non-operating cost is primarily related to corporate giving.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides detail of APS’s other income and other expense for 2024, 2023, and 2022 (dollars in thousands):

1 unchanged sentence

Other income:

Interest income $ 26,853 (a) $ 5,332 $ 4,692

Debt return on Four Corners SCR deferral (Note 3)

Debt return on Ocotillo modernization project (Note 3)

Interest income (a) $ 21,088 (a) $ 26,853 (a) $ 5,332

Miscellaneous 6 219 556

1 unchanged sentence

Other expense:

Non-operating costs $ ( 14,070 ) $ ( 15,579 ) $ ( 10,080 )

Miscellaneous ( 4,194 ) ( 10,529 ) (b) ( 8,817 )

Non-operating costs $ ( 26,588 ) (b) $ ( 14,070 ) $ ( 15,579 )

Miscellaneous ( 3,110 ) ( 4,194 ) ( 10,529 )

Total other expense $ ( 29,698 ) $ ( 18,264 ) $ ( 26,108 )

(a) The 2023 interest income is primarily related to PSA Interest.

(b) The 2022 miscellaneous amount includes donations of $ 7 million to the APS Foundation.

(a) The 2023 and 2024 Interest income is primarily related to PSA Interest.

(b) The 2024 Non-operating cost is primarily related to corporate giving.

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 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 policies exclude nuclear liability at Palo Verde.

See Note 10 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 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,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Palo Verde Sale Leaseback Variable Interest Entities

the Captive’s insurance premium revenues derived from Pinnacle West policies is 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 our Consolidated Balance Sheets, and the Captive’s investment gains and losses reflected through earnings on our Consolidated Income Statements.

Consolidation of the Captive resulted in an increase in Pinnacle West net income of $ 5 million for 2024, and zero for 2023 and 2022.

These amounts are fully attributable to Pinnacle West shareholders.

Consolidation impacts Pinnacle West Consolidated Income Statement’s operations and maintenance expense and other income line items.

Pinnacle West’s Consolidated Balance Sheets as of December 31, 2024 include $ 34 million of assets relating to the Captive that is reported within the other special use funds line item.

See Notes 12 and 18 for additional details on these investment holdings.

Our Consolidated Balance Sheets as of December 31, 2023, include $ 5 million of assets relating to the Captive that is reported within the other assets line item.

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.

4 unchanged sentences

Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $ 17 million for 2023, 2022 and 2021, respectively.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $ 17 million for each of 2024, 2023 and 2022.

The increase in net income is entirely attributable to the noncontrolling interests.

Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Consolidated Balance Sheets include the following amounts relating to the VIEs (dollars in thousands):

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our Consolidated Balance Sheets include the following amounts relating to these VIEs (dollars in thousands):

December 31, 2024 December 31, 2023

8 unchanged sentences

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Account, and an Active Union Employee Medical Account.

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts and Other Special Use funds.

Investments in debt securities are classified as available-for-sale securities.

We record both debt and equity security

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

investments at their fair value on our Consolidated Balance Sheets.

We record both debt and equity security investments at their fair value on our Consolidated Balance Sheets.

See Note 12 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy.

10 unchanged sentences

Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Active Union Employee Medical Account — APS has investments restricted for paying active union employee medical costs.

These investments may be used to pay active union employee medical costs incurred in the current and future periods.

In 2023 and 2022, APS was reimbursed $ 14 million and $ 15 million, respectively, for prior year active union employee medical claims from the active union employee medical account.

In 2024 and 2023, APS was reimbursed $ 14 million for each year, for prior year active union employee medical claims from the active union employee medical account.

The account is invested primarily in fixed income securities.

In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory liabilities.

In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory assets and liabilities.

Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trusts and other special use fund assets (dollars in thousands):

Captive Insurance Cell — Pinnacle West has investments in the Captive that may be used to pay insurance losses in the event of certain insured loss events.

The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments.

These investments are restricted for insured loss events.

Pinnacle West Consolidated investment holdings reflected in the tables below primarily relate to APS, with the exception of the Captive’s investments included within Other Special Use Funds.

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of the nuclear decommissioning trusts and other special use fund assets (dollars in thousands):

December 31, 2024

5 unchanged sentences

Other 3,335 27,851 31,186 (b) — —

Total $ 1,201,246 $ 362,781 $ 1,564,027 $ 358,112 $ ( 40,868 )

Total $ 1,282,845 $ 408,357 $ 1,691,202 (c) $ 366,844 $ ( 32,136 )

(a) As of December 31, 2024, the amortized cost basis of these available-for-sale investments is $ 1,224 million.

(b) Represents net pending securities sales and purchases.

(c) All amounts pertain to APS, with the exception of $ 34 million of Other Special Use Fund investments in equity securities relating to the Captive.

December 31, 2023

5 unchanged sentences

Other ( 767 ) 2,196 1,429 (b) 39 —

Total $ 1,073,410 $ 347,231 $ 1,420,641 $ 337,994 $ ( 69,091 )

Total $ 1,201,246 $ 362,781 $ 1,564,027 (c) $ 358,112 $ ( 40,868 )

(a) As of December 31, 2023, the amortized cost basis of these available-for-sale investments is $ 1,120 million.

(b) Represents net pending securities sales and purchases.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):

Year Ended December 31,

23 unchanged sentences

Balance at December 31, 2022

OCI (loss) before reclassifications 17,550 1,873 19,423

Amounts reclassified from accumulated other comprehensive loss 4,003 (a) — 4,003

$ ( 32,332 ) $ 897 $ ( 31,435 )

Other comprehensive income/(loss) before reclassifications

( 4,420 ) 713 ( 3,707 )

Amounts reclassified from accumulated other comprehensive loss

1,998 (a) — 1,998

Balance at December 31, 2023

OCI (loss) before reclassifications ( 4,420 ) 713 ( 3,707 )

Amounts reclassified from accumulated other comprehensive loss 1,998 (a) — 1,998

( 34,754 ) 1,610 ( 33,144 )

Other comprehensive income/(loss) before reclassifications

1,039 ( 891 ) 148

Amounts reclassified from accumulated other comprehensive loss

2,054 (a) — 2,054

Balance at December 31, 2024

$ ( 31,661 ) $ 719 $ ( 30,942 )

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.

Changes in Accumulated Other Comprehensive Loss — APS

The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):

Pension and Other Postretirement Benefits Total

Pension and Other Postretirement Benefits

Balance at December 31, 2022

OCI (loss) before reclassifications 15,646 15,646

Amounts reclassified from accumulated other comprehensive loss 3,638 (a) 3,638

Other comprehensive (loss) before reclassifications

Amounts reclassified from accumulated other comprehensive loss

Balance at December 31, 2023

OCI (loss) before reclassifications ( 3,383 ) ( 3,383 )

Amounts reclassified from accumulated other comprehensive loss 1,760 (a) 1,760

Other comprehensive income before reclassifications

Amounts reclassified from accumulated other comprehensive loss

Balance at December 31, 2024

4 unchanged sentences

The transaction is accounted for as the sale of a business and was structured to close in multiple stages that were completed on January 12, 2024.

Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to PNW Power, a newly-formed, wholly-owned subsidiary of Pinnacle West.

The BCE Sale did not include a $ 31 million equity bridge loan relating to BCE’s Los Alamitos project, which was paid in full by Pinnacle West on August 4, 2023.

Other than these retained investments and the debt instrument, all BCE assets and liabilities were included in the BCE Sale and were transferred to Ameresco.

The first stage of the BCE Sale closed on August 4, 2023, with the carrying value of net assets transferred to Ameresco totaling $ 44 million, which included a $ 36 million construction term loan.

The assets and liabilities transferred in this stage related to the BCE Los Alamitos project and were previously primarily classified as construction work in progress and current maturities of long-term debt, respectively.

Our Consolidated Income Statement for the year ended December 31, 2023, includes a pretax gain of $ 6 million relating to this stage of the BCE Sale reported within other income.

Our Consolidated Balance Sheets as of December 31, 2023, includes a $ 28 million note receivable from Ameresco relating to this initial stage of the BCE Sale, which was received in full by Pinnacle West on January 29, 2024.

As of December 31, 2023, our Consolidated Balance Sheets also include $ 35 million of assets classified as held for sale, relating to the remaining assets of BCE that transferred to Ameresco on January 12, 2024, in the second stage of the sale.

These assets held for sale include BCE’s investment in the Kūpono Solar project, and other projects in various stages of development.

The completion of the second stage of the BCE Sale was subject to various conditions precedent, including third-party consents which have been obtained.

Prior to being classified as held for sale, these assets were primarily included in the other assets line item within the investments and other assets section on our Consolidated Balance Sheets.

We measure assets held for sale at the lower of carrying value or fair value less cost to sell.

For the year ended December 31, 2023, no impairment loss was recognized related to the assets classified as held for sale.

The purchase and sale agreement, as amended, provided for Pinnacle West to purchase, from Ameresco, approximately $ 28 million of investment tax credits that were generated by the assets included in the BCE Sale.

The tax credits were purchased and transferred to Pinnacle West on January 30, 2024.

The total carrying value of net assets transferred to Ameresco as a result of the BCE Sale was $ 79 million, with total consideration received by Pinnacle West of $ 108 million, resulting in a total pre-tax gain of $ 29 million, which was recognized between August 4, 2023 and January 12, 2024.

The net assets transferred includes $ 41 million of liabilities that have been assumed by Ameresco.

The consideration received by Pinnacle West includes both cash and interest-bearing promissory notes.

The stages of the BCE Sale and timing of net assets transferring to Ameresco and related gain recognition are as follows:

• The first stage of the BCE Sale was completed on August 4, 2023.

In the first stage, the net assets transferred to Ameresco totaled $ 44 million, which included a $ 36 million construction term loan.

The assets and liabilities transferred in the first stage related to the BCE Los Alamitos project and were previously primarily classified as construction work in progress and current maturities of long-term debt, respectively.

A gain of $ 6 million was recognized on our Consolidated Statements of Income for the year ended December 31, 2023, relating to the first stage of the BCE Sale.

• The final stage of the BCE Sale was completed on January 12, 2024.

In the final stage, the net assets transferred to Ameresco totaled $ 35 million.

The assets transferred in the final stage related primarily to equity method investments in the Kūpono Solar Project and other development stage projects.

These assets were previously classified as assets held for sale on our December 31, 2023, Consolidated Balance Sheets.

Our Consolidated Statements of Income for the year ended December 31, 2024, include a $ 23 million gain relating to the final stage of the BCE Sale.

As of January 12, 2024, all stages of the BCE Sale have been completed.

The purchase and sale agreement, as amended, allows Ameresco to make certain deferred payments relating to the BCE Sale throughout 2024.

Pinnacle West continues to maintain certain performance guarantees relating to the BCE Kūpono Solar project financing which were not transferred in the BCE Sale transaction.

As partial consideration for the BCE Sale, Pinnacle West received a $ 46 million interest-bearing promissory note from Ameresco.

The note required Ameresco to make cash payments to Pinnacle West throughout 2024 and Pinnacle West received payment in full of the note receivable during the fourth quarter of 2024.

As the note receivable has been paid in full, our December 31, 2024 Consolidated Balance Sheets do not include any amounts relating to the promissory note.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Additionally, Pinnacle West continues to maintain certain guarantees relating to the Kūpono Solar Project sale-leaseback financing, which were not transferred in the BCE Sale transaction.

New Accounting Standards

1 unchanged sentence

Improvements to Reportable Segment Disclosures

In November 2023, a new accounting standard was issued that changes disclosures relating to reportable segments.

The new guidance expands the disclosure requirements relating to reportable segments, including requiring entities to disclose information about a reportable segment’s significant expenses, among other changes.

The amended guidance does not change how an entity identifies reportable segments or the accounting for segments.

The new standard is effective for us, using a retrospective approach, on December 31, 2024, with early adoption permitted.

The adoption of the new guidance may result in changes to our reportable segment disclosures, but will not impact our segment accounting or financial statement results.

In November 2023, a new standard was issued that modifies segment reporting disclosure requirements.

The disclosure changes include information about a reportable segment’s significant expenses, details relating to the entity’s chief operating decision maker, and other disclosures.

We adopted this standard on December 31, 2024, using a retrospective approach.

The adoption of the new standard results in changes to our reportable segment disclosures, but does not impact how we identify reportable segments or our financial statement results.

ASU 2023-09, Income Taxes:

1 unchanged sentence

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

The changes require entities to include a tabular income tax rate reconciliation, disclose details on specific reconciliation categories and reconciling items, and disclose the amount of income taxes paid by jurisdiction, among other disclosure changes.

The standard is effective for us on December 31, 2025, using a prospective approach, and may be early adopted.

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

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 will adopt this standard on December 31, 2025, using a prospective approach.

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

ASU 2024-03, Income Statement:

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 income statement.

The standard is effective for us on December 31, 2027, using either a prospective or retrospective approach, 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.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

43 unchanged sentences

Long-term debt less current maturities 867,770 498,731

Deferred income taxes 24,536 —

Pension liabilities 4,462 6,487

39 unchanged sentences

Issuance of long-term debt 867,387 175,000 300,000

Short-term debt repayments under revolving credit facility — — ( 19,000 )

Short-term debt borrowings under revolving credit facility 200,000 — —

Short-term borrowings and (repayments) — net ( 48,100 ) 60,930 2,420

12 unchanged sentences

Investments in subsidiaries are accounted for using the equity method.

The noncontrolling interests relate to the Palo Verde sale leaseback VIE.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

1 unchanged sentence

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

What changed 10-K

Item 8. Financial Statements and Supplementary Data