What changed in this filing

/stocks — the workspaceLOADING

Item 8. Financial Statements and Supplementary Data

2024-02-27 compared with 2023-02-27 · 658 added, 706 removed, 2420 unchanged (36% of the section changed)

33 unchanged sentences

Changes in Accumulated Other Comprehensive Loss

Sale of Bright Canyon Energy

New Accounting Standards

MANAGEMENT’S REPORT ON INTERNAL CONTROL

11 unchanged sentences

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2022, the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”).

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”).

We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

36 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 applicable regulatory environment changes, recent rate orders specific to APS and to other regulated entities in the same jurisdiction, and likelihood of success of legal appeals.

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

Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the ACC and legal bodies, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the ACC, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to regulatory accounting included the following, among others:

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

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

1 unchanged sentence

regulatory assets or liabilities;

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

and the implementation of new rates as ordered by the ACC.

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

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

1 unchanged sentence

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

• We read APS’s 2022 rate application submitted to the ACC on October 28, 2022.

• 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 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.

For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their 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.

• We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery.

We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, read APS’s opening brief submitted to the Arizona Court of Appeals, read the ACC’s Answering Brief, read the Intervenors’ briefs, read APS’s reply brief, and observed the Appeal Oral Arguments, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.

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

53 unchanged sentences

Derivative instruments:

Net unrealized gain (loss), net of tax benefit (expense) of $( 615 ), $( 378 ), and $ 662

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

713 1,873 1,095

Reclassification of net realized gain, net of tax benefit (expense) of $ 0 , $ 18 , and $( 171 ) (Note 15)

Pension and other postretirement benefits activity, net of tax benefit (expense) of $ 801 , $( 7,078 ), and $( 2,256 ) (Note 7)

18 unchanged sentences

Assets from risk management activities (Note 15)

87,835 63,481

Assets held for sale (Note 20)

Deferred fuel and purchased power regulatory asset (Note 3)

10 unchanged sentences

Assets from risk management activities (Note 15)

44,394 46,908

Other assets 102,845 125,672

38 unchanged sentences

Liabilities from risk management activities (Note 15)

80,913 37,697

Liabilities for asset retirements (Note 11)

28,550 12,232

Operating lease liabilities (Note 8)

15 unchanged sentences

112,702 116,286

Liabilities from risk management activities (Note 15)

Customer advances 533,580 422,103

2 unchanged sentences

Unrecognized tax benefits (Note 4)

33,861 38,658

Operating lease liabilities (Note 8)

2 unchanged sentences

Total deferred credits and other 7,946,322 7,060,102

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

COMMITMENTS AND CONTINGENCIES (Note 10)

Common stock, no par value;

22 unchanged sentences

Adjustments to reconcile net income to net cash provided by operating activities:

Gain on sale relating to BCE ( 6,423 ) — —

Depreciation and amortization including nuclear fuel 854,136 817,814 719,141

15 unchanged sentences

Other current liabilities 40,510 ( 1,856 ) ( 51,736 )

Change in margin and collateral accounts — assets 22 ( 50 ) 404

Change in margin and collateral accounts — liabilities 4,200 350 100

Change in unrecognized tax benefits ( 1,989 ) ( 568 ) 2,220

Change in long-term regulatory assets 53,112 12,432 ( 17,012 )

Change in long-term regulatory liabilities 28,495 ( 332,470 ) 57,549

Change in other long-term assets ( 195,598 ) 159,030 ( 345,470 )

Change in operating lease assets 90,525 105,359 116,009

Change in other long-term liabilities 63,080 170,359 78,219

Change in operating lease liabilities ( 65,779 ) ( 103,671 ) ( 108,365 )

Net cash provided by operating activities 1,207,697 1,241,441 860,014

2 unchanged sentences

Contributions in aid of construction 180,866 137,436 105,654

Proceeds from sale relating to BCE 23,400 — —

Allowance for borrowed funds used during construction ( 43,564 ) ( 28,030 ) ( 21,052 )

7 unchanged sentences

Short-term borrowings and (repayments) — net 241,900 48,720 142,000

Short-term debt borrowings under revolving credit facility — — 751,690

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

15 unchanged sentences

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

Other comprehensive loss

Other comprehensive income

— — — 7,935 — 7,935

5 unchanged sentences

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

Other — — 1 — 1 2

Balance, December 31, 2021

13 unchanged sentences

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

Other comprehensive income

Other comprehensive loss

— — — ( 1,709 ) — ( 1,709 )

62 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.

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:

2 unchanged sentences

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.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to regulatory accounting included the following, among others:

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

1 unchanged sentence

regulatory assets or liabilities;

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

and the implementation of new rates as ordered by the ACC.

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

• We 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 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 read the Company’s 2022 rate application submitted to the ACC on October 28, 2022.

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 read the minutes of the Boards of Directors

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

• We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery.

We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, read the Company’s opening brief submitted to the Arizona Court of Appeals, read the ACC’s Answering Brief, read the Intervenors’ briefs, read the Company’s reply brief, and observed the Appeal Oral Arguments, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.

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

47 unchanged sentences

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX

Derivative instruments:

Net unrealized loss, net of tax expense of $ 0 , $ 18 , and $ 18

— ( 18 ) ( 18 )

Reclassification of net realized gain, net of tax benefit (expense) of $ 0 , $ 18 , and $( 171 ) (Note 15)

Pension and other postretirement benefits activity, net of tax benefit (expense) of $ 536 , $( 6,332 ), and $( 1,990 ) (Note 7)

26 unchanged sentences

Assets from risk management activities (Note 15)

44,394 46,908

Other assets 43,625 43,344

10 unchanged sentences

Assets from risk management activities (Note 15)

87,704 63,481

Deferred fuel and purchased power regulatory asset (Note 3)

35 unchanged sentences

532,850 325,000

Current maturities of long-term debt (Note 6)

Accounts payable 433,229 417,732

4 unchanged sentences

Liabilities from risk management activities (Note 15)

80,913 37,697

Liabilities for asset retirements (Note 11)

28,550 12,232

Operating lease liabilities (Note 8)

13 unchanged sentences

106,215 108,068

Liabilities from risk management activities (Note 15)

Customer advances 533,580 422,103

7 unchanged sentences

Total deferred credits and other 7,933,909 7,026,738

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

COMMITMENTS AND CONTINGENCIES (Note 10)

TOTAL LIABILITIES AND EQUITY $ 24,516,455 $ 22,543,852

23 unchanged sentences

Other current liabilities 62,212 1,190 ( 61,297 )

Change in margin and collateral accounts — assets 22 ( 50 ) 404

Change in margin and collateral accounts — liabilities 4,200 350 100

Change in unrecognized tax benefits ( 1,989 ) ( 568 ) 2,220

Change in long-term regulatory assets 53,112 12,432 ( 17,012 )

Change in long-term regulatory liabilities 28,495 ( 332,470 ) 57,549

Change in other long-term assets ( 188,483 ) 170,587 ( 330,642 )

Change in operating lease assets 90,234 105,058 115,850

Change in other long-term liabilities 58,574 168,503 87,376

Change in operating lease liabilities ( 65,482 ) ( 103,361 ) ( 108,216 )

Net cash provided by operating activities 1,275,636 1,230,102 865,554

9 unchanged sentences

Issuance of long-term debt 496,025 524,852 446,999

Repayment of long-term debt — — ( 465,150 )

Short-term borrowings and (repayments) — net 180,970 46,300 278,700

Short-term debt borrowings under revolving credit facility — — 540,000

Short-term debt repayments under revolving credit facility — — ( 540,000 )

Dividends paid on common stock ( 393,600 ) ( 385,800 ) ( 376,500 )

15 unchanged sentences

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

Other comprehensive loss

Other comprehensive income

— — — 6,038 — 6,038

1 unchanged sentence

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

Other — — 1 — 1 2

Balance, December 31, 2021

6 unchanged sentences

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

Other — — 1 — 1 2

Balance, December 31, 2022

2 unchanged sentences

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

Other comprehensive income

Other comprehensive loss

— — — ( 1,623 ) — ( 1,623 )

1 unchanged sentence

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

Other — — ( 2 ) — — ( 2 )

Balance, December 31, 2023

4 unchanged sentences

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA.

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

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

APS accounts for essentially all of our revenues and earnings and is expected to continue to do so.

El Dorado is an investment firm.

BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company’s core expertise in the electric energy industry.

4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso’s 7 % interest in Four Corners.

See Note 10 for more information on 4CA matters.

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

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

See Note 20 for more information on PNW Power.

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

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

The sale was completed on January 12, 2024.

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

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:

APS, El Dorado, BCE and 4CA.

APS, El Dorado, BCE and PNW Power.

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

12 unchanged sentences

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 those estimates.

Actual results could differ from

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

22 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

25 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.

3 unchanged sentences

See Note 11 for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for AROs.

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

Both the debt and equity

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

1 unchanged sentence

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1 unchanged sentence

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

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

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

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

This change impacted the AFUDC composite rate in 2020 and 2021 but did not impact prior years or 2022.

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

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

14 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 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

2 unchanged sentences

See Note 12 for additional information about fair value measurements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Accounting

18 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.

4 unchanged sentences

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we accrued a receivable and an offsetting regulatory liability through the settlement period which ended December of 2022.

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

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

10 unchanged sentences

2023 2022 2021

Cash paid (received) during the period for:

Cash paid during the period for:

Income taxes, net of refunds $ 8,788 $ 46,227 $ 229

3 unchanged sentences

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

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):

7 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Intangible Assets

6 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).

BCE holds investments in equity securities.

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).

7 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 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

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.

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.

2 unchanged sentences

APS enters into purchased power contracts that may contain leases.

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

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

Purchased power lease contracts may also include energy storage facilities.

Lease costs relating to purchased power lease contracts are

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

7 unchanged sentences

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

Year Ended December 31, Year Ended December 31, Year Ended December 31,

Year Ended December 31,

2023 2022 2021

Retail Electric Service

Residential $ 2,046,111 $ 1,913,324 $ 1,929,178 (a)

Residential $ 2,289,196 $ 2,046,111 $ 1,913,324

Non-Residential 2,048,416 1,767,616 1,586,940

3 unchanged sentences

Total Operating Revenues $ 4,695,991 $ 4,324,385 $ 3,803,835

(a) Residential revenues for the year ended December 31, 2020, reflect a $ 24 million reduction related to the Arizona Attorney General matter.

See Note 10 .

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retail Electric Revenue.

Pinnacle West’s retail electric revenue is generated by wholly-owned regulated subsidiary APS’s sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage.

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

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

Revenues related to the sale of electricity are generally recognized when service is rendered, or electricity is delivered to customers.

3 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Wholesale Energy Sales and Transmission Services for Others.

7 unchanged sentences

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

Our revenues from contracts with customers for the year ended December 31, 2022, 2021 and 2020 were $ 4,302 million, $ 3,760 million, and $ 3,533 million, respectively.

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.

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

For the year ended December 31, 2022, 2021 and 2020, our revenues that do not qualify as revenue from contracts with customers were $ 22 million, $ 44 million and $ 54 million, respectively.

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.

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

4 unchanged sentences

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, 2022, and 2021.

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 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.

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.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

Year Ended December 31, 2022 Year Ended December 31, 2021 Year Ended December 31, 2020

Year Ended December 31,

2023 2022 2021

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

7 unchanged sentences

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 are:

The principal provisions of APS’s application were:

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

8 unchanged sentences

• modification of its adjustment mechanisms including:

▪ eliminate the Environmental Improvement Surcharge and collect costs through base rates,

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

▪ maintain as inactive the Tax Expense Adjustor Mechanism,

▪ maintain the Transmission Cost Adjustment mechanism,

▪ modify the performance incentive in the DSMAC, and

▪ 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

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

▪ 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.

APS requested that the increase become effective December 1, 2023.

The hearing for this rate case is currently scheduled to begin in August 2023.

APS cannot predict the outcome of its request.

2019 Retail Rate Case

APS filed an application with the ACC on October 31, 2019 (the “2019 Rate Case”) seeking an increase in annual retail base rates of $ 69 million.

This amount includes recovery of the deferral and rate base effects of the Four Corners Power Plant (“Four Corners”) selective catalytic reduction (“SCR”) project that was the subject of a separate proceeding.

See “Four Corners SCR Cost Recovery” below.

It also reflects a net credit to base rates of approximately $ 115 million primarily due to the prospective inclusion of rate refunds currently provided through the Tax Expense Adjustment Mechanism (“TEAM”).

The proposed total annual revenue increase in APS’s application is $ 184 million.

The average annual customer bill impact of APS’s request is an increase of 5.6 % (the average annual bill impact for a typical APS residential customer is 5.4 %).

The principal provisions of APS’s application were:

• a test year comprised of 12 months ended June 30, 2019, adjusted as described below;

• an original cost rate base of $ 8.87 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 45.3 % 4.10 %

Common stock equity 54.7 % 10.15 %

Weighted-average cost of capital 7.41 %

• 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 $ 0.030168 per kWh for the Base Fuel Rate;

• authorization to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

• a number of proposed rate and program changes for residential customers, including:

▪ a super off-peak period during the winter months for APS’s time-of-use with demand rates;

▪ additional $ 1.25 million in funding for APS’s limited-income crisis bill program;

▪ a flat bill/subscription rate pilot program;

• proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 megawatt (“MW”) of medium and large commercial customers;

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement);

• continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the “Navajo Plant”) (see “Navajo Plant” below).

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC.

The ACC Staff recommended, among other things, (i) an $ 89.7 million revenue increase, (ii) an average annual customer bill increase of 2.7 %, (iii) a return on equity of 9.4 %, (iv) a 0.3 % or, as an alternative, a 0 % return on the increment of fair value rate base greater than original cost , (v) the recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) the recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project.

RUCO recommended, among other things, (i) a $ 20.8 million revenue decrease, (ii) an average annual customer bill decrease of 0.63 %, (iii) a return on equity of 8.74 %, (iv) a 0 % return on the increment of fair value rate base, (v) the nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) the recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application.

On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, (i) a $ 169 million revenue increase, (ii) average annual customer bill increase of 5.14 %, (iii) return on equity of 10 %, (iv) return on the increment of fair value rate base of 0.8 %, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $ 25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components:

(i) $ 100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $ 1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $ 10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $ 2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners through 2038, which would be funds not recoverable through rates, (v) $ 12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $ 3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, which would primarily be funded by customers.

The commitment of funds that would not be recoverable through rates of $ 25 million were recognized in our December 31, 2020 financials.

In 2021, APS committed an additional $ 0.9 million to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in its December 31, 2021 financials.

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.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony.

The ACC Staff reduced its recommended rate increase to $ 59.8 million, or an average annual customer bill increase of 1.82 %.

In RUCO’s surrebuttal, the recommended revenue decrease changed to $ 50.1 million, or an average annual customer bill decrease of 1.52 %.

The hearing concluded on March 3, 2021, and the post-hearing briefing concluded on April 30, 2021.

On August 2, 2021, the 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 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 Navajo Plant regulatory asset recovery, (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 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, and (iii) $ 1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant.

2019 Retail Rate Case

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

On August 2, 2021, an Administrative Law Judge issued a 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 %, (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 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:

(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.

1 unchanged sentence

Monday through Friday, excluding holidays.

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

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.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

The Court took the matter under advisement and will issue its decision in due course.

APS cannot predict the outcome of this proceeding.

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 and will be continuing to explore whether penalties or rebates would be owed to certain customers.

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.

APS cannot predict if the ACC will take any further action on this matter.

Additionally, consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT:

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:

(i) $ 6.66 million to the Navajo Nation;

7 unchanged sentences

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.

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.

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.

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,

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

3 unchanged sentences

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.

APS cannot predict if the ACC will take any further action on this matter.

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

2 unchanged sentences

APS cannot predict the outcome of this matter.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2016 Retail Rate Case Filing and the 2017 Settlement Agreement

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates.

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, RUCO, limited income advocates and private rooftop solar organizations signed a settlement agreement (the “2017 Settlement Agreement”) and filed it with the ACC.

The 2017 Settlement Agreement provides for, among other things, a net retail base rate increase of $ 94.6 million, excluding the transfer of adjustor balances, consisting of:

(1) a non-fuel, non-depreciation, base rate increase of $ 87.2 million per year;

(2) a base rate decrease of $ 53.6 million attributable to reduced fuel and purchased power costs;

and (3) a base rate increase of $ 61.0 million due to changes in depreciation schedules.

On August 15, 2017, the ACC approved the 2017 Settlement Agreement without material modifications, and on August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the “2017 Rate Case Decision”).

The new rates went into effect on August 19, 2017.

See “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to the rate plan comparison tool offered to APS customers and other related issues.

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.

APS cannot predict the outcome of this matter.

Cost Recovery Mechanisms

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

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

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

Renewable Energy Standard .

4 unchanged sentences

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.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision.

APS Solar Communities is a 3 -year program authorizing APS to spend $ 10 million to $ 15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities.

The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES.

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $ 86.3 million.

APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2020.

On September 23, 2020, the ACC approved the 2020 RES Implementation Plan, including APS’s requested

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

waiver of the residential distributed energy requirements for 2020.

In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems.

Recovery of the costs associated with the pilot will be addressed in the 2021 Demand Side Management Implementation Plan (“DSM Plan”).

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $ 84.7 million.

APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2021.

In the 2021 RES Implementation Plan, APS requested $ 4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020.

On June 7, 2021, the ACC approved the 2021 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2021.

As part of the approval, the ACC approved the requested budget and authorized APS to collect $ 68.3 million through the Renewable Energy Adjustment Charge to support APS’s RES programs.

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 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 requests for proposals (“RFP”) requirements and the IRP process.

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.

See “Energy Modernization Plan” below for more information.

1 unchanged sentence

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

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

APS’s budget proposal supports existing approved projects and commitments and requests 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 Commission’s consideration at a future date.

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

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

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

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

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.

The community solar program was 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.

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

This budget contains funding for programs to comply with Commission-approved initiatives, including the 2019 Rate Case decision.

APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

residential and non-residential distributed energy requirements for 2022.

This budget contained funding for programs to comply with ACC-approved initiatives, including the 2019 Rate Case decision.

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

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

In response to an ACC inquiry, the ACC Staff filed a report providing the history of APS’s long-term purchased power contract of the 280 MW Concentrating Solar Power Plant.

This report outlines alternative options that the ACC could pursue to address the costs of this contract, which was executed in February 2008.

On July 13, 2022, the ACC approved an option to take no action at this time.

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

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

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

Demand Side Management Adjustor Charge .

1 unchanged sentence

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

however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its Lost Fixed Cost Recovery (“LFCR”) mechanism.

See below for discussion of the LFCR.

On December 31, 2019, APS filed its 2020 DSM Plan, which requested a budget of $ 51.9 million and continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies.

The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only.

On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic.

The amended 2020 DSM Plan requested the same budget amount of $ 51.9 million.

On September 23, 2020, the ACC approved the amended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers.

On May 5, 2020, the ACC approved APS returning $ 36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020.

APS has refunded approximately $ 43 million to customers.

The additional $ 7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption during the refund period.

The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, as described below.

On December 31, 2020, APS filed its 2021 DSM Implementation Plan, which requested a budget of $ 63.7 million and continued APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19.

On April 6, 2021, APS filed an amended 2021 DSM Implementation Plan that proposed an additional one-time incentive for customers participating in the residential energy storage pilot program approved in the 2020 RES Implementation Plan.

On July 13, 2021, the ACC approved the amended 2021 DSM Implementation Plan.

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

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

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

On November 30, 2022,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

The 2023 TE Plan detailed APS’s efforts to grow and 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.

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

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

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

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

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

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

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

APS cannot predict the outcome of this proceeding.

Power Supply Adjustor Mechanism and Balance.

8 unchanged sentences

• the PSA rate may not be increased or decreased more than $ 0.004 per kWh in a year without permission of the ACC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2023 and 2022 (dollars in thousands):

6 unchanged sentences

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

The 2020 PSA rate is a $ 0.002115 per kWh decrease compared to the 2019 PSA year.

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

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

On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021.

That rate was $ 0.003544 per kWh, which consisted of a forward component of $ 0.003434 per kWh and a historical component of $ 0.000110 per kWh.

The 2021 PSA rate is a $ 0.004 per kWh increase compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA.

This left $ 215.9 million of fuel and purchased power costs above this annual cap which will be reflected in

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

future year resets of the PSA.

These rates were to be effective on February 1, 2021, but APS delayed the effectiveness of these rates until the first billing cycle of April 2021 due to concerns of the impact on customers during COVID-19.

In March 2021, the ACC voted to implement the 2021 PSA rate on a staggered basis, with 50 % of the rate increase taking effect in April 2021, and the remaining 50 % taking effect in November 2021.

The PSA rate implemented on April 1, 2021 was $ 0.001544 per kWh, which consisted of a forward component of $( 0.004444 ) per kWh and a historical component of $ 0.005988 per kWh.

On November 1, 2021, the remaining increase was implemented to a rate of $ 0.003544 per kWh and consisted of a forward component of $( 0.004444 ) per kWh and a historical component of $ 0.007988 per kWh.

As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit to better understand the factors that contributed to the increase in fuel costs.

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

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.

1 unchanged sentence

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

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

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

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

On 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.

As of October 31, 2022, the amount in the PSA balancing account was approximately $ 456 million of fuel and purchased power costs.

On February 23, 2023, the ACC approved a rate of $ 0.019074 per kWh that will continue until further notice of the ACC.

The rate will become 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 will also be required to notify the ACC when the PSA balancing account approaches $ 500,000 .

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA, and on January 12, 2021, the ACC approved this application.

On October 28, 2021, APS filed an application requesting approval to recover costs related to three additional energy storage projects through the PSA once the systems are in service, and on December 16, 2021, the ACC approved this application.

On February 22, 2022, APS filed an application requesting similar recovery through the PSA for a solar plus energy storage project, and on April 13, 2022, the ACC approved this application.

On December 21, 2022, APS filed an application requesting similar recovery through the PSA for a solar plus energy storage project, and on February 22, 2023, the ACC approved this application.

For the applications that were approved by the ACC, the ACC has not yet ruled on prudency.

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.

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”).

1 unchanged sentence

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.

There is 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, and it will become effective with the first billing cycle in April 2023 absent the ACC taking action.

Transmission Rates, Transmission Cost Adjustor (“TCA”) and Other Transmission Matters .

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.

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.

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.

8 unchanged sentences

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

On March 17, 2020, APS made 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 statutory tax rate changes.

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, 2020, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $ 6.1 million for the 12-month period beginning June 1, 2020, in accordance with the FERC-approved formula.

Of this net amount, wholesale customer rates increased by $ 4.8 million and retail customer rates would have decreased by approximately $ 10.9 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 a total of $ 7.4 million, resulting in reductions to both residential and commercial

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.

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.

6 unchanged sentences

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

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

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

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

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

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 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement.

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

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

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.

Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.

1 unchanged sentence

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

On February 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $ 26.6 million (a $ 9.6 million decrease from previous levels).

On April 14, 2020, the ACC approved the 2020 LFCR adjustment as filed, effective with the first billing cycle in May 2020.

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).

2 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

rate for the subsequent year is set at zero.

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.

5 unchanged sentences

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

APS does not believe further ACC approval is needed to move the filing date, and APS intends to file its 2023 annual LFCR adjustment later in 2023 in accordance with the July 31 deadline.

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

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

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

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

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.

Tax Expense Adjustor Mechanism .

1 unchanged sentence

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

On December 22, 2017, the Tax Act was enacted.

This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On August 13, 2018, APS filed a request with the ACC that addressed the return of $ 86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers (“TEAM Phase II”).

The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020.

On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020.

Amounts credited to customers after the last billing cycle in March 2020 were recorded as a part of the balancing account and were addressed for recovery as part of the 2019 Rate Case.

Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit were recognized based upon our seasonal kWh sales pattern.

On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 -year period consistent with IRS normalization rules (“TEAM Phase III”).

On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $ 64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which provided an additional benefit of $ 39.5 million to customers through December 31, 2020.

On November 20, 2020, APS filed an application to continue the TEAM Phase III monthly bill credit through the earlier of December 31, 2021, or at the conclusion of the 2019 Rate Case.

On December 9, 2020, the ACC approved this request.

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.

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

the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit were recognized based upon APS’s seasonal kWh sales pattern.

As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021, and all impacts of the Tax Act were removed from the TEAM and incorporated into APS’s base rates.

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

APS’s 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 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 projects.

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.

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.

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.

7 unchanged sentences

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.

In accordance with the 2017 Rate Case Decision, APS filed its request for a RCP export energy price of 10.5 cents per kWh on May 1, 2019.

This price also reflects the 10 % annual reduction discussed above.

The new rate rider became effective on October 1, 2019.

APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020.

This price reflects the 10 % annual reduction discussed above.

On September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021.

In accordance with this decision, the RCP export energy price of 9.4 cents per kWh became effective on October 1, 2021.

On April 29, 2022, APS filed an application to decrease the RCP price to 8.46 cents per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2022.

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

See “2016 Retail Rate Case Filing” above for information regarding an ACC order in connection with the rate review of the 2017 Rate Case Decision requiring APS to provide grandfathered net metering customers on legacy demand rates with an opportunity to switch to another legacy rate to enable such customers to benefit from legacy net metering rates.

Subpoena from Former Arizona Corporation Commissioner Robert Burns

On August 25, 2016, then-Commissioner Robert Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016.

The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions.

The return date for the production of information was set as September 15, 2016.

The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

After various proceedings between September 2016 and March 2020, at which time Burns’ appeal of a prior dismissal by the trial court was pending before the Arizona Court of Appeals, Burns’ position as an ACC commissioner ended on January 4, 2021.

Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter.

On March 4, 2021, the Court of Appeals found Burns’ motion to be moot because the Court of Appeals had issued an opinion deciding the matter that same day.

In its March 4, 2021, opinion, the Court of Appeals affirmed the trial court’s dismissal of Burns’ complaint, concluding that Burns could not overturn the ACC’s 4-1 vote refusing to enforce his subpoenas.

On May 15, 2021, Burns filed a petition for review with the Arizona Supreme Court asking for reversal of the Court of Appeals opinion and the trial court’s judgment.

APS and the ACC filed responses to Burns’ petition on July 14, 2021, requesting that the petition be denied.

The Arizona Supreme Court granted Burns’ petition and heard oral argument on March 8, 2022.

On September 27, 2022, the Arizona Supreme Court issued a decision in favor of Burns reversing the Court of Appeals’ decision.

The Court held that the ACC acting by a majority of its commissioners may not prevent an individual commissioner from exercising investigatory powers pursuant to certain provisions of the Arizona Constitution and that a commissioner aggrieved by such action may seek judicial recourse by way of declaratory judgment.

Pinnacle West and APS do not believe there will be any immediate implications given the underlying issues at hand are moot, but the Company cannot predict if or how this authority may be used by commissioners in the future.

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

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

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

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.

Energy Modernization Plan

On January 30, 2018, the initial Energy Modernization Plan was proposed, which consisted of a series of energy policies tied to clean energy sources.

Draft energy rules were subsequently issued and a series of revisions were made to the draft rules in 2019 and 2020.

On July 30, 2020, the ACC Staff issued final draft energy rules which proposed 100% of retail kWh sales from clean energy resources by the end of 2050.

Nuclear power was defined as a clean energy resource.

The proposed rules also required 50% of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

retail energy served be renewable by the end of 2035.

A new Energy Efficiency Standard (“EES”) was not included in the proposed rules.

The ACC discussed the final draft energy rules at several different meetings in 2020 and 2021.

On November 13, 2020, the ACC approved a final draft energy rules package.

On April 19, 2021, the Administrative Law Judge issued a Recommended Order and Opinion on the final energy rules.

In June 2021, the ACC adopted revised clean energy rules based on a series of ACC amendments.

The adopted rules included a final standard of 100% clean energy by 2070 and the following interim standards for carbon reduction from baseline carbon emissions level:

50% reduction by December 31, 2032;

65% reduction by December 31, 2040;

80% reduction by December 31, 2050, and 95% reduction by December 31, 2060.

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 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.

During the August 2022 Open Meeting, Commissioners voted to postpone a decision on the All-Source RFP and IRP rulemaking package until 2023.

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.

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.

APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop 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 timeframe.

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

Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020.

On February 20, 2020, the ACC extended the deadline for all utilities to file their IRPs from April 1, 2020, to June 26, 2020.

On June 26, 2020, APS filed its final IRP.

On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021.

In February 2022, the ACC acknowledged APS’s IRP.

In February 2022, the ACC acknowledged APS’s 2020 IRP filed on June 26, 2020.

The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by January 1, 2030.

APS intends to file its next IRP later in 2023.

On May 1, 2023, APS, Tucson Electric Power Company, and UNS Electric, Inc.

filed a joint request for an extension to file the IRPs from August 1, 2023, to November 1, 2023.

On June 21, 2023, the ACC granted the extension.

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.

See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

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

Public Utility Regulatory Policies Act

4 unchanged sentences

In March 2021, the ACC approved these agreements.

On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA.

The final rule went into effect on December 31, 2020.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Residential Electric Utility Customer Service Disconnections

2 unchanged sentences

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 and customers will have four months to pay back their deposit and any remaining delinquent amounts.

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.

4 unchanged sentences

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, and APS has employed the calendar method for its disconnection moratorium.

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 beginning of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements.

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 addition, APS voluntarily began waiving late payment fees of its customers (“Late Fee Waivers”) on March 13, 2020.

14 unchanged sentences

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 and intends to intervene to contest it.

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 his insights on the applicable law.

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.

1 unchanged sentence

APS cannot predict the outcome of these future activities .

Rate Plan Comparison Tool and Investigation

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and APS’s meter data management system.

APS immediately removed the tool from its website and notified the ACC.

The purpose of the tool was to provide customers with a rate plan recommendation based upon historical usage data.

Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019, and November 14, 2019.

By the middle of May 2020, APS provided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $ 25 payment for any inconvenience that the customer may have experienced.

The refunds and payment for inconvenience being provided did not have a material impact on APS’s financial statements.

In February 2020, APS launched a new online rate comparison tool.

The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool.

On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

report concluded APS’s new rate comparison tool is working as intended.

The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $ 25 inconvenience payment to approximately 3,800 additional customers.

These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements.

On September 28, 2020, the ACC discussed this report but did not take any action.

APS cannot predict whether additional inquiries or actions may be taken by the ACC .

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement.

APS fully cooperated with the Attorney General’s Office in this matter.

On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter.

The settlement resulted in APS paying $ 24.75 million, approximately $ 24 million of which has been returned to customers as restitution.

While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

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

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.

4 unchanged sentences

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 argument on November 30, 2022.

The Court took the matter under advisement and will issue its decision in due course.

Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2022.

If the 2019 Rate Case decision to disallow $ 215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $ 154.4 million.

We cannot predict the outcome of the legal

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

challenges nor the timing of when this matter will be resolved.

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

On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals.

On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs.

See above for further discussion on the 2019 Rate Case decision.

4 unchanged sentences

In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020.

APS has committed to end the use of coal at its remaining Cholla units by 2025.

APS is required to cease burning coal at its remaining Cholla units by April 2025.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033.

3 unchanged sentences

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Navajo Plant ceased operations in November 2019.

13 unchanged sentences

Income taxes — AFUDC equity 2053 189,058 179,631

Ocotillo deferral (e) 2031 138,143 147,650

Ocotillo deferral 2031 128,636 138,143

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

SCR deferral (e) 2038 89,477 97,624

Retired power plant costs 2033 83,536 98,692

SCR deferral (e) (f) 2031 97,624 105,771

Deferred property taxes 2027 41,057 49,626

Deferred compensation 2036 33,660 33,997

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

Income taxes — investment tax credit basis adjustment 2056 34,230 23,977

Deferred compensation 2036 33,972 33,660

Deferred property taxes 2027 32,488 41,057

Palo Verde VIEs (Note 17)

2046 20,772 20,933

Active union medical trust (g) 18,226 1,175

Four Corners cost deferral 2024 15,999 24,075

Power supply adjustor-interest 2024 19,416 1,541

Active union medical trust (f) 12,747 18,226

Navajo coal reclamation 2026 10,883 13,862

Lost fixed cost recovery (b) 2023 9,547 63,889

Loss on reacquired debt 2038 9,468 11,020

Mead-Phoenix transmission line — contributions in aid of construction 2050 8,716 9,048

Loss on reacquired debt 2038 7,965 9,468

Four Corners cost deferral 2024 7,922 15,999

Tax expense adjustor mechanism (b) 2031 5,190 5,845

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

Other Various 4,528 6,630

1 unchanged sentence

current regulatory assets $ 625,757 $ 538,879

Total noncurrent regulatory assets $ 1,283,221 $ 1,192,987

Total non-current regulatory assets $ 1,390,279 $ 1,283,221

(a) This asset represents the future recovery of pension benefit obligations and expense through retail rates.

1 unchanged sentence

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.

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.”

(e) Balance includes amounts for future regulatory consideration and amortization period determination.

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

(g) Collected in retail rates.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(f) Collected in retail rates.

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

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

5 unchanged sentences

Removal costs (c) 94,368 106,889

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

2024 96,367 107,601

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

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

Four Corners coal reclamation 2038 55,917 52,592

Income taxes — deferred investment tax credit 2056 48,035 49,601

Spent nuclear fuel 2027 39,217 45,282

Renewable energy standard (b) 2024 43,251 35,720

FERC transmission true up (b) 2024 22,895 34,303

Property tax deferral (e) 2024 15,521 20,192

Spent nuclear fuel 2027 33,154 39,217

Sundance maintenance 2031 19,989 16,893

Demand side management (b) 2023 14,374 8,461

Tax expense adjustor mechanism (b) (e) N/A 4,835 4,835

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

Tax expense adjustor mechanism (b) 2031 4,835 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 3,873 3,092

1 unchanged sentence

current regulatory liabilities $ 209,923 $ 271,575

Total noncurrent regulatory liabilities $ 2,061,776 $ 2,499,213

Total non-current regulatory liabilities $ 1,965,865 $ 2,061,776

(a) For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.

2 unchanged sentences

(d) See Note 7.

(e) Balance includes amounts for future regulatory consideration and amortization period determination.

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.

The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.

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.

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.

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.

51 unchanged sentences

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

Allowance for equity funds used during construction (see Note 1)

Allowance for equity funds used during construction (Note 1)

( 5,964 ) ( 4,629 ) ( 4,180 ) ( 5,964 ) ( 4,629 ) ( 4,180 )

Palo Verde VIE noncontrolling interest (see Note 17)

Palo Verde VIE noncontrolling interest (Note 17)

( 3,617 ) ( 3,617 ) ( 3,617 ) ( 3,617 ) ( 3,617 ) ( 3,617 )

Investment tax credit amortization ( 9,495 ) ( 5,608 ) ( 7,620 ) ( 9,495 ) ( 5,608 ) ( 7,620 )

Federal production tax credit ( 8,441 ) ( 3,146 ) ( 3,064 ) ( 5,460 ) — —

Other federal income tax credits ( 3,453 ) ( 7,721 ) ( 3,912 ) ( 2,803 ) ( 7,721 ) ( 3,912 )

36 unchanged sentences

Deferred income taxes — net $ ( 2,416,480 ) $ ( 2,384,421 ) $ ( 2,431,697 ) $ ( 2,385,647 )

As of December 31, 2022, PNW consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $ 43 million, which first begin to expire in 2024.

PNW consolidated credit and loss carryforwards amount above has been reduced by $ 5 million of unrecognized tax benefits.

As of December 31, 2022, APS consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $ 19 million, which first begin to expire in 2025.

As of December 31, 2023, Pinnacle West consolidated deferred tax assets for credit and loss carryforwards relate to federal and state credit carryforwards, net of federal benefit, of $ 56 million, which first begin to expire in 2025.

Pinnacle West consolidated credit and loss carryforwards amount above has been reduced by $ 12 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.

6 unchanged sentences

Commitments under Credit Facilities $ 200,000 $ 1,250,000 $ 1,450,000 $ 200,000 $ 1,000,000 $ 1,200,000

Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings ( 15,720 ) ( 325,000 ) ( 340,720 ) ( 13,300 ) ( 278,700 ) ( 292,000 )

Outstanding short-term borrowings ( 76,650 ) ( 532,850 ) ( 609,500 ) ( 15,720 ) ( 325,000 ) ( 340,720 )

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

Commitment Fees 0.175 % 0.125 % 0.175 % 0.125 %

Weighted-Average Commitment Fees 0.170 % 0.120 % 0.175 % 0.125 %

Pinnacle West

At December 31, 2022, Pinnacle West had a $ 200 million revolving credit facility that matures on May 28, 2026.

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

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.

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

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

1 unchanged sentence

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, 2022, APS had two $ 500 million revolving credit facilities that total $ 1 billion and that mature on May 28, 2026.

APS may increase the amount of each facility up to a maximum of $ 700 million, for a total of $ 1.4 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 agreements include 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.

These facilities are available to support APS’s general corporate purposes, including support for APS’s $ 750 million commercial paper program, for bank borrowings or for issuances of letters of credit.

At December 31, 2022, APS ha d no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $ 325 million of outstanding commercial paper b orrowings.

See “Financial Assurances” in Note 10 for a discussion of other outstanding letters of credit.

The weighted-average interest rate for the outstanding borrowings on December 31, 2023, was 5.47 %.

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.

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.

The weighted-average interest rate for the outstanding borrowings on December 31, 2023, was 5.46 %.

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.

Borrowings under the facility bear interest at SOFR plus 1.0 % per annum.

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

See “Financial Assurances” in Note 10 for a discussion of other outst anding letters of credit.

Debt Provisions

On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved 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 15, 2022, the ACC issued a financing order that, among other things, reaffirmed the short-term debt authorization from the 2020 financing order.

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).

See Note 6 for additional long-term debt provisions.

17 unchanged sentences

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

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

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

Unamortized debt issuance cost — ( 135 )

14 unchanged sentences

(b) The weighted-average interest rate for the variable rate pollution control bonds was 4.11 % at December 31, 2023, and 3.96 % at December 31, 2022.

See additional details below.

(d) The weighted-average interest rate for the variable rate equity bridge loan is 5.18 % at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(e) The weighted-average interest rate for the variable rate construction facility is 5.71 % at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023.

See additional details below.

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

Year Consolidated

Pinnacle West Consolidated

2023 $ 50,685 $ — $ 50,685

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

Year Pinnacle West Consolidated APS Consolidated

2024 $ 875,000 $ 250,000

18 unchanged sentences

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

On December 21, 2021, $ 150 million of the proceeds were received and recognized as long-term debt on the Consolidated Balance Sheets.

On January 6, 2022, the remaining $ 300 million of proceeds was received and recognized on that date as long-term debt on the Consolidated Balance Sheets.

The proceeds were used for general corporate purposes.

On December 23, 2020, Pinnacle West entered into a $ 150 million term loan facility that was set to mature June 30, 2022.

The proceeds were received on January 6, 2023, and used for general corporate purposes.

We recognized the term loan facility as long-term debt upon settlement on January 6, 2023.

On January 6, 2022, Pinnacle West repaid this term loan facility early.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The proceeds were received on January 6, 2023 and used for general corporate purposes.

We recognized the term loan facility as long-term debt upon settlement on January 6, 2023.

On January 6, 2022, Pinnacle West contributed $ 150 million into APS in the form of an equity infusion.

APS used this contribution to repay short-term indebtedness.

On September 15, 2022, APS remarketed $ 128 million of the Maricopa County, Arizona Pollution Control Corporation Revenue Refunding Bonds, 2009 Series B, C, D and E, due May 1, 2029 (the “Bonds”).

The Bonds were originally issued on June 26, 2009, and prior to this remarketing were held as treasury bonds.

Each series of the Bonds has a principal amount of $ 32 million.

All series of the Bonds have been remarketed and issued in weekly variable interest rate modes and are classified as long-term debt on our Consolidated Balance Sheets.

On November 8, 2022, APS issued $ 400 million of 6.35 % unsecured senior notes that mature December 15, 2032.

The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper, replenish cash used to fund capital expenditures, and for general corporate purposes.

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.

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.

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

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 a 31 MW solar and battery storage project in Los Alamitos, California (“Los Alamitos”) that is under development by the subsidiary.

The credit agreement consists of an approximately $ 33 million equity bridge loan facility, an approximately $ 42 million non-recourse construction facility, and an approximately $ 5 million letter of credit facility.

In connection with the credit agreement, Pinnacle West has issued a guarantee of up to $ 42 million primarily relating to the equity bridge loan.

As of December 31, 2022, $ 28 million has been drawn from the equity bridge loan and there is a $ 23 million outstanding balance for the construction facility and $ 2.5 million letters of credit outstanding under the credit facility.

The equity bridge loan and construction facility mature and are due on the project’s commercial operation date, expected on or before August 15, 2023.

BCE expects to convert the construction facility into a term loan upon the project’s commercial operation date.

On October 19, 2022, BCE executed an interest rate swap to hedge the variable interest rate exposure of this credit facility.

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.

On August 4, 2023, Pinnacle West entered into a purchase and sale agreement with Ameresco, Inc.

(“Ameresco”), pursuant to which we agreed to sell all our equity interest in BCE to Ameresco (the “BCE Sale”).

As a part of the BCE Sale closing, the $ 36 million construction facility, the letter of credit facility, and the interest rate swap were transferred to Ameresco.

On August 4, 2023, concurrent with the BCE Sale, Pinnacle West paid in full the outstanding $ 31 million equity bridge loan balance.

As of December 31, 2023, there is no outstanding balance on our Consolidated Balance Sheets relating to this credit agreement.

On April 18, 2023, and on December 29, 2023, Pinnacle West issued performance guarantees in connection with BCE’s Kūpono Solar investment project financing.

BCE held an equity method investment relating to the Kūpono Solar project that was included in the BCE Sale relating to the stage of the BCE Sale that closed on January 12, 2024.

The performance guarantees did not transfer in the BCE Sale, and Pinnacle West continues to retain these performance guarantees.

Debt Provisions

1 unchanged sentence

Pinnacle West and APS comply with this covenant.

For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

capitalization not exceed 65 %.

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

At December 31, 2023, the ratio was approximately 60 % for Pinnacle West and 52 % for APS.

6 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 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s long-term debt authorization of $ 7.5 billion.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retirement Plans and Other Postretirement Benefits

12 unchanged sentences

We retain the right to change or eliminate these benefits.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.

2 unchanged sentences

Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy.

Prior to 2020, we had been assuming a 4.75 % escalation of these benefits;

however, actual escalation has been significantly less than this assumption.

Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00 % (see weighted-average assumption table below).

This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020.

As a result, on January 4, 2021, we initiated the transfer of approximately $ 106 million of investment assets from the other postretirement benefit plan into the Active Union Employee Medical Account Trust.

The Active Union Employee Medical Account is an existing trust account that holds investments restricted for paying active union employee medical costs.

The transfer of other postretirement benefit plan investment assets into the Active Union Employee Medical Account permits access to approximately $ 106 million of assets for the sole purpose of paying active union employee medical benefits.

This transfer of investment assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and are recoverable in rates.

10 unchanged sentences

Amortization of:

Prior service credit — — — ( 37,789 ) ( 37,705 ) ( 37,575 )

Prior service credit (a) — — — ( 37,789 ) ( 37,789 ) ( 37,705 )

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

1 unchanged sentence

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

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

The impact of these modifications is amortized over a period which reflects the demographics of the impacted population.

In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits.

We have been amortizing these prior-serviced credits since 2015 with the last full-year amortization occurring in 2024.

The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):

10 unchanged sentences

Fair value of plan assets at January 1 2,829,485 3,812,041 652,287 872,435

Actual return on plan assets ( 787,874 ) 18,169 ( 193,807 ) 41,432

Employer contributions — 100,000 — —

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

Benefit payments ( 193,034 ) ( 194,682 ) ( 23,110 ) ( 26,341 )

Transfer to active union medical account — — — ( 105,852 )

Fair value of plan assets at December 31 2,835,549 2,829,485 696,494 652,287

Funded Status at December 31 $ 19,956 $ 95,217 $ 242,826 $ 280,594

Funded/(Underfunded) Status at December 31 $ ( 72,514 ) $ 19,956 $ 266,060 $ 242,826

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, 2023, and December 31, 2022, therefore, the only pension plan with an accumulated benefit obligation in excess of plan assets in 2023 and 2022 is a non-qualified supplemental excess benefit retirement plan.

23 unchanged sentences

As of December 31, Benefit Costs

For the Years Ended December 31,

Year Ended December 31,

2023 2022 2023 2022 2021

7 unchanged sentences

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

Initial and ultimate healthcare cost trend rate (post-65 participants) (a) 2.00 % 2.00 % 2.00 % 2.00 % 4.75 %

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

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

(a) See discussion above relating to this assumptions impact on benefit obligations and the January 2021 asset transfer to the Active Union Employee Medical Account.

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan.

3 unchanged sentences

The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets.

The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.

The investment strategies for these plans include external management of plan assets.

The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations.

To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-seeking assets.

The target allocation between return-seeking and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status.

The target allocation between return-seeking and long-term fixed income assets is defined in the IPS.

The plan’s funded status is reviewed on at least a monthly basis.

1 unchanged sentence

Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S.

Treasury and other

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

government agencies, U.S.

Treasury and other government agencies, U.S.

Treasury futures contracts, and fixed income debt securities issued by corporations.

Long-term fixed income assets may also include interest rate swaps, and other instruments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Return-seeking assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.

2 unchanged sentences

International equities include investments in both developed and emerging markets.

Alternative investments may include investments in real estate, private equity and various other strategies.

Alternative investments may include investments in real estate, private debt and various other strategies.

The plan may also hold investments in return-seeking assets by holding securities in partnerships, common and collective trusts, and mutual funds.

Based on the IPS, and given the pension plan’s funded status at year-end 2022, the target and actual allocation for the pension plan at December 31, 2022, are as follows:

Based on the IPS, the target and actual allocation for the pension plan at December 31, 2023, are as follows:

Target Allocation Actual Allocation

10 unchanged sentences

As of December 31, 2023, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability.

Some of these asset allocation target mixes vary with the plan’s funded status.

The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2023:

5 unchanged sentences

Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts.

Equity securities held directly by the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

plans are valued using quoted active market prices from the published exchange on which the equity security trades and are classified as Level 1.

Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades and are classified as Level 1.

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.

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.

20 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) — — 65,740 65,740

1 unchanged sentence

Other Benefits:

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

Fixed income securities:

54 unchanged sentences

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.

We made contributions to our pension plan totaling $ 0 million in 2022, $ 100 million in 2021, and $ 100 million in 2020.

In 2023 and 2022, 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.

With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2023 or 2022 and do not expect to make any contributions in 2024, 2025 or 2026.

The Company was reimbursed

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$ 26 million in 2022, $ 24 million in 2021, and $ 26 million in 2020 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

The Company was reimbursed $ 23 million in 2023, $ 26 million in 2022, and $ 24 million in 2021 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

Estimated Future Benefit Payments

15 unchanged sentences

We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates.

APS also has certain purchased power agreements that qualify as lease arrangements.

APS also has certain purchased power and energy storage agreements that qualify as lease arrangements.

Our leases have remaining terms that expire in 2024 through 2073.

9 unchanged sentences

non-consecutive periods of use.

APS does not operate or maintain these leased assets.

APS controls the dispatch of these leased assets and is required to pay fixed monthly capacity payments during the 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.

These purchased power lease contracts are accounted for as operating leases.

The contracts do not contain purchase options or term extension options.

In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset.

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.

For this class of energy storage lease assets, APS has elected to separate the lease and non-lease components.

The following table provides information related to our lease costs (dollars in thousands):

For the Year Ended

Year Ended December 31,

2023 2022 2021

Operating Lease Cost - Purchased Power Lease Contracts $ 104,001 $ 105,762 68,883

Operating Lease Cost - Purchased Power & Energy Storage Lease Contracts $ 126,655 $ 104,001 $ 105,762

Operating Lease Cost - Land, Property, and Other Equipment 19,235 18,061 18,498

5 unchanged sentences

Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income.

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

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

The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES.

Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts.

Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the generation source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets.

Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets.

Certain of our lease agreements have lease terms with non-consecutive periods of use.

4 unchanged sentences

December 31, 2023

Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total

Year Purchased Power & Energy Storage Lease Contracts Land, Property & Equipment Leases Total

2024 $ 108,201 $ 14,750 $ 122,951

9 unchanged sentences

At December 31, 2023, we have various lease arrangements that have been executed, but have not yet commenced.

We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $ 7.1 billion over the terms of the agreements.

These arrangements primarily relate to energy storage assets.

1 unchanged sentence

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

We expected lease commencement dates ranging from June 2023 through June 2025, with lease terms expiring through May 2045.

We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $ 2.7 billion over the 20-year terms of the agreements.

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

These lease agreements previously commenced in 2020 and 2021.

In January 2023, as a result of these modifications, APS recorded an additional $ 537 million of operating lease liabilities and right-of-use operating lease assets.

These obligations relate to payments that will occur during the periods 2023 through 2034.

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.

Proceeds received from lessors relating to energy storage PPA leases are accounted for as lease incentives on our Consolidated Balance Sheets, and upon lease commencement are amortized over the associated lease term.

For regulatory purposes, the proceeds received by APS relating to these PPA leases are treated as a reduction to fuel and purchased power costs through the PSA in the period proceeds are received.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide other additional information related to operating lease liabilities (dollars in thousands):

Year Ended December 31, 2022 Year Ended December 31, 2021 Year Ended December 31, 2020

Year Ended December 31,

2023 2022 2021

Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:

$ 123,472 $ 118,463 $ 116,661

Right-of-use operating lease assets obtained in exchange for operating lease liabilities 16,990 500,582 441,653

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

December 31, 2023 December 31, 2022

Weighted average remaining lease term 10 years 7 years

Weighted average discount rate (a) 2.21 % 2.13 %

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

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.

For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities.

42 unchanged sentences

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against DOE in the United States Court of Federal Claims (“Court of Federal Claims”).

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE in the United States Court of Federal Claims (“Court of Federal Claims”).

The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.

1 unchanged sentence

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.

An additional extension is currently pending.

APS has submitted eight claims pursuant to the terms of the August 18, 2014 settlement agreement, for eight separate time periods during July 1, 2011 through June 30, 2021.

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).

1 unchanged sentence

In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers.

On October 31, 2022, APS filed its ninth claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $ 14.3 million (APS’s share is $ 4.2 million).

In February 2023, the DOE approved this claim.

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.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.

In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $ 13.7 billion per occurrence.

This insurance limit is subject to an adjustment every five years based upon the aggregate percentage change in the Consumer Price Index.

The most recent adjustment took effect on January 1, 2024.

As of that date, in accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $ 16.3 billion per occurrence.

Palo Verde maintains the maximum available nuclear liability insurance in the amount of $ 500 million, which is provided by American Nuclear Insurers.

3 unchanged sentences

Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $ 144.9 million, with a maximum annual retrospective premium of approximately $ 21.6 million.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $ 2.8 billion.

APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units.

The property damage,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”).

The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”).

APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumul ated funds.

15 unchanged sentences

The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):

Years Ended December 31,

Year Ended December 31,

2024 2025 2026 2027 2028 Thereafter

4 unchanged sentences

The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):

Years Ended December 31,

Year Ended December 31,

2023 2022 2021

26 unchanged sentences

The annual payments to the escrow account and final distribution to certain coal providers may be subject to adjustments based on escrow earnings.

Superfund-Related Matters

Superfund and Other Related Matters

The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.

Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (“PRPs”).

Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”).

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

7 unchanged sentences

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.

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.

The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.

The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.

As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the

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

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.

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.

On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation.

That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation but excluded APS and certain other parties as named defendants.

Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery.

APS’s share of this settlement was immaterial.

In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice.

An order to this effect was entered on April 17, 2018.

With this disposition of the case, the vendors may file their lawsuit again in the future.

On August 16, 2019, Maricopa County, one of the three direct defendants in the ancillary service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants.

While this lawsuit remains pending, on September 30, 2022, the U.S.

District Court for the District of Arizona granted partial summary judgment to the direct defendants for $ 20.7 million of the $ 21 million in CERCLA response costs claimed by the service provider.

We are unable to predict the outcome of any further litigation related to the remaining response costs at issue in this litigation;

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

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

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.

3 unchanged sentences

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.

At the present time, we are unable to predict the outcome of this matter and expenditures related to this matter cannot be reasonably estimated.

Arizona Attorney General Matter

APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement.

APS fully cooperated with the Attorney General’s Office in this matter.

On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter.

The settlement resulted in APS paying $ 24.75 million, approximately $ 24 million of which was returned to customers as restitution.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

4 unchanged sentences

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

The Court took the matter under advisement and will issue its decision in due course.

We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved.

See Note 3 for additional information regarding the Four Corners SCR cost recovery.

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 GHGs, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs.

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

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.

Associated capital expenditures or operating costs could be material.

APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery.

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

Regional Haze Rules.

APS has received the final rulemaking imposing pollution control requirements on Four Corners.

EPA required the plant to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plant.

Based on EPA’s final standards, APS’s 63 % share of the cost of required controls for Four Corners Units 4 and 5 was approximately $ 400 million, which has been incurred.

In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7 % interest in Four Corners Units 4 and 5.

4CA purchased the El Paso interest on July 6, 2016.

NTEC purchased the interest from 4CA on July 3, 2018.

The cost of the pollution controls related to the 7 % interest is approximately $ 45 million, which was assumed by NTEC through its purchase of the 7 % interest.

In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility.

See “Cholla” in Note 3 for information regarding future plans for Cholla and details related to the resulting regulatory asset.

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

Coal Combustion Waste .

On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash.

The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions.

The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions.

These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements.

The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of recent regulatory and judicial activities described below.

Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of the regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal.

2 unchanged sentences

• 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, including supporting the passage of new state legislation 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.

On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.

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.

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.

The proposal remains pending.

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

This application

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.

We cannot at this time predict the outcome of these regulatory proceedings or when the 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 APS’s financial position, results of operations, or cash flows.

• 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 currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners.

APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

approximately $ 30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $ 16 million.

The Navajo Plant disposed of CCR only in a dry landfill storage area.

To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $ 1 million, which has been incurred.

Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

5 unchanged sentences

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

Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $ 10 million to $ 15 million, which would be incurred over 30 years.

The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time.

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 process, APS cannot predict any ultimate impacts to the Company;

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

Clean Power Plan/Affordable Clean Energy Regulations .

On June 19, 2019, EPA took final action on its proposals to repeal EPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations.

EPA originally finalized the CPP on August 3, 2015, and such rules would have had far broader impact on the electric power sector than the ACE regulations.

On January 19, 2021, the U.S.

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.

EPA Power Plant Carbon Regulations.

EPA’s regulation of carbon dioxide emissions from electric utility power plants has proceeded in fits and starts over most of the last decade.

Starting on August 3, 2015, EPA finalized the Clean Power Plan, which was the Agency’s first effort at such regulation through system-wide generation dispatch shifting.

Those regulations were subsequently repealed by the EPA on June 19, 2019, and replaced by the Affordable Clean Energy (“ACE”) regulations, which were a far narrower set of rules.

While the U.S.

Court of Appeals for the D.C.

Circuit vacated the ACE regulations and remanded them back to EPA to develop new existing power plant carbon regulations consistent with the court’s ruling.

That decision, which endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP, was subsequently reversed by the U.S.

Supreme Court on June 30, 2022.

While the current administration has expressed its intent to develop new carbon emission regulations governing existing power plants sometime in 2023, such action will be constrained by the U.S.

Supreme Court’s decision that the CPP violated the Clean Air Act.

Nonetheless, we cannot at this time predict the outcome of pending EPA rulemaking proceedings related to carbon emissions from existing power plants.

Circuit subsequently vacated the ACE regulations on January 19, 2021, and ordered a remand for EPA to develop replacement regulations consistent with the original 2015 Clean Power Plan, the U.S.

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.

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.

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.

The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our fossil-fuel powered plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.

The financial impact of complying with current and future environmental rules could jeopardize the economic viability of APS’s fossil-fuel powered plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.

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.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit

1 unchanged sentence

Based upon a November 1, 2019, filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit.

EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019.

Based upon a November 1, 2019, filing by several environmental groups, the EAB again took up review of the Four Corners NPDES Permit.

Oral argument on this appeal was held on September 3, 2020, and the EAB denied the environmental group petition on September 30, 2020.

The EAB denied the environmental group petition on September 30, 2020.

While on January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S.

Court of Appeals for the Ninth Circuit, the parties to this 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 is not expected to have a material impact on APS’s financial position, results of operations, or cash flows.

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’s 7 % interest in Four Corners.

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.

2 unchanged sentences

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

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 and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022.

Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order.

On October 7, 2022, the request for rehearing was denied by FERC.

FERC has not ruled on the motion for stay.

Clear Creek has filed a Petition for Review with the U.S.

Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending.

Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner.

The May 25, 2022 Complaint was denied by FERC on December 15, 2022 and Tenaska Clear Creek Wind, LLC requested Rehearing of the denial on January 13, 2023.

Due to the disputed system upgrades and the related curtailment, 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.

These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC.

As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired.

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

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, 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.

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.

See Note 20 for information relating to the BCE Sale.

Financial Assurances

16 unchanged sentences

however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with BCE’s acquisition of minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”).

In connection with PNW Power’s investments in minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has guaranteed the obligations of PNW Power to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”).

The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements.

As of December 31, 2022 there is approximately $ 34 million of remaining guarantees primarily relating to the PTC Guarantees that is expected to terminate by 2030.

As of December 31, 2023, there is approximately $ 31 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2030.

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.

The details of the guarantees are as follows:

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In connection with the credit agreement entered into by a special purpose subsidiary of BCE on Februa ry 11, 2022, Pinnacle West has issued a guarantee of up to $ 42 million primarily related to the bridge loan.

See Note 6 for additional details.

• 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).

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:

• 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.

• 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.

In 2021, APS revised its cost estimates for existing AROs at Cholla related to updated estimates for the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $ 28 million.

See additional details in Notes 3 and 10.

5 unchanged sentences

Estimated cash flow revisions 135,323 —

Newly incurred obligation 2,686 —

Asset retirement obligations at the end of year $ 966,001 $ 797,762

1 unchanged sentence

See detail of regulatory liabilities in Note 3.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements

9 unchanged sentences

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Thus, a valuation may be classified in Level 3 even though the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

valuation may include significant inputs that are readily observable.

Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.

We maximize the use of observable inputs and minimize the use of unobservable inputs.

12 unchanged sentences

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

7 unchanged sentences

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions.

Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.

Long-dated energy transactions may consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.

We rely primarily on broker quotes to value these instruments.

1 unchanged sentence

These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.

When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

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 relate to an interest rate swap, which is valued using financial models that utilize observable inputs for similar instruments and are classified as Level 2.

Inputs include yield curves and credit quality of the counterparties.

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

6 unchanged sentences

These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fixed Income Securities

12 unchanged sentences

The commingled funds are valued using the funds’ NAV as a practical expedient.

The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

held by the funds.

The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds.

We may transact in these commingled funds on a semi-monthly basis at the NAV.

7 unchanged sentences

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):

Level 1 Level 2 Level 3 Other Total

Balance at December 31, 2023 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:

15 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.

3 unchanged sentences

The following table presents the fair value at December 31, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1 Level 2 Level 3 Other Total

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

Risk management activities — derivative instruments:

Commodity contracts $ — $ 127,129 $ 26,132 $ ( 21,163 ) (a) $ 132,098

Interest rate swaps — 131 — — 131

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

Nuclear decommissioning trust:

15 unchanged sentences

Commodity contracts $ — $ ( 25,874 ) $ ( 31,020 ) $ 15,357 (a) $ ( 41,537 )

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.

14 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 )

3 unchanged sentences

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2022 and 2021 (dollars in thousands):

Year Ended December 31,

Commodity Contracts 2023 2022

11 unchanged sentences

See Note 6 for our long-term debt fair values.

Nonrecurring Fair Value Measurements

As of December 31, 2022, the fair value of BCE’s impaired equity method investment that is measured at fair value on a nonrecurring basis was zero, which was valued using significant unobservable inputs (Level 3).

The total tax effected impairment charge included in net income for the year ended December 31, 2022 was $ 12.8 million.

See Note 10 for additional information.

Earnings Per Share

9 unchanged sentences

Net income attributable to common shareholders — diluted $ 4.41 $ 4.26 $ 5.47

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation

1 unchanged sentence

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 authorizes up to 1.3 million common shares to be available for grant.

The 2021 Plan

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

As of December 31, 2023, 3.5 million common shares were available for issuance under the 2021 Plan.

32 unchanged sentences

(a) Includes 34,367 of awards that will be cash settled.

(b) The nonvested performance shares are reflected at target payout level.

(b) The performance shares are reflected at target payout level.

21 unchanged sentences

They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant.

The members of the Board of Directors who elect to defer may elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

The stock units include a dividend equivalent feature that accrues dividend rights from the date of grant to the date of payment, plus interest compounded quarterly.

Beginning in 2023, payments for stock units are issued in stock and include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date.

Prior to 2023, members of the Board of Directors who elected to defer could elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

The stock units prior to 2023 included a dividend equivalent feature that accrues dividend rights from the date of grant to the date of payment, plus interest compounded quarterly.

Performance Share Awards

17 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 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

compensation cost is recognized relating to the EPS, Clean and Metric component, and any previously recognized compensation cost is reversed.

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 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.

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

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.

See Note 12 for a discussion of fair value measurements.

11 unchanged sentences

Gains and Losses from Energy Derivative Instruments

The following table provides information about APS’s gains and losses from energy derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):

Financial Statement Year Ended

Commodity Contracts Location 2022 2021 2020

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $ — $ — $ ( 763 )

(a) During the years ended December 31, 2022, 2021, and 2020, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that no amounts will be reclassified from accumulated OCI into income.

For APS, the delivery period for all energy derivative instruments in designated cash flow accounting hedging relationships have lapsed.

For the years ended December 31, 2023, 2022 and 2021, APS had no energy derivative instruments in designated accounting hedging relationships.

The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):

26 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.

19 unchanged sentences

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 Los Alamitos credit agreement.

The transaction qualifies and has been designated as cash flow hedge.

The hedge’s gain or loss is reported as a component of other comprehensive income and subsequently will be reclassified into earnings in the periods during which the related interest expense on the debt is incurred.

As of December 31, 2022, the interest rate swap has a notional value of $ 32 million with a maturity in 2041.

Relating to this derivative, our Consolidated Balance Sheet as of December 31, 2022 includes approximately $ 0.9 million reported within the liabilities from risk management activities line within the deferred credits and other section, and $ 0.1 million reported within the current assets from risk management activities line.

For the year ended December 31, 2022, the Consolidated Income Statement includes a pretax loss of approximately $ 0.8 million recognized in other comprehensive income relating to the interest rate swap.

There were no gains or losses reclassified out of accumulated other comprehensive income for the year ended December 31, 2022, and we expect no significant amounts will be reclassified into earnings over the next 12 months.

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, 2022, we have two counterparties for which our exposure represents approximately 21 % of Pinnacle West’s $ 132 million of risk management assets.

This exposure relates to master agreements with the counterparties and both are rated as investment grade.

As of December 31, 2023, we have no counterparties with positive exposures of greater than 10% of Pinnacle West’s risk management assets.

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):

4 unchanged sentences

(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.

3 unchanged sentences

Other income:

Interest income $ 7,326 $ 6,726 $ 12,210

Investment gains (losses) — net — — 2,358

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

Gain on Sale of BCE (Note 20)

Debt return on Four Corners SCR deferral (Note 3)

— 14,955 15,865

Debt return on Ocotillo modernization project (Note 3)

— 23,366 26,121

Miscellaneous 219 590 53

3 unchanged sentences

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

Miscellaneous ( 13,229 ) (a) ( 11,021 ) ( 45,376 ) (a)

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

Total other expense $ ( 25,056 ) $ ( 52,385 ) $ ( 25,396 )

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

The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

(b) The 2022 investment loss is primarily related to an impairment write-off of BCE’s Clear Creek wind farm investment.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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

2 unchanged sentences

Other income:

Interest income $ 5,332 $ 4,692 $ 9,621

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

Debt return on Four Corners SCR deferral (Note 3)

— 14,955 15,865

Debt return on Ocotillo modernization project (Note 3)

— 23,366 26,121

Miscellaneous 219 556 40

2 unchanged sentences

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

Miscellaneous ( 10,529 ) (a) ( 8,817 ) ( 43,035 ) (a)

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

Total other expense $ ( 18,264 ) $ ( 26,108 ) $ ( 18,897 )

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

The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

(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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Palo Verde Sale Leaseback Variable Interest Entities

5 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 2022, $ 17 million for 2021 and $ 19 million for 2020.

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.

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

11 unchanged sentences

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

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

We record both debt and equity security

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

8 unchanged sentences

Earnings and proceeds from sales of securities are reinvested in the escrow account.

Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

regulatory liabilities.

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

1 unchanged sentence

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

In 2022 and 2021, APS was reimbursed $ 15 million for each year, for prior year active union employee medical claims from the active union employee medical account.

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.

The account is invested primarily in fixed income securities.

1 unchanged sentence

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):

47 unchanged sentences

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

Amounts reclassified from accumulated other comprehensive loss 4,401 (a) 18 (b) 4,419

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

Balance at December 31, 2022 ( 32,332 ) 897 ( 31,435 )

3 unchanged sentences

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.

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 Derivative Instruments Total

Pension and Other Postretirement Benefits Total

Balance at December 31, 2021 $ ( 34,880 ) $ ( 34,880 )

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

Amounts reclassified from accumulated other comprehensive loss 3,995 (a) 18 (b) 4,013

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

Balance at December 31, 2022 ( 15,596 ) ( 15,596 )

3 unchanged sentences

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Sale of Bright Canyon Energy

On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary, BCE, to Ameresco.

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.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Standards

ASU 2023-07, Segment Reporting:

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.

ASU 2023-09, Income Taxes:

Improvements to Income Tax Disclosures

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

The 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.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

6 unchanged sentences

Equity in earnings of subsidiaries 539,962 500,042 628,916

Other expense ( 4,725 ) ( 4,919 ) ( 4,586 )

Other income (expense) 2,823 ( 4,725 ) ( 4,919 )

Total 542,785 495,317 623,997

14 unchanged sentences

Income tax receivable 1,832 14,494

Assets held for sale- investment in subsidiaries 35,139 —

Other current assets 28,379 288

16 unchanged sentences

Total current liabilities 825,709 142,562

Long-term debt less current maturities (Note 6)

947,892 647,139

Long-term debt less current maturities 498,731 947,892

Pension liabilities 6,487 8,218

2 unchanged sentences

Total deferred credits and other 27,630 26,976

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

COMMITMENTS AND CONTINGENCIES

Common stock equity

17 unchanged sentences

Equity in earnings of subsidiaries — net ( 539,962 ) ( 500,042 ) ( 628,916 )

Gain on sale relating to BCE ( 6,423 ) — —

Depreciation and amortization 76 76 93

7 unchanged sentences

Cash flows from investing activities

Proceeds from sale relating to BCE 23,400 — —

Investments in subsidiaries ( 119,682 ) ( 186,630 ) ( 145,266 )

Repayments of loans from subsidiaries 14,308 4,017 932

Repayments of loans from subsidiaries and other 6,526 14,308 4,017

Advances of loans to subsidiaries ( 59,349 ) ( 3,308 ) ( 12,256 )

2 unchanged sentences

Issuance of long-term debt 175,000 300,000 300,000

Short-term debt borrowings under revolving credit facility — — 211,690

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

4 unchanged sentences

Net cash flow used for financing activities ( 154,649 ) ( 229,114 ) ( 227,528 )

Net decrease in cash and cash equivalents ( 594 ) 575 —

Net increase (decrease) in cash and cash equivalents 9 ( 594 ) 575

Cash and cash equivalents at beginning of year — 594 19

9 unchanged sentences

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

What changed 10-K

Item 8. Financial Statements and Supplementary Data