What changed in this filing

/stocks — the workspaceLOADING

Item 8. Financial Statements and Supplementary Data

2022-02-25 compared with 2021-02-24 · 613 added, 624 removed, 2383 unchanged (34% of the section changed)

3 unchanged sentences

Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)

Report of Independent Registered Public Accounting Firm

Report of Independent Registered Public Accounting Firm (PCAOB ID No.

Pinnacle West Consolidated Statements of Income for 2021, 2020 and 2019

4 unchanged sentences

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)

Report of Independent Registered Public Accounting Firm

Report of Independent Registered Public Accounting Firm (PCAOB ID No.

APS Consolidated Statements of Income for 2021, 2020 and 2019

34 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, 2020 and 2019, 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, 2020, the related notes and the schedules 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, 2021 and 2020, 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, 2021, 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, 2021, 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.

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

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 and recent rate orders to other regulated entities in the same jurisdiction.

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

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, 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 and legal bodies, 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 the uncertainty of future decisions by the ACC included the following, among others:

Our audit procedures related to regulatory accounting 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;

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.

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.

• 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 management’s preliminary rate filings submitted and testimony given to the ACC regarding the 2019 Retail Rate Case filed in October 2019, and monitored activity by intervenors, the ACC and its staff and other testimony, as well as the Company’s rebuttal.

The filing is still under review with the ACC.

We read the filing and related testimony to assess the likelihood of recovery in future rates or of a future reduction in rates based on the information available as of our report date.

◦ We observed the ACC open meetings for the APS 2019 Retail Rate Case.

We read the ACC approved decision regarding the 2019 Retail Rate Case.

◦ We obtained the Company’s internally prepared memo regarding impacts of the ACC decision to rates and recorded balances.

◦ We tested that new rates were implemented within the system effective December 1, 2021.

• 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.

1 unchanged sentence

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, 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.

/s/ Deloitte & Touche LLP

53 unchanged sentences

Derivative instruments:

Net unrealized loss, net of tax benefit (expense) of $ 662 , $ 0 , and $( 78 )

( 2,089 ) — ( 78 )

Reclassification of net realized gain, net of tax expense of $ 171 , $ 375 , and $ 473 (Note 16)

Net unrealized gain (loss), net of tax benefit (expense) of $( 378 ), $ 662 , and $ 0

1,077 ( 2,089 ) —

Reclassification of net realized gain, net of tax benefit (expense) of $ 18 , $( 171 ), and $( 375 ) (Note 16)

Pension and other postretirement benefits activity, net of tax benefit (expense) of $( 2,256 ), $ 1,371 , and $ 3,452 (Note 8)

12 unchanged sentences

Accrued unbilled revenues 133,980 132,197

Allowance for doubtful accounts ( 19,782 ) ( 8,171 )

Allowance for doubtful accounts (Note 2)

( 25,354 ) ( 19,782 )

Materials and supplies (at average cost) 349,135 314,745

13 unchanged sentences

358,410 254,509

Assets from risk management activities (Note 16)

Other assets 97,884 91,104

38 unchanged sentences

Liabilities for asset retirements (Note 12)

15,586 11,025

Operating lease liabilities (Note 9)

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Liabilities from risk management activities (Note 16)

11,062 33,186

Customer advances 257,151 221,032

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Change in other long-term liabilities ( 29,578 ) ( 186,227 ) ( 132,666 )

Net cash flow provided by operating activities 966,365 956,726 1,277,144

Net cash provided by operating activities 860,014 966,365 956,726

CASH FLOWS FROM INVESTING ACTIVITIES

5 unchanged sentences

Other 6,458 7,883 11,452

Net cash flow used for investing activities ( 1,277,818 ) ( 1,130,977 ) ( 1,192,824 )

Net cash used for investing activities ( 1,386,929 ) ( 1,277,818 ) ( 1,130,977 )

CASH FLOWS FROM FINANCING ACTIVITIES

7 unchanged sentences

Distributions to noncontrolling interests ( 21,255 ) ( 22,743 ) ( 22,744 )

Net cash flow provided by (used for) financing activities 361,138 178,768 ( 92,446 )

Net cash provided by financing activities 476,916 361,138 178,768

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ( 49,999 ) 49,685 4,517

9 unchanged sentences

Net income — — 538,320 — 19,493 557,813

Other comprehensive income — — — 5,846 — 5,846

Other comprehensive loss — — — ( 9,388 ) — ( 9,388 )

Dividends on common stock ($ 3.04 per share)

4 unchanged sentences

Capital activities by noncontrolling interests — — — — ( 22,743 ) ( 22,743 )

Reclassification of income tax effects related to new tax reform (b) — — 8,552 ( 8,552 ) — —

Balance, December 31, 2019 112,540,126 2,659,561 ( 103,546 ) ( 9,427 ) 2,837,610 ( 57,096 ) 122,540 5,553,188

9 unchanged sentences

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

Other comprehensive loss — — — ( 5,700 ) — ( 5,700 )

Other comprehensive income — — — 7,935 — 7,935

Dividends on common stock ($ 3.36 per share)

4 unchanged sentences

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

Other — — 1 — 1 2

Balance, December 31, 2021 113,014,528 $ 2,702,743 ( 87,608 ) $ ( 6,401 ) $ 3,264,719 $ ( 54,861 ) $ 115,260 $ 6,021,460

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

(b) In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) on items within accumulated other comprehensive income to retained earnings .

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

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Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiaries (the “Company”) as of December 31, 2020 and 2019, 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, 2020, 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 Arizona Public Service Company and subsidiaries (the “Company”) as of December 31, 2021 and 2020, 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, 2021, and the related notes (collectively referred to as the “financial statements”).

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.

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

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 the uncertainty of future decisions by the ACC included the following, among others:

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

1 unchanged sentence

regulatory assets or liabilities;

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.

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.

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

• We 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 interveners, 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 APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, 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.

The filing is still under review with the ACC.

We read the filing and related testimony to assess the likelihood of recovery in future rates or of a future reduction in rates based on the information available as of our report date.

◦ We observed the ACC open meetings for the APS 2019 Retail Rate Case.

We read the ACC approved decision regarding the 2019 Retail Rate Case.

◦ We obtained the Company’s internally prepared memo regarding impacts of the ACC decision to rates and recorded balances.

◦ We tested that new rates were implemented within the system effective December 1, 2021.

1 unchanged sentence

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, 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.

/s/ Deloitte & Touche LLP

48 unchanged sentences

Derivative instruments:

Net unrealized loss, net of tax benefit (expense) of $( 18 ), $ 0 , and $( 78 )

( 18 ) — ( 78 )

Reclassification of net realized gain, net of tax expense of $ 171 , $ 375 , and $ 473 (Note 16)

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

( 18 ) ( 18 ) —

Reclassification of net realized gain, net of tax benefit (expense) of $ 18 , $( 171 ), and $( 375 ) (Note 16)

Pension and other postretirement benefits activity, net of tax benefit (expense) of $( 1,990 ), $ 1,955 , and $ 3,136 (Note 8)

25 unchanged sentences

358,410 254,509

Assets from risk management activities (Note 16)

Other assets 42,440 44,192

4 unchanged sentences

Accrued unbilled revenues 133,980 132,197

Allowance for doubtful accounts ( 19,782 ) ( 8,171 )

Allowance for doubtful accounts (Note 2)

( 25,354 ) ( 19,782 )

Materials and supplies (at average cost) 349,135 314,745

37 unchanged sentences

CURRENT LIABILITIES

Current maturities of long-term debt (Note 7)

Short-term borrowings (Note 6)

Accounts payable 389,365 311,699

5 unchanged sentences

Liabilities for asset retirements (Note 12)

15,586 11,025

Operating lease liabilities (Note 9)

14 unchanged sentences

Liabilities from risk management activities (Note 16)

11,062 33,186

Customer advances 257,151 221,032

39 unchanged sentences

Change in other long-term liabilities ( 20,272 ) ( 186,871 ) ( 129,682 )

Net cash flow provided by operating activities 929,067 1,007,411 1,254,801

Net cash provided by operating activities 865,554 929,067 1,007,411

CASH FLOWS FROM INVESTING ACTIVITIES

5 unchanged sentences

Other 273 ( 554 ) 6,336

Net cash flow used for investing activities ( 1,286,255 ) ( 1,136,093 ) ( 1,187,446 )

Net cash used for investing activities ( 1,391,434 ) ( 1,286,255 ) ( 1,136,093 )

CASH FLOWS FROM FINANCING ACTIVITIES

1 unchanged sentence

Repayment of long-term debt — ( 465,150 ) ( 600,000 )

Short-term borrowings and (repayments) — net 278,700 — —

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

3 unchanged sentences

Noncontrolling interests ( 21,255 ) ( 22,743 ) ( 22,744 )

Net cash flow provided by (used for) financing activities 404,329 133,144 ( 75,499 )

Net cash provided by financing activities 477,944 404,329 133,144

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ( 47,936 ) 47,141 4,462

8 unchanged sentences

Balance, December 31, 2018 71,264,947 $ 178,162 $ 2,721,696 $ 2,788,256 $ ( 27,107 ) $ 125,790 $ 5,786,797

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

Net income — — 565,271 — 19,493 584,764

Other comprehensive income — — — 4,914 — 4,914

Other comprehensive loss — — — ( 8,415 ) — ( 8,415 )

Dividends on common stock — — ( 341,600 ) — — ( 341,600 )

Reclassifications of income tax effects related to new tax reform (a) — — 5,038 ( 5,038 ) — —

Capital activities by noncontrolling interests — — — — ( 22,743 ) ( 22,743 )

Balance, December 31, 2019 71,264,947 178,162 2,721,696 3,011,927 ( 35,522 ) 122,540 5,998,803

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

Net income — — 568,028 — 19,493 587,521

5 unchanged sentences

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

Other comprehensive loss — — — ( 5,396 ) — ( 5,396 )

Other comprehensive income — — — 6,038 — 6,038

Dividends on common stock — — ( 379,000 ) — — ( 379,000 )

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

Other — — 1 — 1 2

Balance, December 31, 2021 71,264,947 $ 178,162 $ 3,021,696 $ 3,470,235 $ ( 34,880 ) $ 115,260 $ 6,750,473

(a) In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.

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

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

We consolidate VIEs for which we are the primary beneficiary.

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

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

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See Note 18 for additional information.

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

As of December 31, 2021, the captive cell's activities are insignificant to our consolidated financial statements.

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

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Regulatory Accounting

APS is regulated by the ACC and FERC.

APS is regulated by the ACC and the FERC.

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

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

(See Note 2.)

Property, Plant and Equipment

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• construction overhead costs (where applicable);

• allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, 2021, and 2020 Consolidated Balance Sheets is composed of the following (dollars in thousands):

20 unchanged sentences

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 asset retirement obligations.

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.

APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.

1 unchanged sentence

The approximate remaining average useful lives of our utility property at December 31, 2021, were as follows:

• Fossil plant — 17 years;

• Steam generation — 12 years;

• Nuclear plant — 25 years;

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Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation assets.

The Palo Verde asset retirement obligation primarily relates to final plant decommissioning.

APS has AROs for its Palo Verde nuclear facilities and certain other generation assets.

The Palo Verde ARO primarily relates to final plant decommissioning.

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

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

Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal.

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

Some of APS’s transmission and distribution assets have AROs because they are subject to right of way and easement agreements that require final removal.

These agreements have a history of uninterrupted renewal that APS expects to continue.

As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets.

As a result, APS cannot reasonably estimate the fair value of the ARO related to such transmission and distribution assets.

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AFUDC was calculated by using a composite rate of 6.75 % for 2021, 6.72 % for 2020, and 6.98 % for 2019.

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

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021.

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.

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

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

The order provides 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 has 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 has left all other aspects of the AFUDC formula composite rate calculation unchanged.

This change impacts the AFUDC composite rate in 2020 but does not impact prior years.

This change impacts the AFUDC composite rate in 2020 and 2021 but does not impact prior years.

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1 unchanged sentence

See Note 13 for additional information about fair value measurements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Accounting

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See Note 8 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.

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

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

17 unchanged sentences

Dividends declared but not paid 95,988 93,531 87,982

Sale of 4CA 7 % interest in Four Corners

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 96,000 93,500 88,000

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).

Bright Canyon holds investments in equity securities.

BCE 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).

5 unchanged sentences

If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date.

Lease liabilities are recognized based on the present value

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of the fixed lease payments over the lease term.

Lease liabilities are recognized based on the present value of the fixed lease payments over the lease term.

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.

5 unchanged sentences

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.

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 (see Note 4 ).

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.

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

4 unchanged sentences

Preferred Stock

At December 31, 2020, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $ 25 , $ 50 and $ 100 par values, none of which was outstanding.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2021, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, no ne of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $ 25 , $ 50 , and $ 100 par values, no ne of which was outstanding.

Sources of Revenue

10 unchanged sentences

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

(See Note 11).

Retail Electric Revenue.

Pinnacle West’s retail electric revenue is generated by our 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.

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.

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, 2020, 2019 and 2018 were $ 3,533 million, $ 3,415 million and $ 3,644 million, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our revenues from contracts with customers for the year ended December 31, 2021, 2020 and 2019 were $ 3,760 million, $ 3,533 million.

and $ 3,415 million, respectively.

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

10 unchanged sentences

The suspension of customer disconnections was extended from March 13, 2020, through December 31, 2020.

Our disconnection policies are also impacted by the Summer Disconnection Moratorium.

The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and certain customers with past due balances were placed on eight-month payment arrangements.

These circumstances and the on-going COVID-19 pandemic have impacted our allowance for doubtful accounts including our write-off factor.

We continue to monitor the impacts of COVID-19, our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts.

During this time, our disconnection policies were also impacted by the Summer Disconnection Moratorium.

These circumstances and the on-going COVID-19 pandemic continue to impact our allowance for doubtful accounts including our write-off factor.

We continue to monitor the impacts of COVID-19, our disconnection policies, summer moratorium, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts.

See Note 1 for our accounting policies on allowance for doubtful accounts.

See Note 4 for additional discussion on the COVID-19 pandemic and the Summer Disconnection Moratorium.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts all of which primarily relates to APS (dollars in thousands):

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Year Ended December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019

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Allowance for doubtful accounts, balance at end of period $ 25,354 $ 19,782 $ 8,171

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Standards

Standards Adopted in 2020

ASU 2016-13, Financial Instruments:

Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments.

The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables and other financial instruments.

Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes.

The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard.

We adopted the standard on January 1, 2020 using primarily the modified retrospective approach.

While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements.

(See Note 2 for allowance for doubtful accounts related credit loss disclosures.)

ASU 2018-14, Retirement Benefits:

Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, a new accounting standard was issued that amends certain disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans.

The amendments remove disclosures that are no longer considered beneficial, clarifies specific disclosure requirements and adds new disclosure requirements relating to defined benefit plans.

The new standard is effective for fiscal years ending after December 15, 2020.

We adopted and implemented the standard on a retrospective basis in our financial statements for the year ended December 31, 2020.

While the adoption of this guidance modified the disclosure requirements relating to defined benefit plans, these changes did not have a material impact on our financial statements.

(See Note 8 for Retirement Plans and Other Postretirement Benefits disclosure.)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2021-05, Leases:

Certain Leases with Variable Lease Payments

In July 2021, a new accounting standard was issued that amends the lease accounting guidance.

The amended guidance will require lessors to account for certain lease transactions, that contain variable lease payments, as operating leases.

The amendments are intended to eliminate the recognition of any day-one loss associated with certain sales-type and direct-financing lease transactions.

The changes do not impact lessee accounting.

The standard may be adopted using either a prospective or modified retrospective approach.

We adopted this standard on January 1, 2022, using a prospective approach.

The adoption of this standard did not impact our financial statements.

Regulatory Matters

COVID-19 Pandemic

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020.

In addition, APS waived all late payment fees during this suspension period.

On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020.

The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $ 75 or greater.

APS will continue to waive late payment fees until October 15, 2021.

APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic.

The Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $ 23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic.

Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 and also delayed the reset of the PSA to the first billing cycle of April 2021 rather than February 2021 (see below for discussion of EIS, TEAM Phase II and PSA).

During 2020 and 2021, APS implemented several programs and initiatives to help our customers deal with the economic and other impacts of the COVID-19 pandemic, including but not limited to the following:

• Suspension of Disconnections;

Waiver of Late Payment Fees .

APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020, until December 31, 2020.

The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and customers with past due balances of $ 75 or greater as of that date were automatically placed on eight-month payment arrangements.

APS voluntarily began waiving late payment fees of its customers on March 13, 2020 and is continuing to waive late payment fees.

APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium (defined below) and the related write-offs of customer delinquent accounts.

• COVID-19 Emergency Relief Package.

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.

As of December 31, 2020, APS had refunded approximately $ 43 million to customers.

The additional $ 7 million over the approved amount of $ 36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period.

This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings (see below for discussion of the DSM Adjustor Charge).

APS has spent more than $ 15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $ 12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”).

The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $ 8.8 million.

An additional $ 3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50 %, up to a maximum of $ 2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates.

Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $ 100 , an expanded credit of $ 300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $ 1,000 , and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance.

The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $ 250 or their delinquent balance, whichever was less.

As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fund programs combined.

Beyond the COVID Customer Support Fund, APS

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

has also provided $ 2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.

2019 Retail Rate Case Filing with the Arizona Corporation Commission

In accordance with the requirements of the 2019 rate review order described below, APS filed an application with the ACC on October 31, 2019 seeking an annual increase in retail base rates of $ 69 million.

This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction (“SCR”) project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below).

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.

• COVID Customer Support Fund .

In 2020, APS spent more than $ 15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $ 12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”).

The COVID Customer Support Fund was comprised of (i) approximately $ 8.8 million in funds that are not recoverable through rates, and (ii) an additional $ 3.6 million in bill credits for limited income customers ordered by the ACC in December 2020, of which 50 %, up to a maximum of $ 2.5 million, was committed to be funds that are not recoverable through rates, with the remaining bill credits being deferred for potential future recovery in rates.

Included in the COVID Customer Support Fund were programs that assisted customers with a delinquency of two or more months, providing a one-time credit of $ 100 , an expanded credit of $ 300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $ 1,000 , and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance.

The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $ 250 or their delinquent balance, whichever was less.

APS has distributed all funds for all COVID Customer Support Fund programs combined.

Beyond the COVID Customer Support Fund, APS has also provided $ 2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.

• Deferral of PSA Rate Increase .

In February 2021, APS delayed the annual reset of the PSA, with 50 % of the PSA rate increase taking effect in April 2021 and the remaining 50 % taking effect in November 2021.

See below for discussion of the PSA.

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 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 TEAM.

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The principal provisions of APS’s application were:

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

• 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:

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capital Structure Cost of Capital

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• 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 Plant (see “Navajo Plant” below).

APS requested that the increase become effective December 1, 2020.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The ACC Staff recommends, among other things, a (i) $ 89.7 million revenue increase, (ii) average annual customer bill increase of 2.7 %, (iii) 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) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project.

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

• continued recovery of the remaining investment and other costs related to the retirement and closure of 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) a $ 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, a (i) $ 169 million revenue increase, (ii) average annual 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.

On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $ 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, 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Power Plant 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 Generating Station, which would primarily be funded by customers.

(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.

The hearing began January 14, 2021.

Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact on APS’s financial statements if ultimately adopted by the ACC.

In 2021, APS committed an additional $ 900,000 to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in our December 31, 2021 financials.

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 information), (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.

These amounts would be recoverable from APS’s customers through the 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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:

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

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

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.

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.

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 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.

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

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.

On December 3, 2021, ACC Staff notified the ACC of a discrepancy between the written decision, which approved the change in time-of-use on-peak hours to 4 p.m.

to 7 p.m., but did not explicitly approve the 10 months contemplated in APS’s verbal testimony to implement the new time-of-use hours.

On December 16, 2021, the ACC ordered APS to complete the implementation of the time-of-use peak period by April 1, 2022.

On January 12, 2022, the ACC voted to extend the deadline until September 1, 2022, to complete the implementation of the new on-peak hours for residential customers.

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.

APS cannot predict the outcome of this matter.

APS expects to file an application with the ACC for its next general retail rate case by mid-year 2022 but is continuing to evaluate the timing of such filing.

Information Technology ACC Investigation

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

APS is cooperating with the investigation.

The ACC Staff has been directed to report to the ACC on the investigation in April 2022.

APS cannot predict the outcome of this matter.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2016 Retail Rate Case Filing with the Arizona Corporation Commission

2016 Retail Rate Case Filing

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, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the “2017 Settlement Agreement”) and filed it with the ACC.

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the 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 a net retail base rate increase of $ 94.6 million, excluding the transfer of adjustor balances, consisting of:

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

The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28 % (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54 %).

Other key provisions of the agreement include the following:

Other key provisions of the 2017 Settlement Agreement include the following:

• an authorized return on common equity of 10.0 %;

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• rate design changes, including:

▪ a change in the on-peak time of use period from noon-7 p.m.

to 3 p.m.-8 p.m.

▪ a change in the on-peak time-of-use period from noon to 7 p.m.

Monday through Friday, excluding holidays;

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• an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027, for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.

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”), which is subject to requests for rehearing and potential appeal.

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.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”).

The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.

The ACC held a hearing on this matter, and the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed.

On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review).

On July 10, 2019, the ACC adopted the Administrative Law Judge’s amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

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.

ACC Review of APS 2017 Rate Case Decision

On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision.

Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year.

The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision.

On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision.

On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments.

The key provisions of the amended order include the following:

• APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year;

• until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month;

• APS customers can switch rate plans during an open enrollment period of six months;

• APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans;

• APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates;

• APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant;

• APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

APS filed its rate case on October 31, 2019 (see “2019 Retail Rate Case Filing with the Arizona Corporation Commission” above for more information).

APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows.

On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision.

On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning.

The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable.

Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened.

On June 18, 2020, at an ACC Open Meeting, the matters raised in these letters were discussed.

The ACC did not vote to move forward with any adjustments to APS’s current rates.

APS is monitoring this matter, but believes that the proposals are not legal and further that APS has not over-earned.

The ACC voted to administratively close this docket on November 4, 2020.

Cost Recovery Mechanisms

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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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $ 89.9 million.

APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules.

On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.

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 residential distributed energy requirement for 2020 contained in the RES rules.

On September 23, 2020, the ACC approved the 2020 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2020 implementation year.

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 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.

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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 residential distributed energy requirement for 2021 contained in the RES rules.

In the 2021 RES Implementation Plan, APS requests $ 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.

The ACC has not yet ruled on the 2021 RES Implementation Plan.

On July 15, 2020, ACC Staff issued final draft rules which, if approved, would require APS to meet certain clean energy standards, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process.

APS cannot predict the outcome of this matter.

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

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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.

See “Energy Modernization Plan” below for more information.

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

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

This budget 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 permanent waiver of the RES residential and non-residential distributed energy requirements for 2022.

The ACC has not yet ruled on the 2022 RES Implementation Plan.

Demand Side Management Adjustor Charge .

The ACC EES requires APS to submit a Demand Side Management Implementation Plan (“DSM Plan”) annually for review by and approval of the ACC.

The ACC EES requires APS to submit a Demand Side Management Implementation Plan (“DSM Plan”) annually for review and approval by the ACC.

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

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 LFCR mechanism (see below for discussion of the LFCR).

On September 1, 2017, APS filed its 2018 DSM Plan, which proposed modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures.

See below for discussion of the LFCR.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposed modifications to the DSM portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures.

The 2018 DSM Plan sought a requested budget of $ 52.6 million and requested a waiver of the Electric Energy Efficiency Standard for 2018.

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On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $ 34.1 million and focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies.

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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.

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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.

As of December 31, 2020, APS had refunded approximately $ 43 million to customers.

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

This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings.

See “COVID-19 Pandemic” above for more information.

On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $ 63.7 million and continues 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.

The ACC has not yet ruled on the APS 2021 DSM Plan.

On May 5, 2020, the ACC approved APS returning $ 36 million that had been collected through the DSM Adjustor Charge, but not allocated for

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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 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 Plan that proposed an additional performance 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 Plan.

On April 20, 2021, APS filed a request to extend the June 1, 2021 deadline to file its 2022 DSM Plan until 120 days after the ACC has taken action on APS’s amended 2021 DSM Plan.

The ACC approved the request, granting an extension until 120 days after the ACC action on the 2021 DSM Plan, or December 31, 2021, whichever is later.

On December 17, 2021, APS filed its 2022 DSM Plan which requested a budget of $ 78.4 million and represents an increase of approximately $ 14 million in DSM spending above 2021.

Power Supply Adjustor Mechanism and Balance.

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On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020.

That rate was $( 0.000456 ) per kWh and consisted of a forward component of $( 0.002086 ) per kWh and a historical component of $ 0.001630 per kWh.

That rate was $( 0.000456 ) per kWh, which consisted of a forward component of $( 0.002086 ) per kWh and a historical component of $ 0.001630 per kWh.

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

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

That rate was $ 0.003544 per kWh and 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.

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.

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 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 PSA 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 PSA rate of $ 0.003544 per kWh, which 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, which is currently underway, to better understand the factors that contributed to the increase in fuel costs.

APS cannot predict the outcome of this audit.

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

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

The 2022 PSA rate 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.

At the time of the compliance filing, the amount remaining over the annual cap was approximately $ 365 million of fuel and purchased power costs which will be reflected in future year resets of the PSA.

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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.

On December 29, 2020, the ACC Staff filed its report and recommended the storage costs be included in the PSA once the systems are in-service.

On January 12, 2021, the ACC approved this application.

On January 12, 2021, the ACC approved this application but did not rule on the prudency.

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.

On December 16, 2021, the ACC approved this application but did not rule on the prudency.

APS cannot predict the outcome of this matter.

Environmental Improvement Surcharge (“EIS”).

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

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

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 $14 million per year).

APS’s February 1, 2021 application requested an increase in the charge to $ 10.3 million, or $ 1.5 million over the charge in effect for the 2020-2021 rate effective year.

APS’s February 1, 2022 application requested an increase in the charge to $ 11.4 million, or $ 1.1 million over the prior-period charge, and it will become effective with the first billing cycle in April 2022 absent the ACC taking action.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters .

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

In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain

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approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.

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

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

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

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

APS reviews the proposed formula rate filing amounts with the ACC Staff.

Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC.

Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated with FERC.

Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Act beginning in its 2018 annual transmission formula rate update filing.

These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes.

On March 17, 2020, APS made a filing to make further modifications to its annual transmission formula to provide additional transparency for excess and deficient Accumulated Deferred Income Taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes.

This filing is pending with FERC.

Effective June 1, 2018, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $ 22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC-approved formula.

Of this amount, retail customer rates decreased by approximately $ 26.9 million.

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 Act, as well as for future local, state, and federal 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.

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Effective June 1, 2019, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $ 25.8 million for the 12-month period beginning June 1, 2019, in accordance with the FERC-approved formula.

Of this amount, wholesale customer rates increased by $ 21.1 million and retail customer rates would have increased by approximately $ 4.7 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 TCA balancing account, the retail revenue requirement increased by a total of $ 4.9 million, resulting in a decrease to residential rates and an increase to commercial rates.

An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $ 25.8 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula.

Of this amount, retail customer rates increased by approximately $ 4.7 million.

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 rates.

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

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

Of this amount, retail customer rates decreased by approximately $ 10.9 million.

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

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

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $ 28.4 million, resulting in reductions to both residential and commercial rates.

An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2021.

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

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

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of retail revenues.

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 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.

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

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

On February 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $ 60.7 million.

On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019.

On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $ 36.2 million (a $ 24.5 million decrease from previous levels).

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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.

On April 14, 2020, the ACC approved the 2020

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LFCR adjustment as filed, effective with the first billing cycle in May 2020.

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

On April 13, 2021, the ACC voted not to approve the requested $ 11.8 million increase to the annual LFCR adjustment, thus the previously approved rates continue to remain intact.

The $ 11.8 million will continue to be maintained in the LFCR regulatory asset balancing account and will be included in APS’s next LFCR application filing in accordance with the compliance requirements.

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

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

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

On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $ 59.1 million (a $ 32.5 million increase from previous levels).

The ACC’s final determination of APS’s 2022 annual LFCR adjustment filing and related earnings test may materially impact the timing and amounts of future LFCR revenue recognition.

See Note 2 for a discussion of alternative revenue program accounting treatment related to certain regulatory cost recovery mechanisms and see the Regulatory Assets and Liabilities table below.

APS cannot predict the outcome or timing of the ACC’s consideration and final determination of its 2022 annual LFCR adjustment filing.

Tax Expense Adjustor Mechanism.

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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 January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $ 119.1 million annually through an equal cents per kWh credit (“TEAM Phase I”).

On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit.

The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM Phase I, over time, is expected to be earnings neutral.

However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate.

The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $ 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”).

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 will be recorded as a part of the balancing account and will be addressed for recovery as part of APS’s 2019 retail rate case.

Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be 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 are recognized based upon our seasonal kWh sales pattern.

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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 will provide 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 APS’s 2019 pending rate case.

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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.

Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit are 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 APS’s next rate case.

APS’s 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed.

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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.

A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.

This price reflected the 10 % annual reduction discussed above.

The new rate rider became effective on October 1, 2018.

APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019.

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

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

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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.

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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.

APS’s export energy price will remain at 10.5 cents per kWh until October 1, 2021.

On January 23, 2017, The Alliance for Solar Choice (“TASC”) sought rehearing of the ACC’s decision regarding the value and cost of DG.

TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects.

TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017.

As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

See “2016 Retail Rate Case Filing with the Arizona Corporation Commission” 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.

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

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

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS’s obligations to comply with the subpoenas and decline to decide APS’s motion pending court proceedings.

Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Burns’ subpoenas are contrary to law.

On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff.

As part of this docket, Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas.

Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena.

On March 10, 2017, Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas.

On March 30, 2017, APS filed a motion to dismiss Burns’ suit against APS and Pinnacle West.

In response to the motion to dismiss, the

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court stayed the suit and ordered Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC.

On June 20, 2017, the ACC denied the motion to compel.

On August 4, 2017, Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants.

All defendants moved to dismiss the amended complaint.

On February 15, 2018, the Superior Court dismissed Burns’ amended complaint.

On March 6, 2018, Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint.

The Superior Court permitted Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case.

Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed.

Oral argument occurred in November 2018 regarding the motion to dismiss.

On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019.

On February 13, 2019, Burns filed a notice of appeal.

On July 12, 2019, Burns filed his opening brief in the Arizona Court of Appeals.

APS filed its answering brief on October 21, 2019.

The Arizona Court of Appeals originally granted the request for oral argument;

however, on March 31, 2020, the court vacated the date scheduled for oral argument given the COVID-19 pandemic.

The court determined that the matter could be submitted without oral argument and has taken the matter under advisement and will issue a decision without oral argument.

Burns’ position as an ACC commissioner ended on January 4, 2021.

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.

Both APS and the ACC filed responses opposing the motion and asserting that the matter is moot.

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 oral argument is scheduled for March 8, 2022.

Pinnacle West and APS cannot predict the outcome of this matter.

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West.

In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC.

On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018.

Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019.

APS also received and responded to various follow-on requests from ACC Commissioners on these matters.

Pinnacle West and APS cannot predict the outcome of these matters.

The Company’s CEO, Mr.

Guldner, appeared at the ACC’s January 14, 2020 Open Meeting regarding ACC Commissioners’ questions about political spending.

Guldner committed to the ACC that during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.

Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan

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(“IRP”) process.

In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals.

The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics.

On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020.

At the March 11-12, 2020 workshop, the ACC Staff committed to filing a final draft of proposed rules by July 2020.

On January 30, 2018, the initial Energy Modernization Plan was proposed, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan (“IRP”) process.

On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and subsequent drafts were filed by ACC Staff in July 2019, February 2020, and July 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 is defined as a clean energy resource.

The proposed rules also require 50% of retail energy served be renewable by the end of 2035.

A new energy efficiency standard was not included in the proposed rules.

APS would be required to obtain approval of its action plan included in its IRP and seek recovery of prudently incurred costs in a rate process.

If approved by the ACC Commissioners, the rules would require utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023.

In addition, the ACC Staff proposed changing the IRP planning horizon from 15 years to 10 years.

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

On October 14, 2020, the ACC passed one amendment to ACC Staff’s final draft energy rules that will require electric utilities to obtain 35% of peak load (as measured in 2020) by 2030 from DSM resources, including traditional energy efficiency, demand response and other programs aimed at reducing energy usage, peak demand management and load shifting.

This standard aligns with the proposed rules’ three-year resource planning cycle and allows recovery of costs through existing mechanisms until the ACC issues a decision in a future rate proceeding.

On October 29, 2020, the ACC approved an amendment that will require electric utilities to reduce their carbon emissions over 2016-2018 levels by 50% by 2032;

and 100% by 2050.

The ACC also approved an amendment that will require utilities to install energy storage systems with an aggregate capacity equal to 5% of each utility’s 2020 peak demand by 2035, of which 40% must be derived from customer-owned or customer-leased distributed storage.

Another approved amendment modifies the resource planning process, including requirements for the ACC to approve a utility’s load forecast and resource plan, and for a utility to perform an all-source request for information to guide its resource plan.

On November 13, 2020, the ACC approved a final draft energy rules package, and additional procedural steps in the rulemaking process are required to be completed before the rules may take effect.

Nuclear power was defined as a clean energy resource.

The proposed rules also required 50% of retail energy served be renewable by the end of 2035.

A new EES was not included in the proposed rules.

These rules would have required utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023.

In addition, these rules would have changed the IRP planning horizon from 15 years to 10 years.

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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 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.

APS cannot predict the outcome of this matter.

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

In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans.

APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows.

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 IRP’s from April 1, 2020 to June 26, 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.

The ACC has taken no

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action on APS’s IRP.

APS cannot predict the outcome of this matter.

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

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 2030 and authorizing future rate base treatment of qualifying demand-side resources as proposed in future rate cases.

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

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“Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis.

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

These agreements are pending ACC approval.

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

In March 2021, the ACC approved these agreements.

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

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

APS is evaluating how the revised regulations may impact its operations.

Residential Electric Utility Customer Service Disconnections

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

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

During the Summer Disconnection Moratorium, APS could not

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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.

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

Although the emergency rules expired in December 2019, the Summer Disconnection Moratorium will remain in effect through utility tariffs for 2021 and beyond until the ACC adopts permanent rules or determines otherwise.

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

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

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

Stakeholders submitted initial comments to the draft amendments on September 23, 2019.

ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020.

On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment until December 31, 2020.

The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were placed automatically on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater.

APS will continue to waive late payment fees until October 15, 2021.

The Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt

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expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $ 23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic.

See “COVID-19 Pandemic” above for more information.

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

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

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

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

Although the rules are not yet final, APS intends to employ the calendar method for its disconnection moratorium.

This is consistent with APS’s existing disconnection moratorium processes since 2019.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.

An ACC special open meeting workshop was held on December 3, 2018.

No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff.

On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules.

Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019.

ACC Commissioners submitted additional questions regarding this matter.

On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules.

On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules.

The ACC held a workshop on February 25-26, 2020 on further consideration and discussion of the retail electric competition rules.

During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken.

The ACC Commissioners are continuing to explore the retail electric competition rules.

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

At the same time, the Arizona legislature is considering a bill that would nullify, if approved, a 20-year-old electric deregulation law that has been in place since 1998.

The bill has several procedural steps in the legislative process before becoming law.

APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

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

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

APS opposes Green Mountain Energy’s application and intends to intervene to contest it.

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 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.

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

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

APS cannot predict the outcome of these future activities .

Rate Plan Comparison Tool and Investigation

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

APS developed a new tool for comparing customers’ rate plan options.

APS had an independent third party verify that the new rate comparison tool works correctly.

In February 2020, APS launched the new online rate comparison tool, which is now available for its customers.

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.

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

APS cannot predict if any action will be taken by the ACC at this time.

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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.

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

The settlement results in APS paying $ 24.75 million, $ 24 million of which is being returned to customers as restitution.

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.

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APS filed the SCR Adjustment request in April 2018.

Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment.

The SCR Adjustment request provided that there would be a $ 67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers.

Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019.

The hearing for this matter occurred in September 2018.

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hearing for this matter occurred in September 2018.

At the hearing, APS accepted ACC Staff’s recommendation of a lower annual revenue impact of approximately $ 58.5 million.

The Administrative Law Judge issued a 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.

Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018.

The ACC has not issued a decision on this matter.

APS included the costs for the SCR project in the retail rate base in its 2019 Retail Rate Case filing with the ACC.

On March 18, 2020, the ACC agreed to take administrative notice to include in the pending rate case portions of the record in this prior proceeding that are relevant to the SCRs.

APS cannot predict the outcome or timing of the decision on this matter.

APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

The ACC did not issue a decision on this matter.

APS included the costs for the SCR project in the retail rate base in its 2019 Rate Case filing with the ACC.

On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $ 194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031.

The decision also included a partial and combined disallowance of $ 215.5 million on the SCR investments and deferrals.

APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $ 215.5 million disallowance.

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, 2021.

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

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

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules.

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In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017.

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

Cholla Unit 4 was retired on December 24, 2020.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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

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In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset.

The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.

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

The Navajo Plant ceased operations in November 2019.

The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allows for decommissioning activities to begin after the plant ceased operations.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026.

APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($ 72 million as of December 31, 2020) plus a return on the net book value as well as other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset ($ 18 million as of December 31, 2020).

APS believes it will be allowed recovery of the net book value, in addition to a return on its investment.

In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset.

If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

In accordance with GAAP, in the second quarter of 2017, APS’s remaining

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net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset.

APS has been recovering a return on and of the net book value of its interest in the Navajo plant in base rates over its previously estimated life through 2026.

Pursuant to the 2019 Rate Case decision described above, APS will be allowed continued recovery of the book value of its remaining investment in the Navajo plant ($ 62.2 million as of December 31, 2021), in addition to a return on the net book value, with the exception of 15 % of the annual amortization expense in rates.

In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset ($ 16.8 million as of December 31, 2021).

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities

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Income taxes — AFUDC equity 2051 7,625 164,768 7,169 158,776

Ocotillo deferral (e) 2031 9,507 138,143 — 95,723

Retired power plant costs 2033 15,160 99,681 28,181 114,214

Ocotillo deferral N/A — 95,723 — 38,144

SCR deferral N/A — 81,307 — 52,644

Deferred property taxes 2027 8,569 49,626 8,569 58,196

SCR deferral (e) (f) 2031 8,147 97,624 — 81,307

Lost fixed cost recovery (b) 2022 63,889 — 41,807 —

Deferred property taxes 2027 8,569 41,057 8,569 49,626

Deferred compensation 2036 — 33,997 — 36,195

Four Corners cost deferral 2024 8,077 24,075 8,077 32,152

Income taxes — investment tax credit basis adjustment 2056 1,129 23,639 1,113 24,291

Four Corners cost deferral 2024 8,077 15,998 8,077 24,075

Palo Verde VIEs (Note 18) 2046 — 21,094 — 21,255

Coal reclamation 2026 2,978 13,862 1,068 16,999

Deferred fuel and purchased power — mark-to-market (Note 16) 2024 3,341 9,244 36,887 33,185

Loss on reacquired debt 2038 1,648 9,372 1,689 10,877

Mead-Phoenix transmission line — contributions in aid of construction 2050 332 9,048 332 9,380

Demand side management (b) 2022 — 7,268 — —

Tax expense adjustor mechanism (b) 2031 656 5,845 6,226 —

TCA balancing account (b) 2023 170 3,663 — —

Tax expense of Medicare subsidy 2024 1,235 2,469 1,235 3,704

Demand side management (b) 2022 919 — — 7,268

PSA interest 2022 335 — 4,355 —

TCA balancing account (b) 2021 — — 6,324 2,885

Deferred fuel and purchased power — mark-to-market (Note 16) 2024 — — 3,341 9,244

Other Various — 2,976 2,716 1,100

Total regulatory assets (d) $ 518,524 $ 1,192,987 $ 291,713 $ 1,133,987

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

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

If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.

As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates.

See Note 8 for further discussion.

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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.

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7 unchanged sentences

Removal costs (c) 69,476 50,104 52,844 103,008

Deferred fuel and purchased power — mark-to-market (Note 17) 2024 60,693 46,908 — —

Income taxes — change in rates 2051 2,876 64,802 2,839 66,553

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Renewable energy standard (b) 2022 38,453 187 39,442 103

FERC transmission true up (b) 2023 21,379 12,924 6,598 3,008

Property tax deferral (e) 2024 4,671 15,521 — 13,856

Sundance maintenance 2031 — 13,797 2,989 11,508

Property tax deferral N/A — 13,856 — 7,046

Demand side management (b) 2022 — 5,417 10,819 —

FERC transmission true up 2022 6,598 3,008 1,045 2,004

Tax expense adjustor mechanism (b) (e) N/A — 4,835 7,089 —

Deferred gains on utility property 2022 1,301 551 2,423 1,544

TCA balancing account (b) 2022 — — 2,902 4,672

Tax expense adjustor mechanism (b) (e) 2021 7,089 — 7,018 —

Active union medical trust N/A — — — 6,057

Deferred gains on utility property 2022 2,423 1,544 2,423 4,163

Other Various 210 41 409 189

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(d) See Note 8.

(e) Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $ 7 million of liability recorded to the TEAM balancing account through December 31, 2021.

Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.

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

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8 unchanged sentences

In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of this net regulatory liability over the remaining regulatory life of the related property.

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property.

As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018.

1 unchanged sentence

As a result, the Company began amortization in March 2019.

The Company recorded $ 14 million and $ 57 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities in 2020 and 2019, respectively.

The Company recorded $ 14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities as of March 31, 2020, with these non-depreciation related net excess deferred tax liabilities being fully amortized as of March 31, 2020.

On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5 -year period with amortization to retroactively begin as of January 1, 2018.

The Company recorded $ 31 million and $ 62 million of income tax benefit related to amortization of these depreciation related liabilities in 2020 and 2019, respectively.

The Company recorded $ 31 million of income tax benefit related to amortization of these depreciation related net excess deferred tax liabilities for the periods ending December 31, 2021, and December 31, 2020.

See Note 4 for more details.

In August 2018, U.S.

Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018.

However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018.

In September 2019, U.S.

Treasury issued final regulations, which replaced the August 2018 proposed regulations.

These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018.

In September 2020, U.S.

Treasury issued final regulations, which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017.

The final regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 continues to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act.

These final regulations do not materially impact any tax position taken by the Company for property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020.

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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.

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See Note 18 for additional details related to the Palo Verde sale leaseback VIEs.

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

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Unrecognized tax benefit interest expense/(benefit) recognized $ ( 535 ) $ 266 $ 459 $ ( 535 ) $ 266 $ 459

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

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Additionally, as of December 31, 2021, we have recognized less than $ 1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

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

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

Pinnacle West Consolidated APS Consolidated

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Income tax expense/(benefit) $ 110,086 $ 78,173 $ ( 15,773 ) $ 125,553 $ 88,764 $ ( 9,572 )

T he following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):

The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):

Pinnacle West Consolidated APS Consolidated

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State income tax credits net of federal income tax benefit ( 7,015 ) ( 8,951 ) ( 8,519 ) ( 5,277 ) ( 7,213 ) ( 6,781 )

Nondeductible expenditures associated with ballot initiative — — 7,879 — — —

Stock compensation 34 ( 2,252 ) ( 1,804 ) 183 ( 1,054 ) ( 780 )

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

Excess deferred income taxes — Tax Cuts and Jobs Act ( 36,558 ) ( 50,543 ) ( 124,082 ) ( 36,558 ) ( 50,543 ) ( 124,082 )

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Deferred income taxes — net $ ( 2,311,862 ) $ ( 2,135,403 ) $ ( 2,331,701 ) $ ( 2,143,673 )

As of December 31, 2020, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $ 35 million, which first begin to expire in 2036 and state credit carryforwards net of federal benefit of $ 33 million, which first begin to expire in 2023.

As of December 31, 2021, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $ 51 million, which first begin to expire in 2036, state credit carryforwards net of federal benefit of $ 42 million, which first begin to expire in 2023, and Arizona net operating loss net of federal benefit of $ 6 million, which will expire in 2041.

PNW Consolidated credit and loss carryforwards amount above has been reduced by $ 42 million of unrecognized tax benefits.

As of December 31, 2020, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $ 16 million, which first begin to expire in 2024.

APS Consolidated credit and loss carryforwards amount above has been reduced by $ 8 million of unrecognized tax benefits.

As of December 31, 2021, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $ 24 million, which first begin to expire in 2024 and Arizona net operating loss net of federal benefit of $ 4 million, which will expire in 2041.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated credit and loss carryforwards amount above has been reduced by $ 9 million of unrecognized tax benefits.

Lines of Credit and Short-Term Borrowings

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

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2020 and 2019 (dollars in thousands):

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

December 31, 2021 December 31, 2020

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Amount of Credit Facilities Available $ 186,700 $ 721,300 $ 908,000 $ 62,000 $ 1,000,000 $ 1,062,000

Weighted-Average Commitment Fees 0.125 % 0.100 % 0.125 % 0.100 %

Commitment Fees 0.175 % 0.125 % 0.125 % 0.100 %

Pinnacle West

On May 5, 2020, Pinnacle West refinanced its 364-day $ 50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $ 31 million term loan agreement that matures May 4, 2021.

Borrowings under the agreement bear interest at Eurodollar Rate plus 1.40 % per annum.

At December 31, 2020, Pinnacle West had $ 19 million in outstanding borrowings under the agreement.

At December 31, 2020, Pinnacle West had a $ 200 million revolving credit facility that matures in July 2023.

On May 5, 2020, Pinnacle West refinanced its 364-day $ 50 million term loan agreement with a new 364-day $ 31 million term loan facility that would have matured May 4, 2021 .

Borrowings under the facility bore interest at Eurodollar Rate plus 1.40 % per annum.

Pinnacle West repaid this facility on April 27, 2021.

On May 28, 2021, Pinnacle West replaced its $ 200 million revolving credit facility that would have matured on July 11, 2023, with a new $ 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.

Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings.

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

At December 31, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $ 150 million of commercial paper borrowings.

At December 31, 2020, APS had two revolving credit facilities totaling $ 1 billion, including a $ 500 million credit facility that matures in June 2022 and a $ 500 million facility that matures in July 2023.

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.

These facilities are available to support APS’s $ 500 million commercial paper program, for bank borrowings or for issuances of letters of credit.

At December 31, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding or commercial paper borrowings.

See “Financial Assurances” in Note 11 for a discussion of APS’s other outstanding letters of credit.

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.

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

At December 31, 2021, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility and $ 13 million of commercial paper borrowings.

On May 28, 2021, APS replaced its two $ 500 million revolving credit facilities that would have matured on June 29, 2022 and July 11, 2023, respectively, with two new $ 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2021, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $ 279 million of outstanding commercial paper borrowings.

See “Financial Assurances” in Note 11 for a discussion of other outstanding letters of credit.

Debt Provisions

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See Note 7 for additional long-term debt provisions.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt and Liquidity Matters

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

The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2020 and 2019 (dollars in thousands):

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

Maturity Interest December 31,

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Variable 2029 (b) $ 35,975 $ 35,975

Fixed 2024 4.70 % — 115,150

Total pollution control bonds 35,975 35,975

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6,280,000 5,830,000

Term loans (c) — 200,000

Unamortized discount ( 14,995 ) ( 15,900 )

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Senior unsecured notes 2025 1.3 % 500,000 500,000

Term loan (d) — 150,000

Term loans 2022-2024 (c) 300,000 —

Unamortized discount ( 34 ) ( 44 )

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This term loan was repaid on May 26, 2020.

See additional details below.

(d) The weighted-average interest rate was 2.20 % at December 31, 2019.

This term loan was repaid on June 19, 2020.

See additional details below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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2024 400,000 250,000

2025 800,000 300,000

2026 250,000 250,000

Thereafter 5,515,975 5,515,975

Total $ 7,115,975 $ 6,315,975

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Debt Fair Value

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Pinnacle West

On June 17, 2020, Pinnacle West issued $ 500 million of 1.3 % unsecured senior notes that mature June 15, 2025.

The net proceeds from the sale were used to repay early its $ 150 million term loan facility set to mature on December 21, 2020, to repay short-term indebtedness consisting of commercial paper and replenish cash incurred or used to fund capital expenditures, to redeem prior to maturity our $ 300 million, 2.25 % senior notes due November 30, 2020, and for general corporate purposes.

On December 21, 2021, Pinnacle West entered into a $ 450 million term loan facility that matures December 20, 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 matures June 30, 2022.

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We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.

On January 15, 2020, APS repaid at maturity the remaining $ 150 million of the $ 250 million aggregate principal amount of its 2.2 % senior notes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On May 22, 2020, APS issued $ 600 million of 3.35 % unsecured senior notes that mature May 15, 2050.

The net proceeds from the sale were used to repay early its $ 200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

On September 11, 2020, APS issued $ 400 million of 2.65 % unsecured senior notes that mature September 15, 2050.

The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.

On November 19, 2020, APS reopened its $ 300 million, 2.6 % unsecured senior notes that mature on August 15, 2029, and issued an additional $ 105 million of 2.6 % unsecured senior notes.

The aggregate balance of $ 405 million will mature on August 15, 2029.

The net proceeds from the sale, together with funds made available from other sources, were used to redeem, prior to maturity, no later than 20 days after the date that the new notes were issued, (i) the $ 49.4 million outstanding principal amount of 4.7 % City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series A, and (ii) the $ 65.75 million outstanding principal amount of 4.7 % City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series B.

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

On August 16, 2021, APS issued $ 450 million of 2.2 % unsecured senior notes that mature December 15, 2031.

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.

On December 21, 2021, Pinnacle West contributed $ 150 million into APS in the form of an equity infusion.

APS used this contribution to repay short-term indebtedness.

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.

See “Lines of Credit and Short-Term Borrowings” in Note 6 and “Financial Assurances” in Note 11 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 microgrid project in California under development by the subsidiary.

The credit facilities consist of an approximately $ 33 million equity bridge loan facility, an

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

approximately $ 42 million non-recourse construction to term loan facility, and an approximately $ 5 million letter of credit.

In connection with the credit agreement, Pinnacle West has guaranteed the full amount of the equity bridge loan.

On February 11, 2022, $ 12 million was drawn from the equity bridge loan.

Debt Provisions

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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.

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We calculate the benefits based on age, years of service and pay.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement “HRA”) for the employees of Pinnacle West and its subsidiaries.

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The market-related value of our plan assets is their fair value at the measurement date.

(See Note 13 for further discussion of how fair values are determined.) 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.

See Note 13 for further discussion of how fair values are determined.

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.

In prior years, we had been assuming a 4.75 % escalation of these benefits;

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

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

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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 (see Note 19).

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Accordingly, these changes are recorded as a regulatory asset or regulatory liability (see Note 4).

Accordingly, these changes are recorded as a regulatory asset or regulatory liability.

Our retail rates provide for the inclusion of annual benefit costs, which allows for recovery or return of this regulatory asset/liability.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

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Service cost-benefits earned during the period $ 61,236 $ 56,233 $ 49,902 $ 17,796 $ 22,236 $ 18,369

$ 56,233 $ 49,902 $ 56,669 $ 22,236 $ 18,369 $ 21,100

Non-service costs (credits):

Interest cost on benefit obligation 98,566 118,567 136,843 16,513 25,857 29,894

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Prior service credit — — — ( 37,705 ) ( 37,575 ) ( 37,821 )

Net actuarial loss 34,612 42,584 32,082 — — —

Net actuarial (gain)/loss 15,948 34,612 42,584 ( 10,093 ) — —

Net periodic benefit cost/(benefit) $ ( 26,878 ) $ 21,969 $ 57,445 $ ( 54,933 ) $ ( 29,559 ) $ ( 27,970 )

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Benefit payments ( 192,672 ) ( 174,180 ) ( 24,310 ) ( 26,405 )

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

Fair value of plan assets at December 31 3,812,041 3,886,544 872,435 961,165

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Fair value of plan assets — —

The Pinnacle West Capital Corporation Retirement Plan is more than 100 % funded on a projected benefit obligation basis at December 31, 2020, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2020 is a non-qualified supplemental excess benefit retirement plan.

The Pinnacle West Capital Corporation Retirement Plan is more than 100 % funded on a projected benefit obligation basis at December 31, 2021, and December 31, 2020, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2021 and 2020 is a non-qualified supplemental excess benefit retirement plan.

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

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Noncurrent liability ( 152,865 ) ( 166,484 ) — —

Net amount recognized $ ( 16,323 ) $ ( 294,763 ) $ 337,131 $ 90,570

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2020 and 2019 (dollars in thousands):

Net amount recognized (funded status) $ 95,217 $ ( 16,323 ) $ 280,594 $ 337,131

The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2021, and 2020 (dollars in thousands):

Pension Plans Other Benefits Plans

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Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates.

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

Treasury and other

Long-term fixed

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

government agencies, U.S.

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

Treasury and other government agencies, U.S.

Treasury Futures Contracts, and fixed income debt securities issued by corporations.

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Based on the IPS, and given the pension plan’s funded status at year-end 2021, the target and actual allocation for the pension plan at December 31, 2021, are as follows:

Pension Plans

Target Allocation Actual Allocation

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The permissible range is within +/-3% of the target allocation shown in the above table, and also considers the plan’s funded status.

At December 31, 2020, the return-seeking assets were slightly outside the target allocation permissible range and were rebalanced to within the target range during January 2021.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:

Asset Class Target Allocation

Target Allocation

Equities in US and other developed markets 12 %

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The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2021:

Other Benefits Plans

Actual Allocation

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Return-generating assets 37 %

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied.

The plans invest directly in fixed income, U.S.

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.

Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

use of mutual funds, partnerships and common and collective trusts.

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.

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

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

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

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Real estate — — 191,595 191,595

Fixed Income — — 98,065 98,065

Partnerships — — 22,420 22,420

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We made contributions to our pension plan totaling $ 100 million in 2021, $ 100 million in 2020, and $ 150 million in 2019.

The minimum required contributions for the pension plan are zero for the next three years.

We expect to make voluntary contributions up to $ 100 million in 2021 and zero thereafter.

With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2020 and 2019.

We do not expect to make any contributions over the next three years to

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 2022, 2023 or 2024.

With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2021 or 2020 and do not expect to make any contributions in 2022, 2023 or 2024.

The Company was reimbursed

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

our other postretirement benefit plans.

The Company was reimbursed $ 26 million in 2020, $ 30 million in 2019, and $ 72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

$ 24 million in 2021, $ 26 million in 2020, and $ 30 million in 2019 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

Estimated Future Benefit Payments

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Pinnacle West recorded expenses for this plan of approximately $ 12 million for 2021, $ 11 million for 2020, and $ 11 million for 2019.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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See Note 18 for a discussion of VIEs.

On June 1, 2020 APS had two separate purchased power lease contracts that commenced.

The lease terms end on September 30, 2025 and September 30, 2026, respectively.

Both of these leases allow APS the right to the generation capacity from certain natural-gas fueled generators during the months of June through September over the contract term.

On May 1, 2021, APS had a new purchased power lease contract that commenced, with a lease term expiring on October 31, 2027.

On December 31, 2021, APS modified an existing purchased power lease contract that had commenced in June 2020.

The lease modification extends the expiration of this

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

lease from September 30, 2025, to October 31, 2031, among other changes.

These purchased power lease agreements allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements.

As APS only has rights to use the assets during certain periods of each year the leases have non-consecutive periods of use.

APS does not operate or maintain these leased assets.

APS controls the dispatch of the leased assets during the months of June through September and is required to pay a fixed monthly capacity payment during these periods of use.

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

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

December 31, 2020 Year Ended

December 31, 2019

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

Operating lease cost $ 68,883 $ 18,493 $ 87,376 $ 42,190 $ 18,038 $ 60,228

Variable lease cost 121,359 972 122,331 113,233 782 114,015

For the Year Ended

2021 2020 2019

Operating Lease Cost - Purchased Power Lease Contracts $ 105,762 $ 68,883 42,190

Operating Lease Cost - Land, Property, and Other Equipment 18,498 18,493 18,038

Total Operating Lease Cost 124,260 87,376 60,228

Variable lease cost (a) 118,969 122,331 114,015

Short-term lease cost 3,872 3,804 4,385

Total lease cost $ 247,101 $ 213,511 $ 178,628

(a) Primarily relates to purchased power lease contracts.

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

Lease costs relating to purchased power 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 (see Note 4).

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.

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

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

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

Certain of our lease agreements

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

have lease terms with non-consecutive periods of use.

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.

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

For these agreements we recognize lease costs during the periods of use.

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

Lease expense recognized in the Consolidated Statements of Income was $ 18 million in 2018, this amount does not include purchased power lease contracts.

Operating lease cost for purchased power lease contracts was $ 47 million in 2018.

In addition, contingent rents for purchased power lease contracts was $ 109 million in 2018.

These purchased power lease costs are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):

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We recognize lease assets and liabilities upon lease commencement.

At December 31, 2020, we have certain purchased power lease contracts, that have been executed but have not yet commenced.

In January 2021, we also executed additional purchased power lease contracts relating to energy storage.

These arrangements have commencement dates beginning in May 2021 with terms ending through December 2042.

We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $ 650 million over the term of the arrangements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2021, we have various lease arrangements that have been executed but have not yet commenced.

These arrangements primarily relate to energy storage assets, with expected lease commencement dates ranging from June 2022 through June 2024, with lease terms expiring through May 2044.

We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $ 1.3 billion over the term of the arrangements.

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

December 31, 2020 Year Ended December 31, 2019

December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019

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

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(b) Weighted-average of interests.

The common facilities at Cholla are jointly-owned.

Cholla Unit 4 was retired on December 24, 2020.

The common facilities at Cholla are jointly-owned.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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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 the United States Department of Energy (“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, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.

On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011.

In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

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”).

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

On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011.

The settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

On September 1, 2020, APS and DOE entered into an addendum to the settlement agreement allowing for the recovery of costs incurred through December 31, 2022.

APS has submitted six claims pursuant to the terms of the August 18, 2014 settlement agreement, for six separate time periods during July 1, 2011 through June 30, 2019.

The DOE has approved and paid $ 99.7 million for these claims (APS’s share is $ 29.0 million).

APS has submitted seven claims pursuant to the terms of the August 18, 2014, settlement agreement, for seven separate time periods during July 1, 2011, through June 30, 2020.

DOE has approved and paid $ 111.8 million for these claims (APS’s share is $ 32.5 million).

The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income.

In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4).

On November 2, 2020, APS filed its seven th claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $ 12.2 million (APS’s share is $ 3.6 million).

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

On November 1, 2021, APS filed its eight h claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $ 12.2 million (APS’s share is $ 3.6 million).

In February 2022, the DOE approved 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 of up to approximately $ 13.8 billion per occurrence.

Palo Verde maintains the maximum available nuclear liability insurance in the amount of $ 450 million, which is provided by American Nuclear Insurers (“ANI”).

In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $ 13.5 billion per occurrence.

Palo Verde maintains the maximum available nuclear liability insurance in the amount of $ 450 million, which is provided by American Nuclear Insurers.

The remaining balance of approximately $ 13.1 billion of liability coverage is provided through a mandatory, industry-wide retrospective premium program.

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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,

APS has also secured accidental outage

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

insurance for a sudden and unforeseen accidental outage of any of the three units.

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

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

The maximum amount APS could incur under the current NEIL policies totals approximately $ 22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.

In addition, NEIL policies contain rating triggers that would result in APS providing approximately $ 75.1 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.

Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $ 63.3 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment.

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

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APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2022 and 2043 that include required purchase provisions.

APS estimates the contract requirements to be approximately $ 772 million in 2021;

APS estimates the contract requirements to be approximately $ 1 billion in 2022;

$ 765 million in 2023;

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However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

These amounts include estimated commitments relating to purchased power lease contracts (see Note 9).

These amounts include estimated commitments relating to purchased power lease contracts.

Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions.

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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):

Year Ended December 31,

Years Ended December 31,

2021 2020 2019

Total purchases $ 219,958 $ 189,817 $ 204,888

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Renewable Energy Credits

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These amounts do not include purchases of renewable energy credits that are bundled with energy.

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Coal Mine Reclamation Obligations

APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation.

APS must reimburse certain coal providers for final and contemporaneous coal mine reclamation.

We account for contemporaneous reclamation costs as part of the cost of the delivered coal.

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and $ 48 million thereafter.

Any amendments to current coal supply agreements may change the timing of the contribution.

Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

These funds are held in an escrow account and will be distributed to certain coal providers under the terms of the applicable coal supply agreements.

Any amendments to current coal supply agreements may change the timing of the contribution or cost of final reclamation.

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

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

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

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

On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona.

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Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS during the first or second quarter of 2022.

We estimate that our costs related to this investigation and study will be approximately $ 3 million.

We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

APS's estimated costs related to this investigation and study is approximately $ 3 million.

APS anticipates incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, 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.

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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, 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.

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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.

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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

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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.

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.

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

The settlement results in APS paying $ 24.75 million, $ 24 million of which is being returned to customers as restitution.

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

Four Corners SCR Cost Recovery

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

The decision also included a partial and combined disallowance of $ 215.5 million on the SCR investments and deferrals.

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

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$ 154.4 million.

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

See Note 4 for additional information regarding the Four Corners SCR cost recovery.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs.

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and 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.

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

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 below for details of the Cholla BART approval.

Four Corners.

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.

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See “Four Corners — 4CA Matter” below for a discussion of the NTEC purchase.

The cost of the pollution controls related to

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the 7 % interest is approximately $ 45 million, which was assumed by NTEC through its purchase of the 7 % interest.

In early 2017, EPA approved a final rule containing a revision to Arizona’s State Implementation Plan (“SIP”) for Cholla that implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements.

In conjunction with the closure of Cholla Unit 2 in 2015, APS has committed to ceasing coal combustion within Units 1 and 3 by April 2025.

PacifiCorp retired Cholla Unit 4 at the end of 2020.

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.

See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset.

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The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

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• 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.

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Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations.

On July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments;

such disposal units must close as soon as technically feasible, but no later than April 22, 2021.

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On July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments by April 11, 2021, at the latest.

All APS disposal units subject to these closure requirements were closed as of April 11, 2021.

• On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure.

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

On January 11, 2022, EPA began issuing proposed decisions pursuant to this provision of the federal CCR regulations and we anticipate receiving a proposed decision with respect to the Cholla facility in 2022.

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.

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As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring.

APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action.

In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by October 31, 2020.

APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2021.

As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action.

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

APS determined that several of its CCR disposal units at Cholla and

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Four Corners will need to undergo corrective action.

In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by April 11, 2021, at the latest (except for those disposal units subject to alternative closure).

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

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

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

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.

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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.

The ACE regulations had been stayed pending judicial review and on January 19, 2021, the U.S.

On January 19, 2021, the U.S.

Court of Appeals for the D.C.

Circuit vacated the ACE regulations and remanded them back to

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EPA to develop new existing power plant carbon regulations consistent with the court’s ruling.

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 ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP.

While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision.

Nonetheless, on October 29, 2021, the U.S.

Supreme Court announced that it was accepting judicial review of the January D.C.

Circuit decision vacating the ACE regulations.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.

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

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board (“EAB”) concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018.

The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.

To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018.

Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis.

The EAB thereafter dismissed the environmental group appeal on February 12, 2019.

The latest NPDES permit for Four Corners was issued on September 30, 2019.

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

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.

Oral argument on this appeal

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

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.

We cannot predict the outcome of these appeal proceedings and, if such appeal is successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.

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The September 2019 permit remains in effect pending this appeal.

As of November 11, 2021, the parties to this lawsuit, including APS, reached a tentative agreement to settle this matter.

Review of this agreement, including public commenting, is currently pending with EPA.

Notwithstanding this tentative agreement, we cannot predict the outcome of these appeal proceedings, including further settlement discussions, and, if settlement efforts fail and the appeal is eventually successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.

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

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

As of December 31, 2020, the note has a remaining balance of $ 27 million.

As of December 31, 2021, the note has a remaining balance of approximately $ 9.2 million.

NTEC continues to make payments in accordance with the terms of the note.

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

The 2016 Coal Supply Agreement contained alternate pricing terms for the 7 % interest in the event NTEC did not purchase the interest.

Until the time that NTEC purchased the 7 % interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7 % interest.

These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales.

The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7 % interest) was approximately $ 10 million, which was due to 4CA on December 31, 2019.

Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations of which the prepayment has been fully utilized as of June 2020.

Financial Assurances

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These instruments support commodity contract collateral obligations and other transactions.

As of December 31, 2020, standby letters of credit totaled $ 5.2 million and will expire in 2021.

As of December 31, 2020, surety bonds expiring through 2022 totaled $ 16 million.

As of December 31, 2021, standby letters of credit totaled approximately $ 5 million and will expire in 2022.

As of December 31, 2021, surety bonds expiring through 2023 totaled approximately $ 14 million.

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

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

(See “Four Corners — 4CA Matter” above for information related to this guarantee.) Pinnacle West has not needed to perform under this guarantee.

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

Pinnacle West has not needed to perform under this guarantee.

A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated;

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 and Nobles 2 wind farms, 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 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”).

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

The Equity Contribution Guarantees remaining as of December 31, 2020 are immaterial in amount (approximately $ 3 million) and the PTC Guarantees (approximately $ 39 million as of December 31, 2020) are currently expected to be terminated ten years following the commercial operation date of the applicable project.

The Equity Contribution Guarantees remaining as of December 31, 2021, are immaterial in amount (approximately $ 2 million) and the PTC Guarantees (approximately $ 37 million as of December 31, 2021) are currently expected to be terminated 10 years following the commercial operation date of the applicable project.

In connection with the credit agreement entered into by a special purpose subsidiary of BCE on Februa ry 11, 2022, Pinnacle West has guaranteed the full amount of the equity bridge loan under the credit facility.

See Note 7 for additional details.

Asset Retirement Obligations

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 4 and 11.

In 2020, APS revised its cost estimates for existing AROs at Cholla relating to updated estimates for the closure of ponds and facilities, and at Four Corners and the Navajo Plant relating to corrective action and water monitoring costs, which resulted in an increase to the ARO of $ 6 million.

Also in 2020, an updated Four Corners decommissioning study was finalized for the updated closure date of 2031, which resulted in an increase to the ARO of $ 13 million.

In 2019, APS received updated decommissioning estimates for the Navajo Plant closure in December 2019, which resulted in a decrease to the ARO in the amount of $ 8 million (see Note 4 for additional information).

In addition, APS received a new decommissioning study for Palo Verde.

This resulted in a decrease to the ARO in the amount of $ 89 million, a decrease in plant in service of $ 80 million and a reduction in the regulatory liability of $ 9 million.

The following table shows the change in our asset retirement obligations for 2020 and 2019 (dollars in thousands):

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

Asset retirement obligations at the beginning of year $ 705,083 $ 657,218

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

Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

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

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

Recurring Fair Value Measurements

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Equity Securities

The Nuclear Decommissioning Trust’s equity security investments are held indirectly through commingled funds.

The nuclear decommissioning trusts’ equity security investments are held indirectly through commingled funds.

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

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Commodity contracts $ — $ ( 4,740 ) $ ( 2,738 ) $ 3,105 (a) $ ( 4,373 )

(a) Represents counterparty netting, margin, and collateral (see Note 16).

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

(b) Represents net pending securities sales and purchases.

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Commodity contracts $ — $ ( 20,498 ) $ ( 1,107 ) $ 2,986 (a) $ ( 18,619 )

(a) Represents counterparty netting, margin, and collateral (see Note 16).

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

(b) Represents net pending securities sales and purchases.

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Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.

Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).

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

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The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy.

(See Note 7 for our long-term debt fair values.) The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9 % per annum and has a book value of $ 27.1 million as of December 31, 2020, as presented on the Consolidated Balance Sheets.

See Note 7 for our long-term debt fair values.

The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9 % per annum and has a book value of $ 9 million as of December 31, 2021, as presented on the Consolidated Balance Sheets.

The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy.

See Note 11 for more information on 4CA matters.

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Earnings Per Share

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During 2021, 2020, and 2019, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares.

Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

Awards granted from 2012 to May 2021 were issued under the 2012 Long-Term Incentive Plan (“2012 Plan”), and awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”).

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

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Stock-Based Compensation Expense and Activity

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The total fair value of shares vested was $ 22 million in 2021, $ 22 million in 2020 and $ 21 million in 2019.

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The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2020, 2019 and 2018:

The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years:

Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b)

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(b) Reflects the target payout level.

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The following table is a summary of the status of non-vested awards as of December 31, 2021, and changes during the year:

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however, awards granted to retirement-eligible employees will vest upon the employee’s retirement.

Awardees elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

Restricted stock unit awards typically include a

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dividend equivalent feature.

Awardees typically elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

Restricted stock unit awards typically include a dividend equivalent feature.

This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock.

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Compensation cost is recognized over the requisite service period based on the fair value of the award.

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Stock grants are issued to non-officer members of the Board of Directors.

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Compensation cost relating to the TSR component of the award 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.

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Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates.

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates.

Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options, and swaps.

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While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.

Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

Contracts that have the same terms (quantities, delivery points and delivery periods) and for which

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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.

(See Note 13 for a discussion of fair value measurements.) Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.

See Note 13 for a discussion of fair value measurements.

Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery, and the quantities represent those transacted in the normal course of business.

Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

For its regulated operations, APS defers for future rate treatment 100 % of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.

Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4).

Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate.

Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

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Gas Billion cubic feet 155 205

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Gains and Losses from Derivative Instruments

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For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed.

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The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):

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Commodity Contracts Location 2021 2020 2019

Net Loss Recognized in Income Operating revenues $ — $ — $ ( 2,557 )

Net Loss Recognized in Income Fuel and purchased power (a) ( 3,178 ) ( 84,953 ) ( 12,951 )

Total $ ( 3,178 ) $ ( 84,953 ) $ ( 15,508 )

Net Gain (Loss) Recognized in Income Fuel and purchased power (a) $ 216,847 $ ( 3,178 ) $ ( 84,953 )

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

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Derivatives Other

Balance Sheet

Balance Sheets

Current assets $ 66,777 $ ( 3,346 ) $ 63,431 $ 50 $ 63,481

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

Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral posted in excess of the recognized derivative instrument.

Includes cash collateral received from counterparties of $ 1,285 .

Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.

Includes cash collateral received from counterparties of $ 1,635 and cash margin provided to counterparties of $ 50 .

As of December 31, 2020:

(dollars in thousands) Gross

Balance Sheet

Derivatives Other

Balance Sheets

Current assets $ 5,870 $ ( 2,939 ) $ 2,931 $ — $ 2,931

Investments and other assets 3,150 ( 1,332 ) 1,818 — 1,818

Total assets 9,020 ( 4,271 ) 4,749 — 4,749

Current liabilities ( 9,211 ) 2,939 ( 6,272 ) ( 1,285 ) ( 7,557 )

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Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.

Includes cash collateral received from counterparties of $ 1,185 and cash margin provided to counterparties of $ 405 .

Includes cash collateral received from counterparties of $ 1,285 .

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties.

As of December 31, 2020, we have four counterparties for which our exposure represents approximately 62 % of Pinnacle West’s $ 5 million of risk management assets.

This exposure relates to master agreements with counterparties and all four are rated as investment grade.

As of December 31, 2021, we have three counterparties for which our exposure represents approximately 38 % of Pinnacle West’s $ 110 million of risk management assets.

This exposure relates to master agreements with counterparties and all three are rated as investment grade.

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

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Total other expense $ ( 25,396 ) $ ( 57,776 ) $ ( 17,880 )

(a) Miscellaneous includes donation of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan (see Note 4).

(a) The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

Other Income and Other Expense - APS

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Total other expense $ ( 18,897 ) $ ( 53,694 ) $ ( 12,990 )

(a) Miscellaneous includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan (see Note 4).

(a) The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.

APS will retain the assets through 2023 under one lease and 2033 under the other two leases.

APS will be required to make payments relating to these leases of approximately $ 23 million annually for the period 2021 through 2023, and about $ 16 million annually for the period 2024 through 2033.

Prior to April 1, 2021, the lease terms allowed APS the right to retain the assets through 2023 under one lease and 2033 under the other two leases.

On April 1, 2021, APS executed an amended lease agreement with one of the VIE lessor trust entities relating to the lease agreement with the term ending in 2023.

The amendment extends the lease term for this lease through 2033 and changes the lease payment.

As a result of this amendment, APS will now retain the assets through 2033 under all three lease agreements.

APS will be required to make payments relating to the three leases in total of approximately $ 21 million annually for the period 2022 through 2033.

At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years , or return the assets to the lessors.

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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 $ 19 million for 2020, 2019 and 2018.

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 2021, and $ 19 million for 2020 and 2019.

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

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For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

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

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

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

We record both debt and equity security

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

investments at their fair value on our Consolidated Balance Sheets.

(See Note 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy.) The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

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

See Note 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy.

The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts — APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde.

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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 regulatory liabilities.

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

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

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

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

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

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

On January 4, 2021, an additional $ 106 million of investments were transferred from APS other postretirement benefit trust assets into the active union employee medical account, see Note 8.

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 trust and other special use fund assets at December 31, 2020 and December 31, 2019 (dollars in thousands):

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):

December 31, 2021

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2020, 2019 and 2018 (dollars in thousands):

Year Ended December 31,

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Proceeds from the sale of securities (a) 473,806 245,228 719,034

(a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust.

(a) Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2020 is as follows (dollars in thousands):

Nuclear Decommissioning Trusts Coal Reclamation Escrow Account Active Union Medical Trust Total

The fair value of APS’s fixed income securities, summarized by contractual maturities, at December 31, 2021, is as follows (dollars in thousands):

Nuclear Decommissioning Trusts Coal Reclamation Escrow Account Active Union Employee Medical Account Total

Less than one year $ 31,070 $ 36,852 $ 40,870 $ 108,792

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Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2020 and 2019 (dollars in thousands):

The following table shows the changes in Pinnacle West’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

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Balance at December 31, 2021 $ ( 53,885 ) $ ( 976 ) $ ( 54,861 )

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost (see Note 8).

(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 (see Note 16).

(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 for the years ended December 31, 2020 and 2019 (dollars in thousands):

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

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Balance at December 31, 2021 $ ( 34,880 ) $ — $ ( 34,880 )

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost (see Note 8).

(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 (see Note 16).

(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.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

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Short-term debt repayments under revolving credit facility ( 19,000 ) ( 230,690 ) ( 65,000 )

Commercial paper — net 73,325 54,275 ( 7,000 )

Short-term borrowings and (repayments) — net ( 136,700 ) 73,325 54,275

Dividends paid on common stock ( 369,478 ) ( 350,577 ) ( 329,643 )

Repayment of long-term debt — ( 450,000 ) —

Common stock equity issuance — net of purchases ( 1,389 ) 692 ( 5,055 )

Other — — ( 1 )

Common stock equity issuance and purchases — net ( 2,350 ) ( 1,389 ) 692

Net cash flow used for financing activities ( 227,528 ) ( 250,691 ) ( 290,676 )

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The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company.

Investments in subsidiaries are accounted for using the equity method.

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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