Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND

FINANCIAL STATEMENT SCHEDULES


			Page

Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)			89
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)			90
Pinnacle West Consolidated Statements of Income for 2021, 2020 and 2019			94
Pinnacle West Consolidated Statements of Comprehensive Income for 2021, 2020 and 2019			95
Pinnacle West Consolidated Balance Sheets as of December 31, 2021 and 2020			96
Pinnacle West Consolidated Statements of Cash Flows for 2021, 2020 and 2019			98
Pinnacle West Consolidated Statements of Changes in Equity for 2021, 2020 and 2019			99

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)			100
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)			101
APS Consolidated Statements of Income for 2021, 2020 and 2019			105
APS Consolidated Statements of Comprehensive Income for 2021, 2020 and 2019			106
APS Consolidated Balance Sheets as of December 31, 2021 and 2020			107
APS Consolidated Statements of Cash Flows for 2021, 2020 and 2019			109
APS Consolidated Statements of Changes in Equity for 2021, 2020 and 2019			110

Combined Notes to Consolidated Financial Statements			111



Note 1. Summary of Significant Accounting Policies			111
Note 2. Revenue			119
Note 3. New Accounting Standards			121
Note 4. Regulatory Matters			121
Note 5. Income Taxes			143
Note 6. Lines of Credit and Short-Term Borrowings			147
Note 7. Long-Term Debt and Liquidity Matters			149
Note 8. Retirement Plans and Other Postretirement Benefits			151
Note 9. Leases			160
Note 10. Jointly-Owned Facilities			163
Note 11. Commitments and Contingencies			164
Note 12. Asset Retirement Obligations			172
Note 13. Fair Value Measurements			173
Note 14. Earnings Per Share			178
Note 15. Stock-Based Compensation			178
Note 16. Derivative Accounting			181
Note 17. Other Income and Other Expense			186
Note 18. Palo Verde Sale Leaseback Variable Interest Entities			187
Note 19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds			188
Note 20. Changes in Accumulated Other Comprehensive Loss			191

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2021. The effectiveness of our internal control over financial reporting as of December 31, 2021, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

February 25, 2022

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Pinnacle West Capital Corporation

Phoenix, Arizona

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, 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).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based

on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting — Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the financial statements*.*

Critical Audit Matter Description

Arizona Public Service Company (“APS”), which is a wholly-owned subsidiary of the Company, is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.

The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs

and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment. If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.

We identified Regulatory Accounting, specifically the impact of rate regulation on the financial statements, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements. 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 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 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. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; and the implementation of new rates as ordered by the ACC.
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 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.

◦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. For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.
We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery. We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, 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

Phoenix, Arizona

February 25, 2022

We have served as the Company’s auditor since 1932.

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(dollars and shares in thousands, except per share amounts)


	Year Ended December 31,
	2021		2020		2019

OPERATING REVENUES (Note 2)	$	3,803,835	$	3,586,982	$	3,471,209
OPERATING EXPENSES
Fuel and purchased power	1,152,551		993,419		1,042,237
Operations and maintenance	954,067		958,910		941,616

Depreciation and amortization	650,875		614,378		590,929
Taxes other than income taxes	234,639		224,835		218,579
Other expenses	6,393		7,288		5,888
Total	2,998,525		2,798,830		2,799,249
OPERATING INCOME	805,310		788,152		671,960
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	41,737		33,776		31,431
Pension and other postretirement non-service credits — net (Note 8)	112,541		56,341		22,989
Other income (Note 17)	45,100		56,703		50,263
Other expense (Note 17)	(25,396)		(57,776)		(17,880)
Total	173,982		89,044		86,803
INTEREST EXPENSE
Interest charges	254,314		247,501		235,251
Allowance for borrowed funds used during construction (Note 1)	(21,052)		(18,530)		(18,528)
Total	233,262		228,971		216,723
INCOME BEFORE INCOME TAXES	746,030		648,225		542,040
INCOME TAXES (Note 5)	110,086		78,173		(15,773)
NET INCOME	635,944		570,052		557,813
Less: Net income attributable to noncontrolling interests (Note 18)	17,224		19,493		19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	618,720	$	550,559	$	538,320

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	112,910		112,666		112,443
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	113,192		112,942		112,758

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	5.48	$	4.89	$	4.79
Net income attributable to common shareholders — diluted	$	5.47	$	4.87	$	4.77

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)


	Year Ended December 31,
	2021		2020		2019

NET INCOME	$	635,944	$	570,052	$	557,813

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
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)	18		592		1,137
Pension and other postretirement benefits activity, net of tax benefit (expense) of $(2,256), $1,371, and $3,452 (Note 8)	6,840		(4,203)		(10,525)
Total other comprehensive income (loss)	7,935		(5,700)		(9,388)

COMPREHENSIVE INCOME	643,879		564,352		548,425
Less: Comprehensive income attributable to noncontrolling interests	17,224		19,493		19,493

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	626,655	$	544,859	$	528,932

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,
	2021		2020
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	9,969	$	59,968
Customer and other receivables	391,923		313,576
Accrued unbilled revenues	133,980		132,197
Allowance for doubtful accounts (Note 2)	(25,354)		(19,782)
Materials and supplies (at average cost)	349,135		314,745
Fossil fuel (at average cost)	18,032		19,552

Income tax receivable (Note 5)	7,514		6,792
Assets from risk management activities (Note 16)	63,481		2,931
Deferred fuel and purchased power regulatory asset (Note 4)	388,148		175,835
Other regulatory assets (Note 4)	130,376		115,878
Other current assets	83,896		76,627
Total current assets	1,551,100		1,198,319
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 13 and 19)	1,294,757		1,138,435
Other special use funds (Notes 13 and 19)	358,410		254,509
Assets from risk management activities (Note 16)	46,908		1,818
Other assets	97,884		91,104
Total investments and other assets	1,797,959		1,485,866
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
Plant in service and held for future use	21,688,661		20,837,885
Accumulated depreciation and amortization	(7,504,603)		(7,110,310)
Net	14,184,058		13,727,575
Construction work in progress	1,329,478		937,384
Palo Verde sale leaseback, net of accumulated depreciation of $256,884 and $253,014 (Note 18)	94,166		98,036
Intangible assets, net of accumulated amortization of $737,694 and $698,500	273,693		282,570
Nuclear fuel, net of accumulated amortization of $133,122 and $137,207	106,039		113,645
Total property, plant and equipment	15,987,434		15,159,210
DEFERRED DEBITS
Regulatory assets (Notes 1, 4 and 5)	1,192,987		1,133,987
Operating lease right-of-use assets (Note 9)	890,057		505,064

Assets for pension and other postretirement benefits (Note 8)	545,723		502,992
Other	37,962		34,983
Total deferred debits	2,666,729		2,177,026
TOTAL ASSETS	$	22,003,222	$	20,020,421

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,
	2021		2020
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	393,083	$	318,585
Accrued taxes	168,645		159,551
Accrued interest	57,332		56,962
Common dividends payable	95,988		93,531
Short-term borrowings (Note 6)	292,000		169,000
Current maturities of long-term debt (Note 7)	150,000		—
Customer deposits	42,293		48,340
Liabilities from risk management activities (Note 16)	4,373		7,557
Liabilities for asset retirements (Note 12)	4,473		15,586

Operating lease liabilities (Note 9)	100,443		74,785
Regulatory liabilities (Note 4)	296,271		229,088
Other current liabilities	151,968		187,448
Total current liabilities	1,756,869		1,360,433
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7)	6,913,735		6,314,266
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 5)	2,311,862		2,135,403
Regulatory liabilities (Notes 1, 4, 5 and 8)	2,499,213		2,450,169
Liabilities for asset retirements (Note 12)	762,909		689,497
Liabilities for pension benefits (Note 8)	152,865		166,484
Liabilities from risk management activities (Note 16)	—		11,062
Customer advances	257,151		221,032
Coal mine reclamation	174,616		170,097
Deferred investment tax credit	186,570		191,372
Unrecognized tax benefits (Note 5)	4,657		5,834
Operating lease liabilities (Note 9)	728,401		361,336
Other	232,914		190,643
Total deferred credits and other	7,311,158		6,592,929
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 113,014,528 and 112,760,051 issued at respective dates	2,702,743		2,677,482
Treasury stock at cost; 87,608 shares at end of 2021 and 72,006 shares at end of 2020	(6,401)		(6,289)
Total common stock	2,696,342		2,671,193
Retained earnings	3,264,719		3,025,106
Accumulated other comprehensive loss (Note 20)	(54,861)		(62,796)
Total shareholders’ equity	5,906,200		5,633,503
Noncontrolling interests (Note 18)	115,260		119,290
Total equity	6,021,460		5,752,793
TOTAL LIABILITIES AND EQUITY	$	22,003,222	$	20,020,421

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)


	Year Ended December 31,
	2021		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	635,944	$	570,052	$	557,813
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	719,141		686,253		664,140
Deferred fuel and purchased power	(256,871)		(93,651)		(82,481)
Deferred fuel and purchased power amortization	44,557		(12,047)		49,508
Allowance for equity funds used during construction	(41,737)		(33,776)		(31,431)
Deferred income taxes	117,471		69,469		(1,479)
Deferred investment tax credit	(4,802)		(5,096)		(3,938)

Stock compensation	18,460		18,292		18,376
Changes in current assets and liabilities:
Customer and other receivables	(72,559)		(18,191)		(12,789)
Accrued unbilled revenues	(1,783)		(4,032)		9,005
Materials, supplies and fossil fuel	(32,870)		11,623		(51,826)
Income tax receivable	(722)		14,935		(21,727)
Other current assets	(22,720)		(30,640)		(3,507)
Accounts payable	20,267		(6,059)		50,641
Accrued taxes	9,094		14,652		(9,920)
Other current liabilities	(52,086)		22,520		(84,651)
Change in margin and collateral accounts — assets	(50)		404		(247)
Change in margin and collateral accounts — liabilities	350		100		(125)

Change in unrecognized tax benefits	(568)		2,220		2,704
Change in long-term regulatory liabilities	57,549		13,017		124,221
Change in other long-term assets	(246,473)		(67,453)		(82,895)
Change in other long-term liabilities	(29,578)		(186,227)		(132,666)
Net cash provided by operating activities	860,014		966,365		956,726
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,473,475)		(1,326,584)		(1,191,447)
Contributions in aid of construction	105,654		62,503		70,693
Allowance for borrowed funds used during construction	(21,052)		(18,530)		(18,528)
Proceeds from nuclear decommissioning trust sales and other special use funds	1,720,966		819,518		719,034
Investment in nuclear decommissioning trust and other special use funds	(1,725,480)		(822,608)		(722,181)
Other	6,458		7,883		11,452
Net cash used for investing activities	(1,386,929)		(1,277,818)		(1,130,977)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	746,999		1,596,672		1,092,188
Repayment of long-term debt	—		(915,150)		(600,000)
Short-term borrowings and (repayments) — net	142,000		73,325		54,275
Short-term debt borrowings under revolving credit facility	—		751,690		49,000
Short-term debt repayments under revolving credit facility	(19,000)		(770,690)		(65,000)
Dividends paid on common stock	(369,478)		(350,577)		(329,643)
Common stock equity issuance and purchases — net	(2,350)		(1,389)		692
Distributions to noncontrolling interests	(21,255)		(22,743)		(22,744)
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
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	59,968		10,283		5,766
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	9,969	$	59,968	$	10,283

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands, except per share amounts)


	Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
	Shares	Amount		Shares	Amount
Balance, December 31, 2018	112,159,896	$	2,634,265	(58,135)	$	(4,825)	$	2,641,183	$	(47,708)	$	125,790	$	5,348,705

Net income		—			—		538,320		—		19,493		557,813
Other comprehensive loss		—			—		—		(9,388)		—		(9,388)
Dividends on common stock ($3.04 per share)		—			—		(341,893)		—		—		(341,893)
Issuance of common stock	380,230	25,296			—		—		—		—		25,296
Purchase of treasury stock (a)		—		(121,493)	(11,202)		—		—		—		(11,202)
Reissuance of treasury stock for stock-based compensation and other		—		76,082	6,600		—		—		—		6,600
Capital activities by noncontrolling interests		—			—		—		—		(22,743)		(22,743)
Balance, December 31, 2019	112,540,126	2,659,561		(103,546)	(9,427)		2,837,610		(57,096)		122,540		5,553,188

Net income		—			—		550,559		—		19,493		570,052
Other comprehensive loss		—			—		—		(5,700)		—		(5,700)
Dividends on common stock ($3.23 per share)		—			—		(363,063)		—		—		(363,063)
Issuance of common stock	219,925	17,921			—		—		—		—		17,921
Purchase of treasury stock (a)		—		(81,256)	(7,181)		—		—		—		(7,181)
Reissuance of treasury stock for stock-based compensation and other		—		112,796	10,319		—		—		—		10,319
Capital activities by noncontrolling interests		—			—		—		—		(22,743)		(22,743)
Balance, December 31, 2020	112,760,051	2,677,482		(72,006)	(6,289)		3,025,106		(62,796)		119,290		5,752,793

Net income		—			—		618,720		—		17,224		635,944
Other comprehensive income		—			—		—		7,935		—		7,935
Dividends on common stock ($3.36 per share)		—			—		(379,108)		—		—		(379,108)
Issuance of common stock	254,477	25,261			—		—		—		—		25,261
Purchase of treasury stock (a)		—		(68,892)	(4,655)		—		—		—		(4,655)
Reissuance of treasury stock for stock-based compensation and other		—		53,290	4,543		—		—		—		4,543

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.

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

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(ARIZONA PUBLIC SERVICE COMPANY)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2021. The effectiveness of our internal control over financial reporting as of December 31, 2021, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.

February 25, 2022

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and the Board of Directors of

Arizona Public Service Company

Phoenix, Arizona

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, 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”). 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).

Basis for Opinions

Definition and Limitations of Internal Control over Financial Reporting

Critical Audit Matter

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.

How the Critical Audit Matter Was Addressed in the Audit

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. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; and the implementation of new rates as ordered by the ACC.
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 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.

◦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. For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.
We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery. We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, 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

Phoenix, Arizona

February 25, 2022

We have served as the Company’s auditor since 1932.

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)


	Year Ended December 31,
	2021		2020		2019

OPERATING REVENUES (Note 2)	$	3,803,835	$	3,586,982	$	3,471,209

OPERATING EXPENSES
Fuel and purchased power	1,152,551		993,419		1,042,237
Operations and maintenance	940,588		945,181		926,716
Depreciation and amortization	650,773		614,293		590,844
Taxes other than income taxes	234,569		224,790		218,540
Other expense	6,393		7,288		5,888
Total	2,984,874		2,784,971		2,784,225
OPERATING INCOME	818,961		802,011		686,984
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	41,737		33,776		31,431
Pension and other postretirement non-service credits — net (Note 8)	112,742		57,359		24,529
Other income (Note 17)	43,053		51,755		46,884
Other expense (Note 17)	(18,897)		(53,694)		(12,990)
Total	178,635		89,196		89,854
INTEREST EXPENSE
Interest charges	243,592		233,452		220,174
Allowance for borrowed funds used during construction (Note 1)	(21,052)		(18,530)		(18,528)
Total	222,540		214,922		201,646
INCOME BEFORE INCOME TAXES	775,056		676,285		575,192
INCOME TAXES (Note 5)	125,553		88,764		(9,572)
NET INCOME	649,503		587,521		584,764
Less: Net income attributable to noncontrolling interests (Note 18)	17,224		19,493		19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	632,279	$	568,028	$	565,271

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)


	Year Ended December 31,
	2021		2020		2019

NET INCOME	$	649,503	$	587,521	$	584,764

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
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)	18		592		1,137
Pension and other postretirement benefits activity, net of tax benefit (expense) of $(1,990), $1,955, and $3,136 (Note 8)	6,038		(5,970)		(9,552)
Total other comprehensive income (loss)	6,038		(5,396)		(8,415)

COMPREHENSIVE INCOME	655,541		582,125		576,349
Less: Comprehensive income attributable to noncontrolling interests	17,224		19,493		19,493

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	638,317	$	562,632	$	556,856

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,
	2021		2020
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
Plant in service and held for future use	$	21,685,200	$	20,834,424
Accumulated depreciation and amortization	(7,501,317)		(7,107,058)
Net	14,183,883		13,727,366
Construction work in progress	1,327,721		937,384
Palo Verde sale leaseback, net of accumulated depreciation of $256,884 and $253,014 (Note 18)	94,166		98,036
Intangible assets, net of accumulated amortization of $736,560 and $697,366	273,537		282,415
Nuclear fuel, net of accumulated amortization of $133,122 and $137,207	106,039		113,645
Total property, plant and equipment	15,985,346		15,158,846
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 13 and 19)	1,294,757		1,138,435
Other special use funds (Notes 13 and 19)	358,410		254,509
Assets from risk management activities (Note 16)	46,908		1,818
Other assets	42,440		44,192
Total investments and other assets	1,742,515		1,438,954
CURRENT ASSETS
Cash and cash equivalents	9,374		57,310
Customer and other receivables	390,533		312,644
Accrued unbilled revenues	133,980		132,197
Allowance for doubtful accounts (Note 2)	(25,354)		(19,782)
Materials and supplies (at average cost)	349,135		314,745
Fossil fuel (at average cost)	18,032		19,552
Income tax receivable (Note 5)	10,756		—
Assets from risk management activities (Note 16)	63,481		2,931
Deferred fuel and purchased power regulatory asset (Note 4)	388,148		175,835
Other regulatory assets (Note 4)	130,376		115,878

Other current assets	57,729		47,593
Total current assets	1,526,190		1,158,903
DEFERRED DEBITS
Regulatory assets (Notes 1, 4, and 5)	1,192,987		1,133,987
Operating lease right-of-use assets (Note 9)	888,207		503,475
Assets for pension and other postretirement benefits (Note 8)	537,092		495,673
Other	37,319		34,413
Total deferred debits	2,655,605		2,167,548
TOTAL ASSETS	$	21,909,656	$	19,924,251

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,
	2021		2020
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162	$	178,162
Additional paid-in capital	3,021,696		2,871,696
Retained earnings	3,470,235		3,216,955
Accumulated other comprehensive loss (Note 20)	(34,880)		(40,918)
Total shareholder equity	6,635,213		6,225,895
Noncontrolling interests (Note 18)	115,260		119,290
Total equity	6,750,473		6,345,185
Long-term debt less current maturities (Note 7)	6,266,693		5,817,945
Total capitalization	13,017,166		12,163,130
CURRENT LIABILITIES
Short-term borrowings (Note 6)	278,700		—

Accounts payable	389,365		311,699
Accrued taxes	152,012		148,970
Accrued interest	56,622		56,322
Common dividends payable	96,000		93,500
Customer deposits	42,293		48,340

Liabilities from risk management activities (Note 16)	4,373		7,557
Liabilities for asset retirements (Note 12)	4,473		15,586

Operating lease liabilities (Note 9)	100,199		74,695
Regulatory liabilities (Note 4)	296,271		229,088
Other current liabilities	145,286		190,420
Total current liabilities	1,565,594		1,176,177
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 5)	2,331,701		2,143,673
Regulatory liabilities (Notes 1, 4, 5 and 8)	2,499,213		2,450,169
Liabilities for asset retirements (Note 12)	762,909		689,497
Liabilities for pension benefits (Note 8)	138,328		148,943
Liabilities from risk management activities (Note 16)	—		11,062
Customer advances	257,151		221,032
Coal mine reclamation	174,616		170,097
Deferred investment tax credit	186,570		191,372
Unrecognized tax benefits (Note 5)	37,423		39,410
Operating lease liabilities (Note 9)	726,572		359,653
Other	212,413		160,036
Total deferred credits and other	7,326,896		6,584,944
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	21,909,656	$	19,924,251

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)


	Year Ended December 31,
	2021		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	649,503	$	587,521	$	584,764
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	719,039		686,168		664,055
Deferred fuel and purchased power	(256,871)		(93,651)		(82,481)
Deferred fuel and purchased power amortization	44,557		(12,047)		49,508
Allowance for equity funds used during construction	(41,737)		(33,776)		(31,431)
Deferred income taxes	128,852		36,462		48,367
Deferred investment tax credit	(4,802)		(5,096)		(3,938)

Changes in current assets and liabilities:
Customer and other receivables	(72,101)		(28,206)		(12,075)
Accrued unbilled revenues	(1,783)		(4,032)		9,005
Materials, supplies and fossil fuel	(32,870)		11,623		(51,826)
Income tax receivable	(10,756)		7,313		(7,313)
Other current assets	(25,587)		(24,669)		(1,461)
Accounts payable	23,510		(4,503)		53,258
Accrued taxes	3,042		12,642		(40,029)
Other current liabilities	(61,647)		29,587		(82,138)
Change in margin and collateral accounts — assets	(50)		404		(247)
Change in margin and collateral accounts — liabilities	350		100		(125)

Change in unrecognized tax benefits	(568)		2,220		2,704
Change in long-term regulatory liabilities	57,549		13,017		124,221
Change in other long-term assets	(231,804)		(65,139)		(85,725)
Change in other long-term liabilities	(20,272)		(186,871)		(129,682)
Net cash provided by operating activities	865,554		929,067		1,007,411
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,471,795)		(1,326,584)		(1,191,447)
Contributions in aid of construction	105,654		62,503		70,693
Allowance for borrowed funds used during construction	(21,052)		(18,530)		(18,528)
Proceeds from nuclear decommissioning trust sales and other special use funds	1,720,966		819,518		719,034
Investment in nuclear decommissioning trust and other special use funds	(1,725,480)		(822,608)		(722,181)
Other	273		(554)		6,336
Net cash used for investing activities	(1,391,434)		(1,286,255)		(1,136,093)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	446,999		1,099,722		1,092,188
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		—
Short-term debt repayments under revolving credit facility	—		(540,000)		—
Dividends paid on common stock	(376,500)		(357,500)		(336,300)
Equity infusion from Pinnacle West	150,000		150,000		—
Noncontrolling interests	(21,255)		(22,743)		(22,744)
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
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	57,310		10,169		5,707
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	9,374	$	57,310	$	10,169

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)


	Common Stock			Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
	Shares	Amount
Balance, December 31, 2018	71,264,947	$	178,162	$	2,721,696	$	2,788,256	$	(27,107)	$	125,790	$	5,786,797

Net income		—		—		565,271		—		19,493		584,764
Other comprehensive loss		—		—		—		(8,415)		—		(8,415)
Dividends on common stock		—		—		(341,600)		—		—		(341,600)

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
Other comprehensive loss		—		—		—		(5,396)		—		(5,396)
Dividends on common stock		—		—		(363,000)		—		—		(363,000)

Capital activities by noncontrolling interests		—		—		—		—		(22,743)		(22,743)
Balance, December 31, 2020	71,264,947	178,162		2,871,696		3,216,955		(40,918)		119,290		6,345,185

Equity infusion from Pinnacle West		—		150,000		—		—		—		150,000
Net income		—		—		632,279		—		17,224		649,503
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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings and is expected to continue to do so. El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company’s core expertise in the electric energy industry. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso’s 7% interest in Four Corners. See Note 11 for more information on 4CA matters.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and 4CA. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated.

We consolidate Variable Interest Entities (each a “VIE”) for which we are the primary beneficiary. We 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. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. 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.

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Accounting

APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.

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. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential Commission-ordered refunds to customers on regulatory liabilities.

See Note 4 for additional information.

Electric Revenues

Revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.

We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

See Notes 2 and 4 for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. See Note 2.

Property, Plant and Equipment

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. We report utility plant at its original cost, which includes:

material and labor;
contractor costs;
capitalized leases;
construction overhead costs (where applicable); and
AFUDC.

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):


Property, Plant and Equipment:	2021		2020
Generation	$	9,480,572	$	9,199,012
Transmission	3,402,016		3,290,477
Distribution	7,520,016		7,107,007
General plant	1,286,057		1,241,389
Plant in service and held for future use	21,688,661		20,837,885
Accumulated depreciation and amortization	(7,504,603)		(7,110,310)
Net	14,184,058		13,727,575
Construction work in progress	1,329,478		937,384
Palo Verde sale leaseback, net of accumulated depreciation	94,166		98,036
Intangible assets, net of accumulated amortization	273,693		282,570
Nuclear fuel, net of accumulated amortization	106,039		113,645
Total property, plant and equipment	$	15,987,434	$	15,159,210

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

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12 for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for AROs. APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.

We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2021, were as follows:

Steam generation — 12 years;
Nuclear plant — 25 years;
Other generation — 19 years;
Transmission — 37 years;
Distribution — 33 years; and
General plant — 7 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $575 million in 2021, $553 million in 2020, and $522 million in 2019. For the years 2019 through 2021, the depreciation rates ranged from a low of 1.37% to a high of 12.15%. The weighted-average depreciation rate was 2.87% in 2021, 2.84% in 2020, and 2.81% in 2019.

Asset Retirement Obligations

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 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 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.

See Note 12 for further information on Asset Retirement Obligations.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

AFUDC was calculated by using a composite rate of 6.75% 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.

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

Materials and Supplies

APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

Fair Value Measurements

We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost. See Note 7 for additional information.

Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

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

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.

See Note 13 for additional information about fair value measurements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options, and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. 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 expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Note 16 for additional information about our derivative instruments.

Loss Contingencies and Environmental Liabilities

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred, and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries, in addition to a non-qualified pension plan. We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 8 for additional information on pension and other postretirement benefits.

Nuclear Fuel

APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero. In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2022. See Note 11 for information on spent nuclear fuel disposal costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates. We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 5 for additional discussion.

Cash and Cash Equivalents

We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.

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


	Year ended December 31,
	2021		2020		2019
Cash paid (received) during the period for:
Income taxes, net of refunds	$	229	$	(3,019)	$	12,535
Interest, net of amounts capitalized	227,584		216,951		218,664
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	167,733	$	113,502	$	141,297
Dividends declared but not paid	95,988		93,531		87,982

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


	Year ended December 31,
	2021		2020		2019
Cash paid (received) during the period for:
Income taxes, net of refunds	$	19,783	$	41,176	$	(15,042)
Interest, net of amounts capitalized	217,749		206,328		204,261
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	167,657	$	113,502	$	141,297
Dividends declared but not paid	96,000		93,500		88,000

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $80 million in 2021, $70 million in 2020, and $66 million in 2019. Estimated amortization expense on existing intangible assets over the next five years is $75 million in 2022, $63 million in 2023, $44 million in 2024, $33 million in 2025, and $27 million in 2026. At December 31, 2021, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

El Dorado holds investments in both debt and equity securities. Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

BCE holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

Our investments in the nuclear decommissioning trusts, coal reclamation escrow accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 13 and 19 for more information on these investments.

Leases

We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. 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 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. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.

APS enters into purchased power contracts that may contain leases. This occurs when a purchased power agreement designates a specific power plant, APS obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. 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. See Note 4. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 9 for information on our lease agreements.

Business Segments

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

Preferred Stock

At December 31, 2021, 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.

2. Revenue

Sources of Revenue

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


	Year Ended December 31,		Year Ended December 31,			Year Ended December 31,
	2021		2020			2019
Retail Electric Service
Residential	$	1,913,324	$	1,929,178	(a)	$	1,761,122
Non-Residential	1,586,940		1,486,098			1,509,514
Wholesale Energy Sales	187,640		93,345			121,805
Transmission Services for Others	99,285		65,859			62,460
Other Sources	16,646		12,502			16,308
Total Operating Revenues	$	3,803,835	$	3,586,982		$	3,471,209

(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 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. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 21 days of when the services are billed. 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. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.

Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. 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. For the year ended December 31, 2021, 2020 and 2019, our revenues that do not qualify as revenue from contracts with customers were $44 million, $54 million and $56 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Consolidated Balance Sheets as of December 31, 2021, and 2020.

Allowance for Doubtful Accounts

On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment. The suspension of customer disconnections was extended from March 13, 2020, through December 31, 2020. 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. 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.

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
Allowance for doubtful accounts, balance at beginning of period	$	19,782	$	8,171	$	4,069
Bad debt expense	22,251		20,633		11,819
Actual write-offs	(16,679)		(9,022)		(7,717)
Allowance for doubtful accounts, balance at end of period	$	25,354	$	19,782	$	8,171

3. New Accounting Standards

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.

4. Regulatory Matters

COVID-19 Pandemic

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. APS refunded

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. The proposed total annual revenue increase in APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS’s application were:

a test year comprised of 12 months ended June 30, 2019, adjusted as described below;
an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
the following proposed capital structure and costs of capital:

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Capital Structure		Cost of Capital
Long-term debt	45.3	%	4.10	%
Common stock equity	54.7	%	10.15	%
Weighted-average cost of capital			7.41	%

a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);
authorization to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
a number of proposed rate and program changes for residential customers, including:

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

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

▪a flat bill/subscription rate pilot program;

proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;
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); and
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 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 through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials. In 2021, APS committed an additional $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. to 8 p.m. to 4 p.m. to 7 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.

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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 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: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules.

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

an authorized return on common equity of 10.0%;
a capital structure comprised of 44.2% debt and 55.8% common equity;
a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;
a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at Four Corners;
a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;
an expansion of the PSA to include certain environmental chemical costs and third-party energy storage costs;
a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation (“DG”) with the purpose of expanding access to rooftop solar for low- and moderate-income Arizonans, recoverable through the RES, to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs;
an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;
rate design changes, including:

▪a change in the on-peak time-of-use period from noon to 7 p.m. to 3 p.m. to 8 p.m. Monday through Friday, excluding holidays;

▪non-grandfathered DG customers would be required to select a rate option that has time-of-use rates and either a new grid access charge or demand component;

▪a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and

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.

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.

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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.

Cost Recovery Mechanisms

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

Renewable Energy Standard**.** In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas, and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES.

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2020. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2020. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 DSM Plan.

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2021. In the 2021 RES Implementation Plan, APS requested $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020. On June 7, 2021, the ACC approved the 2021 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2021. As part of the approval, the ACC approved the requested budget and authorized APS to collect $68.3 million through the Renewable Energy Adjustment Charge to support APS’s RES programs.

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

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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 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 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. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels but kept the overall budget at $52.6 million.

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.

On December 31, 2019, APS filed its 2020 DSM Plan, which requested a budget of $51.9 million and continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for

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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. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
the PSA rate includes (a) a “forward component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “historical component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “transition component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

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The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2021 and 2020 (dollars in thousands):


	Twelve Months Ended December 31,
	2021		2020
Beginning balance	$	175,835	$	70,137
Deferred fuel and purchased power costs — current period	256,871		93,651
Amounts refunded/(charged) to customers	(44,558)		12,047
Ending balance	$	388,148	$	175,835

The PSA rate for the PSA year beginning February 1, 2019, was $0.001658 per kWh, as compared to the $0.004555 per kWh for the prior year. This rate was comprised of a forward component of $0.000536 per kWh and a historical component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019.

On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. 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. These rates went into effect as filed on February 1, 2020.

On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh, which consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. This left $215.9 million of fuel and purchased power costs above this annual cap which will be reflected in 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 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 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, 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**.** In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the settlement agreement entered into in 2012 regarding APS’s rate case (“2012 Settlement Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. 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 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. 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, 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, 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.

Lost Fixed Cost Recovery Mechanism**.** The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement. The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential and 2.68 cents 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. The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. DG sales losses are determined from the metered output from the DG units.

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). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. 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

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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. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On August 13, 2018, APS filed a request with the ACC that addressed the return of $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers (“TEAM Phase II”). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020.

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

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

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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.

Net Metering

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. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS’s subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS’s 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;
customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

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

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. The new rate rider became effective on October 1, 2019. APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020. This price reflects the 10% annual reduction discussed above. On September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021. In accordance with this decision, the RCP export energy price of 9.4 cents per kWh became effective on October 1, 2021.

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

Subpoena from Former Arizona Corporation Commissioner Robert Burns

On August 25, 2016, then-Commissioner Robert Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

After various proceedings between September 2016 and March 2020, at which time Burns’ appeal of a prior dismissal by the trial court was pending before the Arizona Court of Appeals, Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. On March 4, 2021, the Court of Appeals found Burns’ motion to be moot because the Court of Appeals had issued an opinion deciding the matter that same day.

In its March 4, 2021, opinion, the Court of Appeals affirmed the trial court’s dismissal of Burns’ complaint, concluding that Burns could not overturn the ACC’s 4-1 vote refusing to enforce his subpoenas. On May 15, 2021, Burns filed a petition for review with the Arizona Supreme Court asking for reversal of the Court of Appeals opinion and the trial court’s judgment. APS and the ACC filed responses to Burns’ petition on July 14, 2021, requesting that the petition be denied. The Arizona Supreme Court granted Burns' petition and oral argument is scheduled for March 8, 2022. Pinnacle West and APS cannot predict the outcome of this matter.

Energy Modernization Plan

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Integrated Resource Planning

ACC rules require utilities to develop 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020. On February 20, 2020, the ACC extended the deadline for all utilities to file their IRPs from April 1, 2020, to June 26, 2020. On June 26, 2020, APS filed its final IRP. On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021. In February 2022, the ACC acknowledged APS’s IRP. 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.

Public Utility Regulatory Policies Act

Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens. On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona and established that the rate paid to qualifying facilities must be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. 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.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills. On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period June 1 through October 15 (“Summer Disconnection Moratorium”). During the Summer Disconnection Moratorium, APS could not

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff and ACC proposed draft amendments to the customer service disconnections rules. On April 14, 2021, the ACC voted to send to the formal rulemaking process a draft rules package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar method (June 1 – October 15) for disconnection moratoriums. On November 2, 2021, the ACC approved the final rules, and on November 23, 2021, the rules were submitted to the Arizona Office of the Attorney General for final review and approval. 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. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and APS’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019, and November 14, 2019. By the middle of May 2020, APS provided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided did not have a material impact on APS’s financial statements. In February 2020, APS launched a new online rate comparison tool. The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is working as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict whether additional inquiries or actions may be taken by the ACC.

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, approximately $24 million of which has been returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

Four Corners SCR Cost Recovery

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS filed the SCR Adjustment request in April 2018. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019. The

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. 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 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. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($41.8 million as of December 31, 2021), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.

Navajo Plant

The Navajo Plant ceased operations in November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allows for decommissioning activities to begin after the plant ceased operations. In accordance with GAAP, in the second quarter of 2017, APS’s remaining

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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


S		December 31, 2021				December 31, 2020
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	509,751	$	—	$	469,953
Deferred fuel and purchased power (b) (c)	2022	388,148		—		175,835		—
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
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
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
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
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		—
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 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.

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

(c)Subject to a carrying charge.

(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


		December 31, 2021				December 31, 2020
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)	2046	$	40,903	$	971,545	$	41,330	$	1,012,583
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)	2058	7,239		221,877		7,240		229,147
Asset retirement obligations	2057	—		614,683		—		506,049
Other postretirement benefits	(d)	37,789		337,027		37,705		349,588
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
Four Corners coal reclamation	2038	2,316		53,076		5,460		49,435
Spent nuclear fuel	2027	6,701		38,581		6,768		44,221
Income taxes — deferred investment tax credit	2056	2,264		47,337		2,231		48,648
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
Demand side management (b)	2022	—		5,417		10,819		—
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
Active union medical trust	N/A	—		—		—		6,057
Other	Various	210		41		409		189
Total regulatory liabilities		$	296,271	$	2,499,213	$	229,088	$	2,450,169

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

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

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

(d)See Note 8.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy. The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. 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 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. On March 13, 2019, the ACC approved the Company’s proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. 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 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 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.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 18 for additional details related to the Palo Verde sale leaseback VIEs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Pinnacle West Consolidated						APS Consolidated
	2021		2020		2019		2021		2020		2019
Total unrecognized tax benefits, January 1	$	45,655	$	43,435	$	40,731	$	45,655	$	43,435	$	40,731
Additions for tax positions of the current year	3,305		3,418		3,373		3,305		3,418		3,373
Additions for tax positions of prior years	1,449		1,431		1,843		1,449		1,431		1,843
Reductions for tax positions of prior years for:
Changes in judgment	(2,659)		(1,965)		(2,078)		(2,659)		(1,965)		(2,078)
Settlements with taxing authorities	—		—		—		—		—		—
Lapses of applicable statute of limitations	(2,664)		(664)		(434)		(2,664)		(664)		(434)
Total unrecognized tax benefits, December 31	$	45,086	$	45,655	$	43,435	$	45,086	$	45,655	$	43,435

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


	Pinnacle West Consolidated						APS Consolidated
	2021		2020		2019		2021		2020		2019
Tax positions, that if recognized, would decrease our effective tax rate	$	26,300	$	25,714	$	22,813	$	26,300	$	25,714	$	22,813

As of the balance sheet date, the tax year ended December 31, 2018, and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2017.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense. The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):


	Pinnacle West Consolidated						APS Consolidated
	2021		2020		2019		2021		2020		2019
Unrecognized tax benefit interest expense/(benefit) recognized	$	(535)	$	266	$	459	$	(535)	$	266	$	459

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):


	Pinnacle West Consolidated						APS Consolidated
	2021		2020		2019		2021		2020		2019
Unrecognized tax benefit interest accrued	$	1,320	$	1,855	$	1,589	$	1,320	$	1,855	$	1,589

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Pinnacle West Consolidated						APS Consolidated
	Year Ended December 31,						Year Ended December 31,
	2021		2020		2019		2021		2020		2019
Current:
Federal	$	(5,041)	$	11,869	$	(13,551)	$	1,514	$	57,299	$	(54,697)
State	2,458		1,932		3,195		(11)		99		695
Total current	(2,583)		13,801		(10,356)		1,503		57,398		(54,002)
Deferred:
Federal	95,327		53,398		(14,982)		101,175		15,122		29,321
State	17,342		10,974		9,565		22,875		16,244		15,109
Total deferred	112,669		64,372		(5,417)		124,050		31,366		44,430
Income tax expense/(benefit)	$	110,086	$	78,173	$	(15,773)	$	125,553	$	88,764	$	(9,572)

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



	Pinnacle West Consolidated						APS Consolidated
	Year Ended December 31,						Year Ended December 31,
	2021		2020		2019		2021		2020		2019
Federal income tax expense at statutory rate	$	156,666	$	136,127	$	113,828	$	162,762	$	142,020	$	120,790
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	22,656		19,146		18,599		23,339		20,124		19,267
State income tax credits net of federal income tax benefit	(7,015)		(8,951)		(8,519)		(5,277)		(7,213)		(6,781)
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)
Allowance for equity funds used during construction (see Note 1)	(4,180)		(2,747)		(2,476)		(4,180)		(2,747)		(2,476)
Palo Verde VIE noncontrolling interest (see Note 18)	(3,617)		(4,094)		(4,094)		(3,617)		(4,094)		(4,094)
Investment tax credit amortization	(7,620)		(7,510)		(6,851)		(7,620)		(7,510)		(6,851)
Other	(4,331)		(3,255)		(2,178)		(3,296)		(1,273)		(5,345)
Income tax expense/(benefit)	$	110,086	$	78,173	$	(15,773)	$	125,553	$	88,764	$	(9,572)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Pinnacle West Consolidated				APS Consolidated
	December 31,				December 31,
	2021		2020		2021		2020
DEFERRED TAX ASSETS
Risk management activities	$	677	$	4,287	$	677	$	4,287
Regulatory liabilities:
Excess deferred income taxes — Tax Cuts and Jobs Act	306,915		319,091		306,915		319,091
Asset retirement obligation and removal costs	174,952		157,470		174,952		157,470
Unamortized investment tax credits	49,601		50,879		49,601		50,879
Other postretirement benefits	92,654		95,778		92,654		95,778
Other	65,815		43,551		65,815		43,551
Operating lease liabilities	204,890		107,853		204,378		107,414
Pension liabilities	42,136		45,853		37,814		40,168
Coal reclamation liabilities	43,165		42,065		43,165		42,065
Renewable energy incentives	22,646		25,355		22,646		25,355
Credit and loss carryforwards	57,077		26,460		18,902		8,034
Other	74,184		78,113		74,184		78,113
Total deferred tax assets	1,134,712		996,755		1,091,703		972,205
DEFERRED TAX LIABILITIES
Plant-related	(2,570,613)		(2,489,899)		(2,570,613)		(2,489,899)
Risk management activities	(27,276)		(1,174)		(27,276)		(1,174)
Pension and other postretirement assets	(133,624)		(123,462)		(132,769)		(122,580)
Other special use funds	(64,610)		(42,927)		(64,610)		(42,927)
Operating lease right-of-use assets	(204,890)		(107,853)		(204,378)		(107,414)
Regulatory assets:
Allowance for equity funds used during construction	(42,616)		(41,038)		(42,616)		(41,038)
Deferred fuel and purchased power	(96,033)		(47,673)		(96,033)		(47,673)
Pension benefits	(126,010)		(116,219)		(126,010)		(116,219)
Retired power plant costs	(28,389)		(35,214)		(28,389)		(35,214)
Other	(123,902)		(106,227)		(123,902)		(106,227)
Other	(28,611)		(20,472)		(6,808)		(5,513)
Total deferred tax liabilities	(3,446,574)		(3,132,158)		(3,423,404)		(3,115,878)
Deferred income taxes — net	$	(2,311,862)	$	(2,135,403)	$	(2,331,701)	$	(2,143,673)

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, 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. APS

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

6. Lines of Credit and Short-Term Borrowings

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

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


	December 31, 2021						December 31, 2020
	Pinnacle West		APS		Total		Pinnacle West		APS		Total
Commitments under Credit Facilities	$	200,000	$	1,000,000	$	1,200,000	$	231,000	$	1,000,000	$	1,231,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings	(13,300)		(278,700)		(292,000)		(169,000)		—		(169,000)
Amount of Credit Facilities Available	$	186,700	$	721,300	$	908,000	$	62,000	$	1,000,000	$	1,062,000

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 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 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.

APS

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

On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power). See Note 7 for additional long-term debt provisions.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Long-Term Debt and Liquidity Matters

All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding (dollars in thousands):


	Maturity	Interest	December 31,
	Dates (a)	Rates	2021		2020
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975	$	35,975

Total pollution control bonds			35,975		35,975
Senior unsecured notes	2024-2050	2.20%-6.88%	6,280,000		5,830,000

Unamortized discount			(14,995)		(15,900)
Unamortized premium			13,575		14,781
Unamortized debt issuance cost			(47,862)		(46,911)
Total APS long-term debt			6,266,693		5,817,945
Less current maturities			—		—
Total APS long-term debt less current maturities			6,266,693		5,817,945
Pinnacle West
Senior unsecured notes	2025	1.3%	500,000		500,000
Term loans	2022-2024	(c)	300,000		—
Unamortized discount			(34)		(44)
Unamortized debt issuance cost			(2,924)		(3,635)

Total Pinnacle West long-term debt			797,042		496,321
Less current maturities			150,000		—
Total Pinnacle West long-term debt less current maturities			647,042		496,321
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	6,913,735	$	6,314,266

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

(b) The weighted-average rate for the variable rate pollution control bonds was 0.22% at December 31, 2021, and 0.18% at December 31, 2020.

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


Year	Consolidated Pinnacle West		Consolidated APS
2022	$	150,000	$	—
2023	—		—
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

Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):


	As of December 31, 2021				As of December 31, 2020
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	797,042	$	792,735	$	496,321	$	509,050
APS	6,266,693		6,933,619		5,817,945		7,103,791
Total	$	7,063,735	$	7,726,354	$	6,314,266	$	7,612,841

Credit Facilities and Debt Issuances

Pinnacle West

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. The proceeds were received on January 4, 2021, and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021. On January 6, 2022, Pinnacle West repaid this term loan facility early.

APS

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.

BCE

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

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2021, the ratio was approximately 56% for Pinnacle West and 50% for APS. Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s long-term debt authorization from $5.9 billion to $7.5 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. See Note 6 for additional short-term debt provisions.

8. Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. 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. These plans provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

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

Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. Prior to 2020, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00% (see weighted-average assumption table below). This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of investment assets from the other postretirement benefit plan into the Active Union Employee Medical Account Trust. The Active Union Employee Medical Account is an existing trust account that holds investments restricted for paying active union employee medical costs. See Note 19. The transfer of other postretirement benefit plan investment assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of investment assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and are recoverable in rates. 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. See Note 4.

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):


	Pension Plans						Other Benefits Plans
	2021		2020		2019		2021		2020		2019
Service cost-benefits earned during the period	$	61,236	$	56,233	$	49,902	$	17,796	$	22,236	$	18,369
Non-service costs (credits):
Interest cost on benefit obligation	98,566		118,567		136,843		16,513		25,857		29,894
Expected return on plan assets	(202,628)		(187,443)		(171,884)		(41,444)		(40,077)		(38,412)
Amortization of:
Prior service credit	—		—		—		(37,705)		(37,575)		(37,821)
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)
Portion of cost/(benefit) charged to expense	$	(32,743)	$	3,386	$	30,312	$	(38,657)	$	(20,966)	$	(19,859)

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


	Pension Plans				Other Benefits Plans
	2021		2020		2021		2020
Change in Benefit Obligation
Benefit obligation at January 1	$	3,902,867	$	3,613,114	$	624,034	$	746,924
Service cost	61,236		56,233		17,796		22,236
Interest cost	98,566		118,567		16,513		25,857
Benefit payments	(207,928)		(191,704)		(31,280)		(31,511)
Actuarial (gain) loss	(137,917)		306,657		(35,222)		(139,472)
Benefit obligation at December 31	3,716,824		3,902,867		591,841		624,034
Change in Plan Assets
Fair value of plan assets at January 1	3,886,544		3,318,351		961,165		837,494
Actual return on plan assets	18,169		642,373		41,432		150,076
Employer contributions	100,000		100,000		—		—
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
Funded Status at December 31	$	95,217	$	(16,323)	$	280,594	$	337,131

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


	As of December 31,
	2021	2020
Accumulated benefit obligation	161,086	171,672
Fair value of plan assets	—	—

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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


	As of December 31,
	2021	2020
Projected benefit obligation	169,912	182,184
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, 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):


	Pension Plans				Other Benefits Plans
	2021		2020		2021		2020
Noncurrent asset	$	265,129	$	165,861	$	280,594	$	337,131
Current liability	(17,047)		(15,700)		—		—
Noncurrent liability	(152,865)		(166,484)		—		—
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
	2021		2020		2021		2020
Net actuarial loss (gain)	$	582,895	$	552,301	$	(262,352)	$	(237,233)
Prior service credit	—		—		(114,632)		(152,337)
APS’s portion recorded as a regulatory (asset) liability	(509,751)		(469,953)		374,816		387,293
Income tax expense (benefit)	(18,081)		(20,364)		990		1,018
Accumulated other comprehensive loss (gain)	$	55,063	$	61,984	$	(1,178)	$	(1,259)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:


	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2021		2020		2021		2020		2019
Discount rate – pension plans	2.92	%	2.53	%	2.53	%	3.30	%	4.34	%
Discount rate – other benefits plans	2.98	%	2.63	%	2.63	%	3.42	%	4.39	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets - pension plans	N/A		N/A		5.30	%	5.75	%	6.25	%
Expected long-term return on plan assets - other benefit plans	N/A		N/A		4.90	%	4.85	%	5.40	%
Initial healthcare cost trend rate (pre-65 participants)	6.00	%	6.50	%	6.50	%	7.00	%	7.00	%
Ultimate healthcare cost trend rate (pre-65 participants)	4.75	%	4.75	%	4.75	%	4.75	%	4.75	%
Number of years to ultimate trend rate (pre-65 participants)	4		5		4		5		7
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)	2.00	%	2.00	%	2.00	%	4.75	%	4.75	%

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

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

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2022, we are assuming a 5.00% long-term rate of return for pension assets and 5.50% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.

Plan Assets

The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.

The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments may include investments in real estate, private equity and various other strategies. The plan may also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts, and mutual funds.

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


	Target Allocation		Actual Allocation
Long-term fixed income assets	80	%	79	%
Return-generating assets	20	%	21	%
Total	100	%	100	%

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

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


	Target Allocation
Equities in US and other developed markets	12	%
Equities in emerging markets	4	%
Alternative investments	4	%
Total	20	%

The pension plan IPS does not provide for a specific mix of long-term fixed income assets but does expect the average credit quality of such assets to be investment grade.

As of December 31, 2021, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2021:


	Actual Allocation
Long-term fixed income assets	63	%
Return-generating assets	37	%
Total	100	%

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

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. U.S. Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity, and credit quality. These instruments are classified as Level 2.

Mutual funds, partnerships, and common and collective trusts are valued utilizing a Net Asset Value (NAV) concept or its equivalent. Mutual funds, which includes exchange traded funds (ETFs), are classified as Level 1, and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). The trust’s shares are offered to a limited group of investors and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2021, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships’ underlying assets. The plan’s partnerships holdings relate to investments in high-yield fixed income instruments. Certain partnerships also include funding commitments that may require the plan to contribute up to $50 million to these partnerships; as of December 31, 2021, approximately $38 million of these commitments have been funded.

The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2021, by asset category, are as follows (dollars in thousands):


	Level 1		Level 2		Other (a)		Total
Pension Plan:
Cash and cash equivalents	$	821	$	—	$	—	$	821
Fixed income securities:
Corporate	—		1,765,623		—		1,765,623
U.S. Treasury	1,008,211		—		—		1,008,211
Other (b)	—		165,496		—		165,496
Common stock equities (c)	209,063		—		—		209,063
Mutual funds (d)	132,656		—		—		132,656
Common and collective trusts:
Equities	—		—		255,141		255,141
Real estate	—		—		173,197		173,197
Partnerships	—		—		15,730		15,730
Short-term investments and other (e)	—		—		86,103		86,103
Total	$	1,350,751	$	1,931,119	$	530,171	$	3,812,041
Other Benefits:
Cash and cash equivalents	$	121	$	—	$	—	$	121
Fixed income securities:
Corporate	—		244,572		—		244,572
U.S. Treasury	287,057		—		—		287,057
Other (b)	—		9,330		—		9,330
Common stock equities (c)	176,024		—		—		176,024
Mutual funds (d)	26,262		—		—		26,262
Common and collective trusts:
Equities	—		—		96,547		96,547
Real estate	—		—		23,851		23,851
Short-term investments and other (e)	2,517		—		6,154		8,671
Total	$	491,981	$	253,902	$	126,552	$	872,435

(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 and asset backed securities.

(c)This category primarily consists of U.S. common stock equities.

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

(e)This category includes plan receivables and payables.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2020, by asset category, are as follows (dollars in thousands):


	Level 1		Level 2		Other (a)		Total
Pension Plan:
Cash and cash equivalents	$	9,911	$	—	$	—	$	9,911
Fixed income securities:
Corporate	—		1,684,782		—		1,684,782
U.S. Treasury	794,571		—		—		794,571
Other (b)	—		112,224		—		112,224
Common stock equities (c)	331,058		—		—		331,058
Mutual funds (d)	262,765		—		—		262,765
Common and collective trusts:
Equities	—		—		407,522		407,522
Real estate	—		—		191,595		191,595
Partnerships	—		—		22,420		22,420
Short-term investments and other (e)	—		—		69,696		69,696
Total	$	1,398,305	$	1,797,006	$	691,233	$	3,886,544
Other Benefits:
Cash and cash equivalents	$	1,909	$	—	$	—	$	1,909
Fixed income securities:
Corporate	—		221,488		—		221,488
U.S. Treasury	258,102		—		—		258,102
Other (b)	—		8,316		—		8,316
Common stock equities (c)	175,605		—		—		175,605
Mutual funds (d)	34,310		—		—		34,310
Common and collective trusts:
Equities	—		—		94,674		94,674
Real estate	—		—		19,778		19,778
Short-term investments and other (e)	142,995		—		3,988		146,983
Total	$	612,921	$	229,804	$	118,440	$	961,165

(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.

(c)This category primarily consists of U.S. common stock equities.

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

(e)This category includes plan receivables and payables.

Contributions

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

$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

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):


Year	Pension Plans		Other Benefits Plans
2022	$	220,549	$	31,244
2023	219,132		31,658
2024	221,724		31,486
2025	222,356		30,988
2026	221,709		30,780
Years 2027-2031	1,121,557		151,194

Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2021, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $12 million for 2021, $11 million for 2020, and $11 million for 2019.

9. Leases

We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2022 through 2050. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. See Note 18 for a discussion of VIEs.

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 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. These purchased power lease contracts are accounted for as operating leases. The contracts do not contain purchase options or term extension options. In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset. The variable consideration is not included in the measurement of our lease obligation.

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


	For the Year Ended December 31,
	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. The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the generation source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	December 31, 2021
Year	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
2022	$	103,752	$	13,051	$	116,803
2023	106,151		10,758		116,909
2024	104,315		8,073		112,388
2025	106,582		6,034		112,616
2026	120,016		4,803		124,819
Thereafter	299,594		35,289		334,883
Total lease commitments	840,410		78,008		918,418
Less imputed interest	72,249		17,325		89,574
Total lease liabilities	$	768,161	$	60,683	$	828,844

We recognize lease assets and liabilities upon lease commencement. 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):


	Year Ended 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:	$	116,661	$	75,097	$	69,075
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	500,582		441,653		11,262


	December 31, 2021		December 31, 2020
Weighted average remaining lease term	8 years		6 years
Weighted average discount rate (a)	2.13	%	1.69	%

(a)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Jointly-Owned Facilities

APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2021 (dollars in thousands):


	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,932,629	$	1,113,905	$	28,288
Palo Verde Unit 2 (a)	16.8	%		657,102		384,193		14,084
Palo Verde Common	28.0	%	(b)	792,849		334,804		43,690
Palo Verde Sale Leaseback			(a)	351,050		256,884		—
Four Corners Generating Station	63.0	%		1,686,702		608,247		21,515
Cholla Common Facilities (c)	50.5	%		208,709		121,877		1,608
Transmission facilities:
ANPP 500kV System	33.5	%	(b)	133,289		53,708		115
Navajo Southern System	26.8	%	(b)	89,895		35,144		1,535
Palo Verde — Yuma 500kV System	25.8	%	(b)	23,650		7,188		716
Four Corners Switchyards	60.1	%	(b)	73,133		18,637		258
Phoenix — Mead System	17.1	%	(b)	39,523		20,150		—
Palo Verde — Rudd 500kV System	50.0	%		96,376		29,426		—
Morgan — Pinnacle Peak System	64.7	%	(b)	119,814		23,575		138
Round Valley System	50.0	%		535		180		—
Palo Verde — Morgan System	87.8	%	(b)	259,180		27,995		268
Hassayampa — North Gila System	80.0	%		148,039		19,317		—
Cholla 500kV Switchyard	85.7	%		8,287		2,163		5
Saguaro 500kV Switchyard	60.0	%		21,655		13,471		—
Kyrene — Knox System	50.0	%		578		328		—

(a)See Note 18.

(b)Weighted-average of interests.

(c)PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information), and APS operated the unit for PacifiCorp. Cholla Unit 4 was retired on December 24, 2020. The common facilities at Cholla are jointly-owned.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. Commitments and Contingencies

Palo Verde Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against DOE in the United States Court of Federal Claims (“Court of Federal Claims”). 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 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 1, 2021, APS filed its eighth 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 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. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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.

Fuel and Purchased Power Commitments and Purchase Obligations

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 $1 billion in 2022; $765 million in 2023; $703 million in 2024; $686 million in 2025; $687 million in 2026; and $6.9 billion thereafter. 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.

Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions. The current coal contracts with take-or-pay provisions have terms expiring through 2031.

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


	Years Ended December 31,
	2022		2023		2024		2025		2026		Thereafter
Coal take-or-pay commitments (a)	$	202,917	$	201,826	$	203,638	$	194,192	$	195,121	$	925,644

(a)Total take-or-pay commitments are approximately $1.9 billion. The total net present value of these commitments is approximately $1.5 billion.

APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):


	Years Ended December 31,
	2021		2020		2019
Total purchases	$	219,958	$	189,817	$	204,888

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $32 million in 2022; $30 million in 2023; $29 million in 2024; $26 million in 2025; $22 million in 2026; and $87 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy.

Coal Mine Reclamation Obligations

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. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $175 million at December 31, 2021, and $170 million at December 31, 2020. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $17 million in 2022; $18 million in 2023; $19 million in 2024; $20 million in 2025; $21 million in 2026; and $48 million thereafter. 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

The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water, or air. Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (“PRPs”). PRPs may be strictly, jointly, and severally liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). 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. 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. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

state governmental investigation into groundwater contamination in this area, on January 25, 2015, the ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery. APS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Arizona Attorney General Matter

APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, approximately $24 million of which was returned to customers as restitution.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$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 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. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.

Regional Haze Rules. APS has received the final rulemaking imposing pollution control requirements on Four Corners. EPA required the plant to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plant.

Based on EPA’s final standards, APS’s 63% share of the cost of required controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred. In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC purchased the interest from 4CA on July 3, 2018. See “Four Corners — 4CA Matter” below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset.

Coal Combustion Waste**.** On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of recent regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. 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:

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.
On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019, to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.
Based on an August 21, 2018, D.C. 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 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. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s July 29, 2020, final regulation adopted this proposal and now requires explicit EPA approval for facilities to utilize an alternative closure deadline. With respect to the Cholla facility, APS’s application for alternative closure (which would allow the continued disposal of CCR within the facility’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025) was submitted to EPA on November 30, 2020, and is currently pending. 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. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment process, we cannot predict any ultimate impacts to the Company; however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations or cash flows.

Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and such rules would have had far broader impact on the electric power sector than the ACE regulations. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to EPA to develop new existing power plant carbon regulations consistent with the court’s ruling. That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP. 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. 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 or ongoing litigation related to the scope of EPA’s authority under the Clean Air Act to regulate carbon emissions from existing power plants.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement but cannot predict whether it would obtain such recovery.

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

The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019, filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit. 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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.

Four Corners

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC purchased this 7% interest on July 3, 2018, from 4CA. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. 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, 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. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the note.

In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. 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. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2021. 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. 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 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, 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 February 11, 2022, Pinnacle West has guaranteed the full amount of the equity bridge loan under the credit facility. See Note 7 for additional details.

12. 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.

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


	2021		2020
Asset retirement obligations at the beginning of year	$	705,083	$	657,218
Changes attributable to:
Accretion expense	38,437		38,652
Settlements	(4,111)		(9,710)

Estimated cash flow revisions	27,973		18,923
Asset retirement obligations at the end of year	$	767,382	$	705,083

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 4.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. Fair Value Measurements

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves).

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of NAV, as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in our fair value disclosures; however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 8 for fair value discussion of plan assets held in our retirement and other benefit plans.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

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

Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds

The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical account. See Note 19 for additional discussion about our investment accounts.

We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These fixed income instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.

Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.

Equity Securities

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. The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

The nuclear decommissioning trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid investments are valued using active market prices.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at December 31, 2021, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Other			Total
Assets

Risk management activities — derivative instruments:
Commodity contracts	$	—	$	115,079	$	—	$	(4,690)	(a)	$	110,389
Nuclear decommissioning trust:
Equity securities	45,264		—		—		(27,782)		(b)	17,482
U.S. commingled equity funds	—		—		—		595,048		(c)	595,048
U.S. Treasury debt	240,745		—		—		—			240,745
Corporate debt	—		203,454		—		—			203,454
Mortgage-backed securities	—		155,574		—		—			155,574
Municipal bonds	—		72,189		—		—			72,189
Other fixed income	—		10,265		—		—			10,265
Subtotal nuclear decommissioning trust	286,009		441,482		—		567,266			1,294,757

Other special use funds:

Equity securities	47,570		—		—		936		(b)	48,506
U.S. Treasury debt	298,170		—		—		—			298,170
Municipal bonds	—		11,734		—		—			11,734
Subtotal other special use funds	345,740		11,734		—		936			358,410

Total assets	$	631,749	$	568,295	$	—	$	563,512		$	1,763,556
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(4,740)	$	(2,738)	$	3,105	(a)	$	(4,373)

(a)Represents counterparty netting, margin, and collateral. See Note 16.

(b)Represents net pending securities sales and purchases.

(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 2020, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Other			Total
Assets

Risk management activities — derivative instruments:
Commodity contracts	$	—	$	9,016	$	4	$	(4,271)	(a)	$	4,749
Nuclear decommissioning trust:
Equity securities	29,796		—		—		(17,828)		(b)	11,968
U.S. commingled equity funds	—		—		—		610,055		(c)	610,055
U.S. Treasury debt	164,514		—		—		—			164,514
Corporate debt	—		149,509		—		—			149,509
Mortgage-backed securities	—		99,623		—		—			99,623
Municipal bonds	—		89,705		—		—			89,705
Other fixed income	—		13,061		—		—			13,061
Subtotal nuclear decommissioning trust	194,310		351,898		—		592,227			1,138,435

Other special use funds:
Equity securities	37,337		—		—		504		(b)	37,841
U.S. Treasury debt	203,220		—		—		—			203,220
Municipal bonds	—		13,448		—		—			13,448
Subtotal other special use funds	240,557		13,448		—		504			254,509

Total assets	$	434,867	$	374,362	$	4	$	588,460		$	1,397,693
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(20,498)	$	(1,107)	$	2,986	(a)	$	(18,619)

(a)Represents counterparty netting, margin, and collateral. See Note 16.

(b)Represents net pending securities sales and purchases.

(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

Financial Instruments Not Carried at Fair Value

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. 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.

14. Earnings Per Share

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


	2021		2020		2019
Net income attributable to common shareholders	$	618,720	$	550,559	$	538,320
Weighted average common shares outstanding — basic	112,910		112,666		112,443
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	282		276		315
Weighted average common shares outstanding — diluted	113,192		112,942		112,758
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	5.48	$	4.89	$	4.79
Net income attributable to common shareholders — diluted	$	5.47	$	4.87	$	4.77

15. Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2021 Long-Term Incentive Plan (“2021 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2021 Plan authorizes up to 1.5 million common shares to be available for grant. As of December 31, 2021, 1.2 million common shares were available for issuance under the 2021 Plan. 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 2012 to May 2021 were issued under the 2012 Long-Term Incentive Plan (“2012 Plan”), and awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”). No new awards may be granted under the 2012 or 2007 Plans.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation Expense and Activity

Compensation cost included in net income for stock-based compensation plans was $18 million in 2021, $18 million in 2020, and $18 million in 2019. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $3 million in 2021, $4 million in 2020, and $7 million in 2019.

As of December 31, 2021, there were approximately $11 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years.

The total fair value of shares vested was $22 million in 2021, $22 million in 2020 and $21 million in 2019.

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)
	2021		2020		2019		2021		2020		2019
Units granted	152,345		118,403		109,106		161,840		122,830		142,874
Weighted-average grant date fair value	$	76.72	$	71.70	$	89.15	$	82.42	$	104.74	$	92.16

(a)Units granted includes awards that will be cash settled of 51,074 in 2021, 45,646 in 2020, and 48,972 in 2019.

(b)Reflects the target payout level.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table is a summary of the status of non-vested awards as of December 31, 2021, and changes during the year:


	Restricted Stock Units, Stock Grants, and Stock Units				Performance Shares
	Shares		Weighted-Average Grant Date Fair Value		Shares (b)	Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2021	220,557		$	77.93	260,004	$	98.28
Granted	152,345		76.72		161,840	82.42
Vested	(115,099)		80.50		(136,070)	92.16
Forfeited (c)	(4,647)		80.11		(5,092)	95.07
Nonvested at December 31, 2021	253,156	(a)	79.37		280,682	92.16
Vested Awards Outstanding at December 31, 2021	88,706				136,070

(a)Includes 118,538 of awards that will be cash settled.

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

(c)We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $4 million, $6 million, and $5 million in 2021, 2020 and 2019, respectively. This includes cash used to settle restricted stock units of $3 million, $4 million, and $5 million in 2021, 2020 and 2019, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees. Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date. Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee’s retirement. 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. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company’s closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Each stock unit is convertible to one share of stock. The stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment, plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, cash, or 50% in cash and 50% in stock.

Performance Share Awards

Performance share awards are granted to officers and key employees. The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that recipients would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. 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.

16. Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates. Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options, and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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. Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):


		Quantity
Commodity	Unit of Measure	December 31, 2021	December 31, 2020
Power	GWh	—	368
Gas	Billion cubic feet	155	205

Gains and Losses from Derivative Instruments

The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):


	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2021		2020		2019

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	$	—	$	(763)	$	(1,512)

(a)During the years ended December 31, 2021, 2020, and 2019, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that no amounts will be reclassified from accumulated OCI into income. For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):


	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2021		2020		2019

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.

Derivative Instruments in the Consolidated Balance Sheets

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.

We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.


As of December 31, 2021: (dollars in thousands)	Gross Recognized Derivatives (a)		Amounts Offset (b)		Net Recognized Derivatives		Other (c)		Amounts Reported on Balance Sheets
Current assets	$	66,777	$	(3,346)	$	63,431	$	50	$	63,481
Investments and other assets	48,302		(1,394)		46,908		—		46,908
Total assets	115,079		(4,740)		110,339		50		110,389

Current liabilities	(6,084)		3,346		(2,738)		(1,635)		(4,373)
Deferred credits and other	(1,394)		1,394		—		—		—
Total liabilities	(7,478)		4,740		(2,738)		(1,635)		(4,373)
Total	$	107,601	$	—	$	107,601	$	(1,585)	$	106,016

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

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

(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,635 and cash margin provided to counterparties of $50.


As of December 31, 2020: (dollars in thousands)	Gross Recognized Derivatives (a)		Amounts Offset (b)		Net Recognized Derivatives		Other (c)		Amounts Reported on 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)
Deferred credits and other	(12,394)		1,332		(11,062)		—		(11,062)
Total liabilities	(21,605)		4,271		(17,334)		(1,285)		(18,619)
Total	$	(12,585)	$	—	$	(12,585)	$	(1,285)	$	(13,870)

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Credit Risk and Credit Related Contingent Features

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, 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. Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities, and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

The following table provides information about our derivative instruments that have credit-risk-related contingent features (dollars in thousands):


	December 31, 2021
Aggregate fair value of derivative instruments in a net liability position	$	7,478
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	2,658

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

We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $88 million if our debt credit ratings were to fall below investment grade.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. Other Income and Other Expense

The following table provides detail of Pinnacle West’s Consolidated other income and other expense for 2021, 2020 and 2019 (dollars in thousands):


	2021		2020			2019
Other income:
Interest income	$	6,726	$	12,210		$	10,377
Investment gains (losses) — net	—		2,358			—
Debt return on Four Corners SCR deferral (Note 4)	14,955		15,865			19,541
Debt return on Ocotillo modernization project (Note 4)	23,366		26,121			20,282
Miscellaneous	53		149			63
Total other income	$	45,100	$	56,703		$	50,263
Other expense:
Non-operating costs	$	(13,008)	$	(12,400)		$	(10,663)
Investment gains (losses) — net	(1,367)		—			(1,835)
Miscellaneous	(11,021)		(45,376)		(a)	(5,382)
Total other expense	$	(25,396)	$	(57,776)		$	(17,880)

(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. See Note 4.

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2021, 2020 and 2019 (dollars in thousands):


	2021		2020			2019
Other income:
Interest income	$	4,692	$	9,621		$	6,998
Debt return on Four Corners SCR deferral (Note 4)	14,955		15,865			19,541
Debt return on Ocotillo modernization project (Note 4)	23,366		26,121			20,282
Miscellaneous	40		148			63
Total other income	$	43,053	$	51,755		$	46,884
Other expense:
Non-operating costs	$	(10,080)	$	(10,659)		$	(9,612)

Miscellaneous	(8,817)		(43,035)		(a)	(3,378)
Total other expense	$	(18,897)	$	(53,694)		$	(12,990)

(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. See Note 4.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

18. Palo Verde Sale Leaseback Variable Interest Entities

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. 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.

The leases’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $17 million for 2021, and $19 million for 2020 and 2019. The increase in net income is entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

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


	December 31, 2021		December 31, 2020
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	94,166	$	98,036
Equity-Noncontrolling interests	115,260		119,290

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our consolidated financial statements.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $315 million beginning in 2022, and up to $501 million over the lease extension terms.

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

19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Account, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Consolidated Balance Sheets. 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. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning 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.

Coal Reclamation Escrow Account — APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. 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. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2021 and 2020, APS was reimbursed $15 million and $14 million, respectively, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. 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 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

APS

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
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
Equity securities	$	640,312	$	47,570	$	687,882		$	451,387	$	—
Available for sale-fixed income securities	682,227		309,904		992,131		(a)	24,283		(4,063)
Other	(27,782)		936		(26,846)		(b)	—		—
Total	$	1,294,757	$	358,410	$	1,653,167		$	475,670	$	(4,063)

(a)As of December 31, 2021, the amortized cost basis of these available-for-sale investments is $972 million.

(b)Represents net pending securities sales and purchases.


	December 31, 2020
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
Equity securities	$	639,851	$	37,337	$	677,188		$	421,666	$	—
Available for sale-fixed income securities	516,412		216,668		733,080		(a)	46,581		(398)
Other	(17,828)		504		(17,324)		(b)	—		—
Total	$	1,138,435	$	254,509	$	1,392,944		$	468,247	$	(398)

(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million.

(b)Represents net pending securities sales and purchases.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Year Ended December 31,
	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
2021
Realized gains	$	134,610	$	49	$	134,659
Realized losses	(8,431)		(7)		(8,438)
Proceeds from the sale of securities (a)	1,457,305		263,661		1,720,966
2020
Realized gains	12,194		176		12,370
Realized losses	(5,553)		(15)		(5,568)
Proceeds from the sale of securities (a)	675,035		144,484		819,519
2019
Realized gains	11,024		108		11,132
Realized losses	(6,972)		—		(6,972)
Proceeds from the sale of securities (a)	473,806		245,228		719,034

(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 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
1 year – 5 years	195,975		41,931		158,235		396,141
5 years – 10 years	155,202		1,775		21,846		178,823
Greater than 10 years	299,980		8,395		—		308,375
Total	$	682,227	$	88,953	$	220,951	$	992,131

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

20. 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 (dollars in thousands):


	Pension and Other Postretirement Benefits			Derivative Instruments			Total
Balance at December 31, 2019	$	(56,522)		$	(574)		$	(57,096)
OCI (loss) before reclassifications	(8,370)			(2,089)			(10,459)
Amounts reclassified from accumulated other comprehensive loss	4,167		(a)	592		(b)	4,759

Balance at December 31, 2020	(60,725)			(2,071)			(62,796)
OCI (loss) before reclassifications	2,439			1,077			3,516
Amounts reclassified from accumulated other comprehensive loss	4,401		(a)	18		(b)	4,419

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.

Changes in Accumulated Other Comprehensive Loss — APS

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


	Pension and Other Postretirement Benefits			Derivative Instruments			Total
Balance at December 31, 2019	$	(34,948)		$	(574)		$	(35,522)
OCI (loss) before reclassifications	(9,568)			(18)			(9,586)
Amounts reclassified from accumulated other comprehensive loss	3,598		(a)	592		(b)	4,190

Balance at December 31, 2020	(40,918)			—			(40,918)
OCI (loss) before reclassifications	2,043			(18)			2,025
Amounts reclassified from accumulated other comprehensive loss	3,995		(a)	18		(b)	4,013

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.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)


	Year Ended December 31,
	2021		2020		2019

Operating expenses	$	10,245	$	7,901	$	12,451

Other
Equity in earnings of subsidiaries	628,916		566,147		562,946
Other expense	(4,919)		(4,586)		(3,957)
Total	623,997		561,561		558,989
Interest expense	10,672		14,021		15,069
Income before income taxes	603,080		539,639		531,469
Income tax benefit	(15,640)		(10,920)		(6,851)
Net income attributable to common shareholders	618,720		550,559		538,320
Other comprehensive income (loss) — attributable to common shareholders	7,935		(5,700)		(9,388)
Total comprehensive income — attributable to common shareholders	$	626,655	$	544,859	$	528,932

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(dollars in thousands)


	December 31,
	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	594	$	19
Accounts receivable	125,457		123,980

Income tax receivable	1,498		14,719
Other current assets	13		298
Total current assets	127,562		139,016
Investments and other assets
Investments in subsidiaries	6,797,528		6,400,339
Deferred income taxes	19,520		7,589
Other assets	57,608		52,595
Total investments and other assets	6,874,656		6,460,523
Total Assets	$	7,002,218	$	6,599,539
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	3,071	$	5,669
Accrued taxes	19,855		16,998
Common dividends payable	95,988		93,531
Short-term borrowings	13,300		169,000
Current maturities of long-term debt	150,000		—
Operating lease liabilities	107		90
Other current liabilities	14,684		15,306
Total current liabilities	297,005		300,594

Long-term debt less current maturities (Note 7)	647,139		496,321



Pension liabilities	14,537		17,541
Operating lease liabilities	1,576		1,683
Other	20,501		30,607
Total deferred credits and other	36,614		49,831
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock	2,696,342		2,671,193
Accumulated other comprehensive loss	(54,861)		(62,796)
Retained earnings	3,264,719		3,025,106
Total Pinnacle West Shareholders’ equity	5,906,200		5,633,503
Noncontrolling interests	115,260		119,290
Total Equity	6,021,460		5,752,793
Total Liabilities and Equity	$	7,002,218	$	6,599,539

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)


	Year Ended December 31,
	2021		2020		2019
Cash flows from operating activities
Net income	$	618,720	$	550,559	$	538,320
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(628,916)		(566,147)		(562,946)
Depreciation and amortization	93		76		76
Deferred income taxes	(11,381)		33,007		(35,831)
Accounts receivable	8,897		(7,903)		182
Accounts payable	(2,598)		(1,964)		(2,129)
Accrued taxes and income tax receivables — net	16,079		9,610		16,400
Dividends received from subsidiaries	376,500		357,500		336,300
Other	4,214		20,163		(1,300)
Net cash flow provided by operating activities	381,608		394,901		289,072
Cash flows from investing activities

Investments in subsidiaries	(145,266)		(137,881)		1,557
Repayments of loans from subsidiaries	4,017		932		4,190
Advances of loans to subsidiaries	(12,256)		(7,261)		(4,165)
Net cash flow provided by (used for) investing activities	(153,505)		(144,210)		1,582
Cash flows from financing activities
Issuance of long-term debt	300,000		496,950		—
Short-term debt borrowings under revolving credit facility	—		211,690		49,000
Short-term debt repayments under revolving credit facility	(19,000)		(230,690)		(65,000)
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 and purchases — net	(2,350)		(1,389)		692

Net cash flow used for financing activities	(227,528)		(250,691)		(290,676)
Net decrease in cash and cash equivalents	575		—		(22)
Cash and cash equivalents at beginning of year	19		19		41
Cash and cash equivalents at end of year	$	594	$	19	$	19

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

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 on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

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