UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2020~~March 31, 2021


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to


Commission File Number	Exact Name of Each Registrant as specified in its charter; State of Incorporation; Address; and Telephone Number			IRS Employer Identification No.
1-8962	PINNACLE WEST CAPITAL CORPORATION			86-0512431
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix	Arizona	85072-3999
	(602)	250-1000
1-4473	ARIZONA PUBLIC SERVICE COMPANY			86-0011170
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix	Arizona	85072-3999
	(602)	250-1000

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	PNW	The New York Stock Exchange

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION

Yes

☒

☐

ARIZONA PUBLIC SERVICE COMPANY

Yes

☒

☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PINNACLE WEST CAPITAL CORPORATION

Yes

☒

☐

ARIZONA PUBLIC SERVICE COMPANY

Yes

☒

☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of ~~"large~~“large accelerated filer,~~" "accelerated~~” “accelerated filer,~~" "smaller~~” “smaller reporting company,"” and ~~"emerging~~“emerging growth ~~company"~~company” in Rule 12b-2 of the Exchange Act.

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

PINNACLE WEST CAPITAL CORPORATION

Yes

☐

☒

ARIZONA PUBLIC SERVICE COMPANY

Yes

☐

☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of ~~October 23, 2020:~~April 28, 2021:	~~112,596,784~~112,750,962
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of ~~October 23, 2020:~~April 28, 2021:	71,264,947

Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

TABLE OF CONTENTS

This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation ("(“Pinnacle ~~West"~~West”) and Arizona Public Service Company ~~("APS"~~(“APS”). Any use of the words ~~"Company," "we,"~~“Company,” “we,” and ~~"our"~~“our” refer to Pinnacle West. Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information. The information required with respect to each company is set forth within the applicable items. Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS. Item 1 also includes Combined Notes to Condensed Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations. These forward-looking statements are often identified by words such as ~~"estimate," "predict," "may," "believe," "plan," "expect," "require," "intend," "assume," "project," "anticipate," "goal," "seek," "strategy," "likely," "should," "will," "could,"~~“estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project,” “anticipate,” “goal,” “seek,” “strategy,” “likely,” “should,” “will,” “could,” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, ~~2019 ("2019~~2020 (“2020 Form ~~10-K"), Part II, Item 1A of the Pinnacle West/APS Quarterly Reports on Form 10‑Q for the quarters ended March 31, 2020 and June 30, 2020 ("2020 1st and 2nd Quarter 10-Q"~~10-K”), Part II, Item 1A of this report and in Part I, Item 2 — ~~"Management’s~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” of this report, these factors include, but are not limited to:

•the potential effects of the continued Coronavirus ("(“COVID-19") pandemic, including, but not limited to, demand for energy, economic growth, our employees and contractors, supply chain, expenses, capital markets, capital projects, operations and maintenance activities, uncollectable accounts, liquidity, cash flows or other unpredictable events;

•our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;

•variations in demand for electricity, including those due to weather, seasonality, the general economy or social conditions, customer and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements;

•power plant and transmission system performance and outages;

•competition in retail and wholesale power markets;

•regulatory and judicial decisions, developments and proceedings;

•new legislation, ballot initiatives and regulation, including those relating to environmental requirements, regulatory and energy policy, nuclear plant operations and potential deregulation of retail electric markets;

•fuel and water supply availability;

•our ability to achieve timely and adequate rate recovery of our costs through our rates and adjustor recovery mechanisms, including returns on and of debt and equity capital investment;

•our ability to meet renewable energy and energy efficiency mandates and recover related costs;

•the ability of APS to achieve its clean energy goals (including a goal by 2050 of 100% clean, carbon-free electricity) and, if these goals are achieved, the impact of such achievement on APS, its customers, and its business, financial condition and results of operations;

•risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

•current and future economic conditions in Arizona, including in real estate markets;

•the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, droughts, or other catastrophic events, such as fires, explosions, pandemic health events, or similar occurrences;

•the development of new technologies which may affect electric sales or delivery;

•the cost of debt and equity capital and the ability to access capital markets when required;

•environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions;

•volatile fuel and purchased power costs;

•the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

•the liquidity of wholesale power markets and the use of derivative contracts in our business;

•potential shortfalls in insurance coverage;

•new accounting requirements or new interpretations of existing requirements;

•generation, transmission and distribution facility and system conditions and operating costs;

•the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region;

•the willingness or ability of our counterparties, power plant participants and power plant ~~land owners~~landowners to meet contractual or other obligations or extend the rights for continued power plant operations; and

•restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission ~~("ACC"~~(“ACC”) orders.

These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our ~~2019~~2020 Form 10-K, ~~Part II, Item 1A of our 2020 1st and 2nd Quarter 10-Q,~~ Part II, Item 1A of this report, and in Part I, Item 2 — ~~"Management’s~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES


			Page

Pinnacle West Condensed Consolidated Statements of Income for Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			5
Pinnacle West Condensed Consolidated Statements of Comprehensive Income for Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			6
Pinnacle West Condensed Consolidated Balance Sheets as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020			7
Pinnacle West Condensed Consolidated Statements of Cash Flows for ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			9
Pinnacle West Condensed Consolidated Statements of Changes in Equity for Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			10

APS Condensed Consolidated Statements of Income for Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			1211
APS Condensed Consolidated Statements of Comprehensive Income for Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			1312
APS Condensed Consolidated Balance Sheets as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020			1413
APS Condensed Consolidated Statements of Cash Flows for ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			1615
APS Condensed Consolidated Statements of Changes in Equity for Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~			1716

Combined Notes to Condensed Consolidated Financial Statements			1917
Note 1. Consolidation and Nature of Operations			1917
Note 2. Revenue			2018
Note 3. Long-Term Debt and Liquidity Matters			2220
Note 4. Regulatory Matters			2422
Note 5. Retirement Plans and Other Postretirement Benefits			4140
Note 6. Palo Verde Sale Leaseback Variable Interest Entities			42
Note 7. Derivative Accounting			43
Note 8. Commitments and Contingencies			47
Note 9. Other Income and Other Expense			54
Note 10. Earnings Per Share			55
Note 11. Fair Value Measurements			55
Note 12. Investment in Nuclear Decommissioning Trusts and Other Special Use Funds			6160

Note 13. ~~New Accounting Standards~~			64
~~Note 14.~~ Changes in Accumulated Other Comprehensive Loss			6563
Note ~~15.~~14. Income Taxes			6765
~~Note 16. Leases~~			68
~~Note 17. Asset Retirement Obligations~~			70

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019			2021		2020

OPERATING REVENUES (NOTE 2)	OPERATING REVENUES (NOTE 2)	$	1,254,501	$	1,190,787	$	2,846,021	$	2,800,818	OPERATING REVENUES (NOTE 2)	$	696,475	$	661,930

OPERATING EXPENSES	OPERATING EXPENSES									OPERATING EXPENSES
Fuel and purchased power	Fuel and purchased power	353,171		344,862		780,074		817,672		Fuel and purchased power	198,227		188,521
Operations and maintenance	Operations and maintenance	236,971		238,582		677,681		711,759		Operations and maintenance	230,055		221,318
Depreciation and amortization	Depreciation and amortization	152,696		149,450		459,257		445,531		Depreciation and amortization	157,820		154,079
Taxes other than income taxes	Taxes other than income taxes	54,978		53,809		168,514		163,989		Taxes other than income taxes	59,483		56,768
Other expenses	Other expenses	1,677		794		3,191		1,904		Other expenses	3,356		822
Total	Total	799,493		787,497		2,088,717		2,140,855		Total	648,941		621,508
OPERATING INCOME	OPERATING INCOME	455,008		403,290		757,304		659,963		OPERATING INCOME	47,534		40,422
OTHER INCOME (DEDUCTIONS)	OTHER INCOME (DEDUCTIONS)									OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	8,144		5,917		24,652		24,677		Allowance for equity funds used during construction	9,207		7,697
Pension and other postretirement non-service credits - net		14,118		5,752		42,171		17,240
Pension and other postretirement non-service credits — net										Pension and other postretirement non-service credits — net	27,791		13,911
Other income (Note 9)	Other income (Note 9)	13,881		15,191		42,888		35,245		Other income (Note 9)	12,429		12,569
Other expense (Note 9)	Other expense (Note 9)	(5,838)		(5,740)		(14,426)		(14,448)		Other expense (Note 9)	(3,853)		(4,784)
Total	Total	30,305		21,120		95,285		62,714		Total	45,574		29,393
INTEREST EXPENSE	INTEREST EXPENSE									INTEREST EXPENSE
Interest charges	Interest charges	61,497		57,481		183,421		175,599		Interest charges	61,938		59,234
Allowance for borrowed funds used during construction	Allowance for borrowed funds used during construction	(4,663)		(3,486)		(13,488)		(14,645)		Allowance for borrowed funds used during construction	(4,994)		(4,076)
Total	Total	56,834		53,995		169,933		160,954		Total	56,944		55,158
INCOME BEFORE INCOME TAXES	INCOME BEFORE INCOME TAXES	428,479		370,415		682,656		561,723		INCOME BEFORE INCOME TAXES	36,164		14,657
INCOME TAXES	INCOME TAXES	77,234		53,266		98,086		72,764		INCOME TAXES	(4,350)		(20,209)
NET INCOME	NET INCOME	351,245		317,149		584,570		488,959		NET INCOME	40,514		34,866
Less: Net income attributable to noncontrolling interests (Note 6)	Less: Net income attributable to noncontrolling interests (Note 6)	4,873		4,873		14,620		14,620		Less: Net income attributable to noncontrolling interests (Note 6)	4,873		4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	346,372	$	312,276	$	569,950	$	474,339	NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	35,641	$	29,993

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	112,679		112,463		112,639		112,408		WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	112,829		112,594
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,987		112,746		112,912		112,739		WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	113,093		112,862

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING	EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING									EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	Net income attributable to common shareholders — basic	$	3.07	$	2.78	$	5.06	$	4.22	Net income attributable to common shareholders — basic	$	0.32	$	0.27
Net income attributable to common shareholders — diluted	Net income attributable to common shareholders — diluted	$	3.07	$	2.77	$	5.05	$	4.21	Net income attributable to common shareholders — diluted	$	0.32	$	0.27

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

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019			2021		2020

NET INCOME	NET INCOME	$	351,245	$	317,149	$	584,570	$	488,959	NET INCOME	$	40,514	$	34,866

OTHER COMPREHENSIVE INCOME, NET OF TAX	OTHER COMPREHENSIVE INCOME, NET OF TAX									OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:	Derivative instruments:									Derivative instruments:
Net unrealized loss, net of tax benefit of $219, $0, $1,024 and $0		(659)		0		(1,916)		0
Reclassification of net realized loss, net of tax benefit of $0, $71, $481 and $313		0		218		282		950
Pension and other postretirement benefit activity, net of tax expense of $345, $290, $256 and $72		1,043		880		1,239		220
Total other comprehensive income (loss)		384		1,098		(395)		1,170
Net unrealized gain, net of tax (expense) benefit of $(86) and $292										Net unrealized gain, net of tax (expense) benefit of $(86) and $292	262		292
Reclassification of net realized gain, net of tax expense of $0 and $394										Reclassification of net realized gain, net of tax expense of $0 and $394	0		20
Pension and other postretirement benefit activity, net of tax expense of $336 and $245										Pension and other postretirement benefit activity, net of tax expense of $336 and $245	1,022		1,205
Total other comprehensive income										Total other comprehensive income	1,284		1,517

COMPREHENSIVE INCOME	COMPREHENSIVE INCOME	351,629		318,247		584,175		490,129		COMPREHENSIVE INCOME	41,798		36,383
Less: Comprehensive income attributable to noncontrolling interests	Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873		14,620		14,620		Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	346,756	$	313,374	$	569,555	$	475,509	COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	36,925	$	31,510

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

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
ASSETS	ASSETS					ASSETS

CURRENT ASSETS	CURRENT ASSETS					CURRENT ASSETS
Cash and cash equivalents	Cash and cash equivalents	$	181,926	$	10,283	Cash and cash equivalents	$	17,202	$	59,968
Customer and other receivables	Customer and other receivables	417,415		266,426		Customer and other receivables	263,126		313,576
Accrued unbilled revenues	Accrued unbilled revenues	175,341		128,165		Accrued unbilled revenues	122,034		132,197
Allowance for doubtful accounts	Allowance for doubtful accounts	(18,069)		(8,171)		Allowance for doubtful accounts	(20,405)		(19,782)
Materials and supplies (at average cost)	Materials and supplies (at average cost)	322,017		331,091		Materials and supplies (at average cost)	314,702		314,745
Fossil fuel (at average cost)	Fossil fuel (at average cost)	17,060		14,829		Fossil fuel (at average cost)	24,396		19,552
Income tax receivable	Income tax receivable	4,325		21,727		Income tax receivable	0		6,792
Assets from risk management activities (Note 7)	Assets from risk management activities (Note 7)	13,875		515		Assets from risk management activities (Note 7)	22,611		2,931
Deferred fuel and purchased power regulatory asset (Note 4)	Deferred fuel and purchased power regulatory asset (Note 4)	162,111		70,137		Deferred fuel and purchased power regulatory asset (Note 4)	228,609		175,835
Other regulatory assets (Note 4)	Other regulatory assets (Note 4)	110,759		133,070		Other regulatory assets (Note 4)	111,271		115,878
Other current assets	Other current assets	67,926		61,958		Other current assets	86,238		76,627
Total current assets	Total current assets	1,454,686		1,030,030		Total current assets	1,169,784		1,198,319
INVESTMENTS AND OTHER ASSETS	INVESTMENTS AND OTHER ASSETS					INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	Nuclear decommissioning trust (Notes 11 and 12)	1,069,837		1,010,775		Nuclear decommissioning trust (Notes 11 and 12)	1,159,699		1,138,435
Other special use funds (Notes 11 and 12)	Other special use funds (Notes 11 and 12)	268,292		245,095		Other special use funds (Notes 11 and 12)	357,506		254,509
Other assets	Other assets	96,855		96,953		Other assets	88,487		92,922
Total investments and other assets	Total investments and other assets	1,434,984		1,352,823		Total investments and other assets	1,605,692		1,485,866
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT					PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	Plant in service and held for future use	20,453,437		19,836,292		Plant in service and held for future use	20,948,591		20,837,885
Accumulated depreciation and amortization	Accumulated depreciation and amortization	(6,999,995)		(6,637,857)		Accumulated depreciation and amortization	(7,189,708)		(7,110,310)
Net	Net	13,453,442		13,198,435		Net	13,758,883		13,727,575
Construction work in progress	Construction work in progress	972,024		808,133		Construction work in progress	1,056,991		937,384
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	99,003		101,906		Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	97,068		98,036
Intangible assets, net of accumulated amortization	Intangible assets, net of accumulated amortization	266,220		290,564		Intangible assets, net of accumulated amortization	278,226		282,570
Nuclear fuel, net of accumulated amortization	Nuclear fuel, net of accumulated amortization	128,876		123,500		Nuclear fuel, net of accumulated amortization	124,533		113,645
Total property, plant and equipment	Total property, plant and equipment	14,919,565		14,522,538		Total property, plant and equipment	15,315,701		15,159,210
DEFERRED DEBITS	DEFERRED DEBITS					DEFERRED DEBITS
Regulatory assets (Note 4)	Regulatory assets (Note 4)	1,305,437		1,304,073		Regulatory assets (Note 4)	1,135,857		1,133,987
Operating lease right-of-use assets (Note 16)		502,898		145,813
Assets for other postretirement benefits (Note 5)		105,675		90,570
Operating lease right-of-use assets						Operating lease right-of-use assets	502,959		505,064
Assets for pension and other postretirement benefits (Note 5)						Assets for pension and other postretirement benefits (Note 5)	418,427		502,992
Other	Other	28,176		33,400		Other	36,238		34,983
Total deferred debits	Total deferred debits	1,942,186		1,573,856		Total deferred debits	2,093,481		2,177,026

TOTAL ASSETS	TOTAL ASSETS	$	19,751,421	$	18,479,247	TOTAL ASSETS	$	20,184,658	$	20,020,421

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

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY

CURRENT LIABILITIES	CURRENT LIABILITIES					CURRENT LIABILITIES
Accounts payable	Accounts payable	$	288,265	$	346,448	Accounts payable	$	309,145	$	318,585
Accrued taxes	Accrued taxes	221,358		144,899		Accrued taxes	213,536		159,551
Accrued interest	Accrued interest	60,642		53,534		Accrued interest	58,709		56,962
Common dividends payable	Common dividends payable	0		87,982		Common dividends payable	0		93,531
Short-term borrowings (Note 3)	Short-term borrowings (Note 3)	57,925		114,675		Short-term borrowings (Note 3)	214,750		169,000
Current maturities of long-term debt (Note 3)		0		800,000

Customer deposits	Customer deposits	47,730		64,908		Customer deposits	45,170		48,340
Liabilities from risk management activities (Note 7)	Liabilities from risk management activities (Note 7)	4,266		38,946		Liabilities from risk management activities (Note 7)	3,067		7,557
Liabilities for asset retirements	Liabilities for asset retirements	12,226		11,025		Liabilities for asset retirements	16,021		15,586

Operating lease liabilities (Note 16)		89,064		12,713
Operating lease liabilities						Operating lease liabilities	74,328		74,785
Regulatory liabilities (Note 4)	Regulatory liabilities (Note 4)	308,019		234,912		Regulatory liabilities (Note 4)	250,228		229,088
Other current liabilities	Other current liabilities	155,289		168,323		Other current liabilities	145,589		187,448
Total current liabilities	Total current liabilities	1,244,784		2,078,365		Total current liabilities	1,330,543		1,360,433
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)	LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)	6,316,420		4,832,558		LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)	6,465,045		6,314,266
DEFERRED CREDITS AND OTHER	DEFERRED CREDITS AND OTHER					DEFERRED CREDITS AND OTHER
Deferred income taxes	Deferred income taxes	2,163,050		1,992,339		Deferred income taxes	2,134,471		2,135,403
Regulatory liabilities (Note 4)	Regulatory liabilities (Note 4)	2,079,323		2,267,835		Regulatory liabilities (Note 4)	2,427,769		2,450,169
Liabilities for asset retirements	Liabilities for asset retirements	674,025		646,193		Liabilities for asset retirements	693,383		689,497
Liabilities for pension benefits (Note 5)	Liabilities for pension benefits (Note 5)	177,855		280,185		Liabilities for pension benefits (Note 5)	164,230		166,484
Liabilities from risk management activities (Note 7)	Liabilities from risk management activities (Note 7)	9,092		33,186		Liabilities from risk management activities (Note 7)	6,928		11,062
Customer advances	Customer advances	224,924		215,330		Customer advances	220,999		221,032
Coal mine reclamation	Coal mine reclamation	168,997		165,695		Coal mine reclamation	171,227		170,097
Deferred investment tax credit	Deferred investment tax credit	187,926		196,468		Deferred investment tax credit	190,842		191,372
Unrecognized tax benefits	Unrecognized tax benefits	6,013		6,189		Unrecognized tax benefits	5,870		5,834
Operating lease liabilities (Note 16)		358,490		51,872
Operating lease liabilities						Operating lease liabilities	360,497		361,336
Other	Other	173,347		159,844		Other	206,174		190,643
Total deferred credits and other	Total deferred credits and other	6,223,042		6,015,136		Total deferred credits and other	6,582,390		6,592,929
COMMITMENTS AND CONTINGENCIES (NOTE 8)	COMMITMENTS AND CONTINGENCIES (NOTE 8)					COMMITMENTS AND CONTINGENCIES (NOTE 8)	0		0
EQUITY	EQUITY					EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,623,623 and 112,540,126 issued at respective dates		2,670,358		2,659,561
Treasury stock at cost; 33,717 and 103,546 shares at respective dates		(2,966)		(9,427)
Common stock, no par value; authorized 150,000,000 shares, 112,791,565 and 112,760,051 issued at respective dates						Common stock, no par value; authorized 150,000,000 shares, 112,791,565 and 112,760,051 issued at respective dates	2,687,052		2,677,482
Treasury stock at cost; 44,338 and 72,006 shares at respective dates						Treasury stock at cost; 44,338 and 72,006 shares at respective dates	(3,776)		(6,289)
Total common stock	Total common stock	2,667,392		2,650,134		Total common stock	2,683,276		2,671,193
Retained earnings	Retained earnings	3,231,485		2,837,610		Retained earnings	3,060,752		3,025,106
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(57,491)		(57,096)		Accumulated other comprehensive loss	(61,512)		(62,796)
Total shareholders’ equity	Total shareholders’ equity	5,841,386		5,430,648		Total shareholders’ equity	5,682,516		5,633,503
Noncontrolling interests (Note 6)	Noncontrolling interests (Note 6)	125,789		122,540		Noncontrolling interests (Note 6)	124,164		119,290
Total equity	Total equity	5,967,175		5,553,188		Total equity	5,806,680		5,752,793

TOTAL LIABILITIES AND EQUITY	TOTAL LIABILITIES AND EQUITY	$	19,751,421	$	18,479,247	TOTAL LIABILITIES AND EQUITY	$	20,184,658	$	20,020,421

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

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
CASH FLOWS FROM OPERATING ACTIVITIES	CASH FLOWS FROM OPERATING ACTIVITIES					CASH FLOWS FROM OPERATING ACTIVITIES
Net income	Net income	$	584,570	$	488,959	Net income	$	40,514	$	34,866
Adjustments to reconcile net income to net cash provided by operating activities:	Adjustments to reconcile net income to net cash provided by operating activities:					Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	Depreciation and amortization including nuclear fuel	515,742		500,801		Depreciation and amortization including nuclear fuel	176,409		173,168
Deferred fuel and purchased power	Deferred fuel and purchased power	(82,679)		(60,911)		Deferred fuel and purchased power	(52,210)		(5,785)
Deferred fuel and purchased power amortization	Deferred fuel and purchased power amortization	(9,295)		38,601		Deferred fuel and purchased power amortization	(564)		(1,808)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(24,652)		(24,677)		Allowance for equity funds used during construction	(9,207)		(7,697)
Deferred income taxes	Deferred income taxes	91,077		83,703		Deferred income taxes	(11,077)		(18,086)
Deferred investment tax credit	Deferred investment tax credit	(8,541)		(7,288)		Deferred investment tax credit	(529)		(465)

Stock compensation	Stock compensation	12,119		16,486		Stock compensation	11,337		6,282
Changes in current assets and liabilities:	Changes in current assets and liabilities:					Changes in current assets and liabilities:
Customer and other receivables	Customer and other receivables	(118,998)		(91,506)		Customer and other receivables	50,545		25,575
Accrued unbilled revenues	Accrued unbilled revenues	(47,176)		(18,666)		Accrued unbilled revenues	10,163		34,731
Materials, supplies and fossil fuel	Materials, supplies and fossil fuel	6,843		(18,332)		Materials, supplies and fossil fuel	(4,801)		5,445
Income tax receivable	Income tax receivable	17,402		(14,063)		Income tax receivable	6,792		1,128
Other current assets	Other current assets	(20,527)		(10,104)		Other current assets	(9,042)		(20,202)
Accounts payable	Accounts payable	(6,400)		33,899		Accounts payable	24,465		(5,192)
Accrued taxes	Accrued taxes	76,459		66,111		Accrued taxes	53,985		49,833
Other current liabilities	Other current liabilities	6,946		(68,927)		Other current liabilities	(46,028)		(63,096)

Change in other long-term assets	Change in other long-term assets	(10,152)		(52,276)		Change in other long-term assets	(36,777)		81,143
Change in other long-term liabilities	Change in other long-term liabilities	(210,719)		(27,049)		Change in other long-term liabilities	(1,963)		(106,212)
Net cash flow provided by operating activities	Net cash flow provided by operating activities	772,019		834,761		Net cash flow provided by operating activities	202,012		183,628
CASH FLOWS FROM INVESTING ACTIVITIES	CASH FLOWS FROM INVESTING ACTIVITIES					CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	Capital expenditures	(971,052)		(857,883)		Capital expenditures	(363,775)		(340,014)
Contributions in aid of construction	Contributions in aid of construction	41,457		34,121		Contributions in aid of construction	15,296		3,152
Allowance for borrowed funds used during construction	Allowance for borrowed funds used during construction	(13,488)		(14,645)		Allowance for borrowed funds used during construction	(4,994)		(4,076)
Proceeds from nuclear decommissioning trust sales and other special use funds	Proceeds from nuclear decommissioning trust sales and other special use funds	607,885		520,996		Proceeds from nuclear decommissioning trust sales and other special use funds	379,978		195,087
Investment in nuclear decommissioning trust and other special use funds	Investment in nuclear decommissioning trust and other special use funds	(624,249)		(523,573)		Investment in nuclear decommissioning trust and other special use funds	(380,548)		(195,658)
Other	Other	3,944		8,971		Other	5,974		349
Net cash flow used for investing activities	Net cash flow used for investing activities	(955,503)		(832,013)		Net cash flow used for investing activities	(348,069)		(341,160)
CASH FLOWS FROM FINANCING ACTIVITIES	CASH FLOWS FROM FINANCING ACTIVITIES					CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	Issuance of long-term debt	1,483,822		794,981		Issuance of long-term debt	150,000		0

Short-term borrowing and payments — net		(42,750)		(6,025)
Short-term debt borrowings		751,690		49,000
Short-term debt repayments		(765,690)		(62,000)
Short-term borrowing and (repayments) — net						Short-term borrowing and (repayments) — net	49,750		(76,675)
Short-term debt borrowings under revolving credit facility						Short-term debt borrowings under revolving credit facility	0		751,690
Short-term debt repayments under revolving credit facility						Short-term debt repayments under revolving credit facility	(4,000)		(226,690)
Dividends paid on common stock	Dividends paid on common stock	(258,924)		(243,116)		Dividends paid on common stock	(91,721)		(86,257)
Repayment of long-term debt	Repayment of long-term debt	(800,000)		(500,000)		Repayment of long-term debt	0		(150,000)
Common stock equity issuance - net of purchases		(1,649)		(130)
Distributions to noncontrolling interests		(11,372)		(11,372)
Common stock equity issuance — net of purchases						Common stock equity issuance — net of purchases	(738)		(1,680)

Net cash flow provided by financing activities	Net cash flow provided by financing activities	355,127		21,338		Net cash flow provided by financing activities	103,291		210,388

NET INCREASE IN CASH AND CASH EQUIVALENTS		171,643		24,086
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(42,766)		52,856

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	10,283		5,766		CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	59,968		10,283

CASH AND CASH EQUIVALENTS AT END OF PERIOD	CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	181,926	$	29,852	CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	17,202	$	63,139

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

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)


		Three Months Ended September 30, 2020															Three Months Ended March 31, 2021
		Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total			Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
		Shares	Amount		Shares	Amount											Shares	Amount		Shares	Amount
Balance, July 1, 2020		112,591,124	$	2,665,518	(35,983)	$	(3,190)	$	2,885,109	$	(57,875)	$	120,915	$	5,610,477
Balance, January 1, 2021																Balance, January 1, 2021	112,760,051	$	2,677,482	(72,006)	$	(6,289)	$	3,025,106	$	(62,796)	$	119,290	$	5,752,793
Net income	Net income		—			—		346,372		—		4,873		351,245		Net income		—			—		35,641		—		4,873		40,514
Other comprehensive income	Other comprehensive income		—			—		—		384		—		384		Other comprehensive income		—			—		—		1,284		—		1,284
Dividends on common stock	Dividends on common stock		—			—		1		—		—		1		Dividends on common stock		—			—		5		—		—		5
Issuance of common stock	Issuance of common stock	32,499	4,840					—		—		—		4,840		Issuance of common stock	31,514	9,570					—		—		—		9,570
Purchase of treasury stock (a)	Purchase of treasury stock (a)		—		(1,499)	(109)		—		—		—		(109)		Purchase of treasury stock (a)		—		(17,437)	(1,333)		—		—		—		(1,333)
Reissuance of treasury stock for stock-based compensation and other	Reissuance of treasury stock for stock-based compensation and other		—		3,765	333		0		—		—		333		Reissuance of treasury stock for stock-based compensation and other		—		45,105	3,846		—		—		—		3,846
Other	Other		—			—		3		—		1		4		Other		—			—		—		—		1		1
Balance, September 30, 2020		112,623,623	$	2,670,358	(33,717)	$	(2,966)	$	3,231,485	$	(57,491)	$	125,789	$	5,967,175
Balance, March 31, 2021																Balance, March 31, 2021	112,791,565	$	2,687,052	(44,338)	$	(3,776)	$	3,060,752	$	(61,512)	$	124,164	$	5,806,680


		Three Months Ended September 30, 2019															Three Months Ended March 31, 2020
		Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total			Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
		Shares	Amount		Shares	Amount											Shares	Amount		Shares	Amount
Balance, July 1, 2019		112,361,595	$	2,648,234	(58,219)	$	(5,140)	$	2,637,620	$	(47,636)	$	124,165	$	5,357,243
Balance, January 1, 2020																Balance, January 1, 2020	112,540,126	$	2,659,561	(103,546)	$	(9,427)	$	2,837,610	$	(57,096)	$	122,540	$	5,553,188
Net income	Net income		—			—		312,276		—		4,873		317,149		Net income		—			—		29,993		—		4,873		34,866
Other comprehensive income	Other comprehensive income		—			—		—		1,098		—		1,098		Other comprehensive income		—			—		—		1,517		—		1,517
Dividends on common stock	Dividends on common stock		—			—		(5)		—		—		(5)		Dividends on common stock		—			—		8		—		—		8
Issuance of common stock	Issuance of common stock	42,156	6,196			—		—		—		—		6,196		Issuance of common stock	23,484	4,826			—		—		—		—		4,826
Purchase of treasury stock (a)	Purchase of treasury stock (a)				(103)	(10)								(10)		Purchase of treasury stock (a)				(20,724)	(2,086)								(2,086)
Reissuance of treasury stock for stock-based compensation and other	Reissuance of treasury stock for stock-based compensation and other		—		375	33		0		—		—		33		Reissuance of treasury stock for stock-based compensation and other		—		51,968	4,513		—		—		—		4,513

Other	Other		—			—		—		—		1		1		Other		—			—		(1)		—		1		0
Balance, September 30, 2019		112,403,751	$	2,654,430	(57,947)	$	(5,117)	$	2,949,891	$	(46,538)	$	129,039	$	5,681,705
Balance, March 31, 2020																Balance, March 31, 2020	112,563,610	$	2,664,387	(72,302)	$	(7,000)	$	2,867,610	(55,579)		$	127,414	$	5,596,832

(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.

~~PINNACLE WEST CAPITAL CORPORATION~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY~~

~~(unaudited)~~

~~(dollars in thousands)~~

Nine Months Ended September 30, 2020
Common Stock Treasury Stock Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount Shares Amount
Balance, January 1, 2020 112,540,126 $ 2,659,561 (103,546) $ (9,427) $ 2,837,610 $ (57,096) $ 122,540 $ 5,553,188
Net income — — 569,950 — 14,620 584,570
Other comprehensive loss — — — (395) — (395)
Dividends on common stock ($1.57 per share) — — (176,079) — — (176,079)
Issuance of common stock 83,497 10,797 — — — — 10,797
Purchase of treasury stock (a) — (34,569) (3,119) — — — (3,119)
Reissuance of treasury stock for stock-based compensation and other — 104,398 9,580 0 — — 9,580
Capital activities by noncontrolling interests — — 0 — (11,372) (11,372)
Other 4 1 5
Balance, September 30, 2020 112,623,623 $ 2,670,358 (33,717) $ (2,966) $ 3,231,485 $ (57,491) $ 125,789 $ 5,967,175

Nine Months Ended September 30, 2019
Common Stock Treasury Stock Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount Shares Amount
Balance, January 1, 2019 112,159,896 $ 2,634,265 (58,135) $ (4,825) $ 2,641,183 $ (47,708) $ 125,790 $ 5,348,705
Net income — — 474,339 — 14,620 488,959
Other comprehensive income — — — 1,170 — 1,170
Dividends on common stock ($1.48 per share) — — (165,631) — — (165,631)
Issuance of common stock 243,855 20,165 — — — — 20,165
Purchase of treasury stock (a) — (75,894) (6,892) — — — (6,892)
Reissuance of treasury stock for stock-based compensation and other — 76,082 6,600 0 — — 6,600
Capital activities by noncontrolling interests — — 0 — (11,372) (11,372)
Other — — — — 1 1
Balance, September 30, 2019 112,403,751 $ 2,654,430 (57,947) $ (5,117) $ 2,949,891 $ (46,538) $ 129,039 $ 5,681,705

~~(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.~~

1110

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019			2021		2020

OPERATING REVENUES (NOTE 2)	OPERATING REVENUES (NOTE 2)	$	1,254,501	$	1,190,787	$	2,846,021	$	2,800,818	OPERATING REVENUES (NOTE 2)	$	696,475	$	661,930

OPERATING EXPENSES	OPERATING EXPENSES									OPERATING EXPENSES
Fuel and purchased power	Fuel and purchased power	353,171		344,862		780,074		817,672		Fuel and purchased power	198,227		188,521
Operations and maintenance	Operations and maintenance	233,452		235,440		667,938		699,958		Operations and maintenance	226,401		218,265
Depreciation and amortization	Depreciation and amortization	152,676		149,428		459,194		445,467		Depreciation and amortization	157,800		154,058
Taxes other than income taxes	Taxes other than income taxes	54,966		53,798		168,482		163,957		Taxes other than income taxes	59,472		56,758
Other expenses	Other expenses	1,677		794		3,191		1,904		Other expenses	3,356		822
Total	Total	795,942		784,322		2,078,879		2,128,958		Total	645,256		618,424
OPERATING INCOME	OPERATING INCOME	458,559		406,465		767,142		671,860		OPERATING INCOME	51,219		43,506
OTHER INCOME (DEDUCTIONS)	OTHER INCOME (DEDUCTIONS)									OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	8,144		5,917		24,652		24,677		Allowance for equity funds used during construction	9,207		7,697
Pension and other postretirement non-service credits - net		14,334		6,133		43,017		18,389
Pension and other postretirement non-service credits — net										Pension and other postretirement non-service credits — net	27,837		14,262
Other income (Note 9)	Other income (Note 9)	13,328		14,534		38,233		32,641		Other income (Note 9)	11,960		11,633
Other expense (Note 9)	Other expense (Note 9)	(2,799)		(2,826)		(11,326)		(10,132)		Other expense (Note 9)	(3,350)		(4,668)
Total	Total	33,007		23,758		94,576		65,575		Total	45,654		28,924
INTEREST EXPENSE	INTEREST EXPENSE									INTEREST EXPENSE
Interest charges	Interest charges	59,132		53,812		171,670		164,068		Interest charges	59,388		55,736
Allowance for borrowed funds used during construction	Allowance for borrowed funds used during construction	(4,663)		(3,486)		(13,488)		(14,645)		Allowance for borrowed funds used during construction	(4,994)		(4,076)
Total	Total	54,469		50,326		158,182		149,423		Total	54,394		51,660
INCOME BEFORE INCOME TAXES	INCOME BEFORE INCOME TAXES	437,097		379,897		703,536		588,012		INCOME BEFORE INCOME TAXES	42,479		20,770
INCOME TAXES	INCOME TAXES	81,861		56,154		106,090		76,070		INCOME TAXES	2,319		(19,448)
NET INCOME	NET INCOME	355,236		323,743		597,446		511,942		NET INCOME	40,160		40,218
Less: Net income attributable to noncontrolling interests (Note 6)	Less: Net income attributable to noncontrolling interests (Note 6)	4,873		4,873		14,620		14,620		Less: Net income attributable to noncontrolling interests (Note 6)	4,873		4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	350,363	$	318,870	$	582,826	$	497,322	NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	35,287	$	35,345

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

1211

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019			2021		2020

NET INCOME	NET INCOME	$	355,236	$	323,743	$	597,446	$	511,942	NET INCOME	$	40,160	$	40,218

OTHER COMPREHENSIVE INCOME, NET OF TAX	OTHER COMPREHENSIVE INCOME, NET OF TAX									OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:	Derivative instruments:									Derivative instruments:
Net unrealized loss, net of tax benefit of $0, $0, $292 and $0		0		0		292		0
Reclassification of net realized loss, net of tax benefit of $0, $71, $481 and $313		0		218		282		950
Pension and other postretirement benefits activity, net of tax expense (benefit) of $298, $249, $174 and $(48)		900		755		823		(146)
Net unrealized gain, net of tax benefit of $0 and $292										Net unrealized gain, net of tax benefit of $0 and $292	0		292
Reclassification of net realized loss, net of tax expense of $0 and $394										Reclassification of net realized loss, net of tax expense of $0 and $394	0		20
Pension and other postretirement benefits activity, net of tax expense of $305 and $237										Pension and other postretirement benefits activity, net of tax expense of $305 and $237	927		1,013
Total other comprehensive income	Total other comprehensive income	900		973		1,397		804		Total other comprehensive income	927		1,325

COMPREHENSIVE INCOME	COMPREHENSIVE INCOME	356,136		324,716		598,843		512,746		COMPREHENSIVE INCOME	41,087		41,543
Less: Comprehensive income attributable to noncontrolling interests	Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873		14,620		14,620		Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	351,263	$	319,843	$	584,223	$	498,126	COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	36,214	$	36,670

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

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)


	March 31, 2021		December 31, 2020
ASSETS

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	20,945,129	$	20,834,424
Accumulated depreciation and amortization	(7,186,452)		(7,107,058)
Net	13,758,677		13,727,366
Construction work in progress	1,056,991		937,384
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	97,068		98,036
Intangible assets, net of accumulated amortization	278,071		282,415
Nuclear fuel, net of accumulated amortization	124,533		113,645
Total property, plant and equipment	15,315,340		15,158,846

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	1,159,699		1,138,435
Other special use funds (Notes 11 and 12)	357,506		254,509
Other assets	44,829		46,010
Total investments and other assets	1,562,034		1,438,954

CURRENT ASSETS
Cash and cash equivalents	14,536		57,310
Customer and other receivables	262,636		312,644
Accrued unbilled revenues	122,034		132,197
Allowance for doubtful accounts	(20,405)		(19,782)
Materials and supplies (at average cost)	314,702		314,745
Fossil fuel (at average cost)	24,396		19,552

Assets from risk management activities (Note 7)	22,611		2,931
Deferred fuel and purchased power regulatory asset (Note 4)	228,609		175,835
Other regulatory assets (Note 4)	111,271		115,878
Other current assets	56,987		47,593
Total current assets	1,137,377		1,158,903

DEFERRED DEBITS
Regulatory assets (Note 4)	1,135,857		1,133,987
Operating lease right-of-use assets	501,395		503,475
Assets for pension and other postretirement benefits (Note 5)	410,933		495,673
Other	35,751		34,413
Total deferred debits	2,083,936		2,167,548

TOTAL ASSETS	$	20,098,687	$	19,924,251

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

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

September 30,
2020 December 31,
2019
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use $ 20,449,975 $ 19,832,805
Accumulated depreciation and amortization (6,996,748) (6,634,597)
Net 13,453,227 13,198,208
Construction work in progress 972,024 808,133
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 99,003 101,906
Intangible assets, net of accumulated amortization 266,065 290,409
Nuclear fuel, net of accumulated amortization 128,876 123,500
Total property, plant and equipment 14,919,195 14,522,156
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12) 1,069,837 1,010,775
Other special use funds (Notes 11 and 12) 268,292 245,095
Other assets 48,393 43,781
Total investments and other assets 1,386,522 1,299,651
CURRENT ASSETS
Cash and cash equivalents 181,793 10,169
Customer and other receivables 417,362 255,479
Accrued unbilled revenues 175,341 128,165
Allowance for doubtful accounts (18,069) (8,171)
Materials and supplies (at average cost) 322,017 331,091
Fossil fuel (at average cost) 17,060 14,829
Income tax receivable 0 7,313
Assets from risk management activities (Note 7) 13,875 515
Deferred fuel and purchased power regulatory asset (Note 4) 162,111 70,137
Other regulatory assets (Note 4) 110,759 133,070
Other current assets 42,847 38,895
Total current assets 1,425,096 981,492
DEFERRED DEBITS
Regulatory assets (Note 4) 1,305,437 1,304,073
Operating lease right-of-use assets (Note 16) 501,282 144,024
Assets for other postretirement benefits (Note 5) 101,792 86,736
Other 27,592 32,591
Total deferred debits 1,936,103 1,567,424
TOTAL ASSETS $ 19,666,916 $ 18,370,723

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

~~ARIZONA PUBLIC SERVICE COMPANY~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~(unaudited)~~

~~(dollars in thousands)~~


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY

CAPITALIZATION	CAPITALIZATION					CAPITALIZATION
Common stock	Common stock	$	178,162	$	178,162	Common stock	$	178,162	$	178,162
Additional paid-in capital	Additional paid-in capital	2,721,696		2,721,696		Additional paid-in capital	2,871,696		2,871,696
Retained earnings	Retained earnings	3,418,753		3,011,927		Retained earnings	3,252,244		3,216,955
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(34,125)		(35,522)		Accumulated other comprehensive loss	(39,991)		(40,918)
Total shareholder equity	Total shareholder equity	6,284,486		5,876,263		Total shareholder equity	6,262,111		6,225,895
Noncontrolling interests (Note 6)	Noncontrolling interests (Note 6)	125,789		122,540		Noncontrolling interests (Note 6)	124,164		119,290
Total equity	Total equity	6,410,275		5,998,803		Total equity	6,386,275		6,345,185
Long-term debt less current maturities (Note 3)	Long-term debt less current maturities (Note 3)	5,820,303		4,833,133		Long-term debt less current maturities (Note 3)	5,818,520		5,817,945
Total capitalization	Total capitalization	12,230,578		10,831,936		Total capitalization	12,204,795		12,163,130
CURRENT LIABILITIES	CURRENT LIABILITIES					CURRENT LIABILITIES

Current maturities of long-term debt (Note 3)		0		350,000

Short-term borrowings (Note 3)						Short-term borrowings (Note 3)	199,500		0
Accounts payable	Accounts payable	282,868		338,006		Accounts payable	301,675		311,699
Accrued taxes	Accrued taxes	268,990		136,328		Accrued taxes	211,174		148,970
Accrued interest	Accrued interest	58,403		52,619		Accrued interest	56,454		56,322
Common dividends payable	Common dividends payable	0		88,000		Common dividends payable	0		93,500
Customer deposits	Customer deposits	47,730		64,908		Customer deposits	45,170		48,340
Liabilities from risk management activities (Note 7)	Liabilities from risk management activities (Note 7)	4,266		38,946		Liabilities from risk management activities (Note 7)	3,067		7,557
Liabilities for asset retirements	Liabilities for asset retirements	12,226		11,025		Liabilities for asset retirements	16,021		15,586

Operating lease liabilities (Note 16)		88,975		12,549
Operating lease liabilities						Operating lease liabilities	74,235		74,695
Regulatory liabilities (Note 4)	Regulatory liabilities (Note 4)	308,019		234,912		Regulatory liabilities (Note 4)	250,228		229,088
Other current liabilities	Other current liabilities	153,986		164,736		Other current liabilities	152,290		190,420
Total current liabilities	Total current liabilities	1,225,463		1,492,029		Total current liabilities	1,309,814		1,176,177
DEFERRED CREDITS AND OTHER	DEFERRED CREDITS AND OTHER					DEFERRED CREDITS AND OTHER
Deferred income taxes	Deferred income taxes	2,166,599		2,033,096		Deferred income taxes	2,150,668		2,143,673
Regulatory liabilities (Note 4)	Regulatory liabilities (Note 4)	2,079,323		2,267,835		Regulatory liabilities (Note 4)	2,427,769		2,450,169
Liabilities for asset retirements	Liabilities for asset retirements	674,025		646,193		Liabilities for asset retirements	693,383		689,497
Liabilities for pension benefits (Note 5)	Liabilities for pension benefits (Note 5)	161,186		262,243		Liabilities for pension benefits (Note 5)	147,235		148,943
Liabilities from risk management activities (Note 7)	Liabilities from risk management activities (Note 7)	9,092		33,186		Liabilities from risk management activities (Note 7)	6,928		11,062
Customer advances	Customer advances	224,924		215,330		Customer advances	220,999		221,032
Coal mine reclamation	Coal mine reclamation	168,997		165,695		Coal mine reclamation	171,227		170,097
Deferred investment tax credit	Deferred investment tax credit	187,926		196,468		Deferred investment tax credit	190,842		191,372
Unrecognized tax benefits	Unrecognized tax benefits	39,589		40,188		Unrecognized tax benefits	39,863		39,410
Operating lease liabilities (Note 16)		356,783		50,092
Operating lease liabilities						Operating lease liabilities	358,840		359,653
Other	Other	142,431		136,432		Other	176,324		160,036
Total deferred credits and other	Total deferred credits and other	6,210,875		6,046,758		Total deferred credits and other	6,584,078		6,584,944
COMMITMENTS AND CONTINGENCIES (NOTE 8)	COMMITMENTS AND CONTINGENCIES (NOTE 8)					COMMITMENTS AND CONTINGENCIES (NOTE 8)	0		0
TOTAL LIABILITIES AND EQUITY	TOTAL LIABILITIES AND EQUITY	$	19,666,916	$	18,370,723	TOTAL LIABILITIES AND EQUITY	$	20,098,687	$	19,924,251

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

1514

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
CASH FLOWS FROM OPERATING ACTIVITIES	CASH FLOWS FROM OPERATING ACTIVITIES					CASH FLOWS FROM OPERATING ACTIVITIES
Net income	Net income	$	597,446	$	511,942	Net income	$	40,160	$	40,218
Adjustments to reconcile net income to net cash provided by operating activities:	Adjustments to reconcile net income to net cash provided by operating activities:					Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	Depreciation and amortization including nuclear fuel	515,679		500,737		Depreciation and amortization including nuclear fuel	176,389		173,147
Deferred fuel and purchased power	Deferred fuel and purchased power	(82,679)		(60,911)		Deferred fuel and purchased power	(52,210)		(5,785)
Deferred fuel and purchased power amortization	Deferred fuel and purchased power amortization	(9,295)		38,601		Deferred fuel and purchased power amortization	(564)		(1,808)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(24,652)		(24,677)		Allowance for equity funds used during construction	(9,207)		(7,697)
Deferred income taxes	Deferred income taxes	52,795		97,002		Deferred income taxes	(2,616)		(17,782)
Deferred investment tax credit	Deferred investment tax credit	(8,541)		(7,288)		Deferred investment tax credit	(529)		(465)

Changes in current assets and liabilities:	Changes in current assets and liabilities:					Changes in current assets and liabilities:
Customer and other receivables	Customer and other receivables	(129,892)		(90,817)		Customer and other receivables	50,103		15,045
Accrued unbilled revenues	Accrued unbilled revenues	(47,176)		(18,666)		Accrued unbilled revenues	10,163		34,731
Materials, supplies and fossil fuel	Materials, supplies and fossil fuel	6,843		(18,332)		Materials, supplies and fossil fuel	(4,801)		5,445
Income tax receivable	Income tax receivable	7,313		(15,982)		Income tax receivable	0		(1,411)
Other current assets	Other current assets	(18,512)		(8,642)		Other current assets	(8,825)		(18,164)
Accounts payable	Accounts payable	(3,355)		37,004		Accounts payable	23,881		(4,038)
Accrued taxes	Accrued taxes	132,662		38,963		Accrued taxes	62,204		54,243
Other current liabilities	Other current liabilities	7,981		(66,368)		Other current liabilities	(43,917)		(49,149)

Change in other long-term assets	Change in other long-term assets	(9,478)		(54,872)		Change in other long-term assets	(36,626)		82,178
Change in other long-term liabilities	Change in other long-term liabilities	(216,308)		(27,521)		Change in other long-term liabilities	(642)		(105,117)
Net cash flow provided by operating activities	Net cash flow provided by operating activities	770,831		830,173		Net cash flow provided by operating activities	202,963		193,591
CASH FLOWS FROM INVESTING ACTIVITIES	CASH FLOWS FROM INVESTING ACTIVITIES					CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	Capital expenditures	(971,052)		(857,883)		Capital expenditures	(363,775)		(340,014)
Contributions in aid of construction	Contributions in aid of construction	41,457		34,121		Contributions in aid of construction	15,296		3,152
Allowance for borrowed funds used during construction	Allowance for borrowed funds used during construction	(13,488)		(14,645)		Allowance for borrowed funds used during construction	(4,994)		(4,076)
Proceeds from nuclear decommissioning trust sales and other special use funds	Proceeds from nuclear decommissioning trust sales and other special use funds	607,885		520,996		Proceeds from nuclear decommissioning trust sales and other special use funds	379,978		195,087
Investment in nuclear decommissioning trust and other special use funds	Investment in nuclear decommissioning trust and other special use funds	(624,249)		(523,573)		Investment in nuclear decommissioning trust and other special use funds	(380,548)		(195,658)
Other	Other	(1,260)		(3,563)		Other	2,306		(900)
Net cash flow used for investing activities	Net cash flow used for investing activities	(960,707)		(844,547)		Net cash flow used for investing activities	(351,737)		(342,409)
CASH FLOWS FROM FINANCING ACTIVITIES	CASH FLOWS FROM FINANCING ACTIVITIES					CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		986,872		794,981
Short-term borrowings and payments — net		0		2,900

Short-term borrowings and (repayments) — net						Short-term borrowings and (repayments) — net	199,500		0
Short-term debt borrowings under revolving credit facility	Short-term debt borrowings under revolving credit facility	540,000		0		Short-term debt borrowings under revolving credit facility	0		540,000
Short-term debt repayments under revolving credit facility	Short-term debt repayments under revolving credit facility	(540,000)		0		Short-term debt repayments under revolving credit facility	0		(110,000)
Repayment of long-term debt	Repayment of long-term debt	(350,000)		(500,000)		Repayment of long-term debt	0		(150,000)
Dividends paid on common stock	Dividends paid on common stock	(264,000)		(248,300)		Dividends paid on common stock	(93,500)		(88,000)
Distributions to noncontrolling interests		(11,372)		(11,372)

Net cash flow provided by financing activities	Net cash flow provided by financing activities	361,500		38,209		Net cash flow provided by financing activities	106,000		192,000
NET INCREASE IN CASH AND CASH EQUIVALENTS		171,624		23,835
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(42,774)		43,182
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	10,169		5,707		CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	57,310		10,169
CASH AND CASH EQUIVALENTS AT END OF PERIOD	CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	181,793	$	29,542	CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	14,536	$	53,351

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

1615

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)


		Three Months Ended September 30, 2020														Three Months Ended March 31, 2021
		Common Stock			Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total			Common Stock			Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
		Shares	Amount													Shares	Amount
Balance, July 1, 2020		71,264,947	$	178,162	$	2,721,696	$	3,068,389	$	(35,025)	$	120,915	$	6,054,137
Balance, January, 2021															Balance, January, 2021	71,264,947	$	178,162	$	2,871,696	$	3,216,955	$	(40,918)	$	119,290	$	6,345,185
Net Income	Net Income		—		—		350,363		—		4,873		355,236		Net Income		—		—		35,287		—		4,873		40,160
Other comprehensive income	Other comprehensive income		—		—		—		900		—		900		Other comprehensive income		—		—		—		927		—		927
Other	Other		—		—		1		—		1		2		Other		—		—		2		—		1		3
Balance, September 30, 2020		71,264,947	$	178,162	$	2,721,696	$	3,418,753	$	(34,125)	$	125,789	$	6,410,275
Balance, March 31, 2021															Balance, March 31, 2021	71,264,947	$	178,162	$	2,871,696	$	3,252,244	$	(39,991)	$	124,164	$	6,386,275

Three Months Ended September 30, 2019
Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount
Balance, July 1, 2019 71,264,947 $ 178,162 $ 2,721,696 $ 2,801,110 $ (27,276) $ 124,165 $ 5,797,857
Net Income — — 318,870 — 4,873 323,743
Other comprehensive income — — — 973 — 973
Other — — (3) — 1 (2)
Balance, September 30, 2019 71,264,947 $ 178,162 $ 2,721,696 $ 3,119,977 $ (26,303) $ 129,039 $ 6,122,571


	Three Months Ended March 31, 2020
	Common Stock			Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
	Shares	Amount
Balance, January 1, 2020	71,264,947	$	178,162	$	2,721,696	$	3,011,927	$	(35,522)	$	122,540	$	5,998,803
Net Income		—		—		35,345		—		4,873		40,218
Other comprehensive income		—		—		—		1,325		—		1,325
Other						(3)				1		(2)
Balance, March 31, 2020	71,264,947	$	178,162	$	2,721,696	$	3,047,269	$	(34,197)	$	127,414	$	6,040,344

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

~~ARIZONA PUBLIC SERVICE COMPANY~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY~~

~~(unaudited)~~

~~(dollars in thousands)~~

Nine Months Ended September 30, 2020
Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount
Balance, January 1, 2020 71,264,947 $ 178,162 $ 2,721,696 $ 3,011,927 $ (35,522) $ 122,540 $ 5,998,803
Net Income — — 582,826 — 14,620 597,446
Other comprehensive income — — — 1,397 — 1,397
Dividends on common stock — — (176,000) — — (176,000)
Capital activities by noncontrolling activities (11,372) (11,372)
Other — — 0 — 1 1
Balance, September 30, 2020 71,264,947 $ 178,162 $ 2,721,696 $ 3,418,753 $ (34,125) $ 125,789 $ 6,410,275

Nine Months Ended September 30, 2019
Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount
Balance, January 1, 2019 71,264,947 $ 178,162 $ 2,721,696 $ 2,788,256 $ (27,107) $ 125,790 $ 5,786,797
Net Income — — 497,322 — 14,620 511,942
Other comprehensive income — — — 804 — 804
Dividends on common stock — — (165,600) — — (165,600)
Capital activities by noncontrolling activities — — — — (11,372) (11,372)
Other (1) 1 0
Balance, September 30, 2019 71,264,947 $ 178,162 $ 2,721,696 $ 3,119,977 $ (26,303) $ 129,039 $ 6,122,571

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

1816

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, 4C Acquisition, LLC ~~("4CA"~~(“4CA”), Bright Canyon Energy Corporation ~~("BCE"~~(“BCE”) and El Dorado Investment Company ("(“El ~~Dorado"~~Dorado”). See Note 8 for more information on 4CA matters. Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Generating Station ("(“Palo ~~Verde"~~Verde”) sale leaseback variable interest entities ~~("VIEs"~~(“VIEs”) (see Note 6 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ~~("GAAP"~~(“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.

Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units ~~("EGU"~~(“EGU”), and other factors.

Our condensed 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. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our ~~2019~~2020 Form 10-K.

On June 30, 2020, the United States Federal Energy Regulatory Commission ~~("FERC"~~(“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction ~~("AFUDC"~~(“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021. On February 23, 2021, this waiver was extended until September 30, 2021. 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 both 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 will not have a material impact on our financial statements. See Note 1 in our ~~2019~~2020 Form 10-K for information on the accounting treatment for AFUDC.

1917

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
Cash paid during the period for:	Cash paid during the period for:					Cash paid during the period for:
Income taxes, net of refunds	Income taxes, net of refunds	$	(3,028)	$	12,488	Income taxes, net of refunds	$	(827)	$	(3,002)
Interest, net of amounts capitalized	Interest, net of amounts capitalized	155,623		166,907		Interest, net of amounts capitalized	53,885		53,723
Significant non-cash investing and financing activities:	Significant non-cash investing and financing activities:					Significant non-cash investing and financing activities:
Accrued capital expenditures	Accrued capital expenditures	$	84,022	$	85,099	Accrued capital expenditures	$	79,597	$	100,868
Right-of-use operating lease assets obtained in exchange for operating lease liabilities						Right-of-use operating lease assets obtained in exchange for operating lease liabilities	785		2,311

The following table summarizes supplemental APS cash flow information (dollars in thousands):

Nine Months Ended
September 30,
2020 2019
Cash paid during the period for:
Income taxes, net of refunds $ 0 $ 35,573
Interest, net of amounts capitalized 148,713 157,593
Significant non-cash investing and financing activities:
Accrued capital expenditures $ 84,022 $ 85,099

~~See Note 16 for cash flow information relating to lease activities.~~


	Three Months Ended March 31,
	2021		2020
Cash paid during the period for:
Income taxes, net of refunds	$	0	$	0
Interest, net of amounts capitalized	53,153		52,034
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	79,597	$	100,868
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	785		2,311

2. Revenue

Sources of Revenue

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Retail Electric Revenue	Retail Electric Revenue									Retail Electric Revenue
Residential	Residential	$	726,231	$	668,467	$	1,566,432	$	1,452,601	Residential		$	340,838	$	325,073
Non-Residential	Non-Residential	461,168		465,602		1,145,640		1,194,199		Non-Residential		314,783		303,351
Wholesale energy sales		45,631		36,775		76,226		95,218
Transmission services for others		18,000		15,841		48,693		46,247
Other sources		3,471		4,102		9,030		12,553
Wholesale Energy Sales										Wholesale Energy Sales		17,597		14,668
Transmission Services for Others										Transmission Services for Others		18,993		15,927
Other Sources										Other Sources		4,264		2,911
Total operating revenues	Total operating revenues	$	1,254,501	$	1,190,787	$	2,846,021	$	2,800,818	Total operating revenues		$	696,475	$	661,930

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Retail Electric Revenue. Pinnacle ~~West's~~West’s retail electric revenue is generated by wholly-owned regulated subsidiary ~~APS's~~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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

sales to individual customers is based on the reading of their meters. We obtain ~~customers'~~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 15 days of when the services are billed. See ~~"Allowance~~“Allowance for Doubtful ~~Accounts"~~Accounts” discussion below for additional details regarding payment terms.

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'~~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.

In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

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 three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020 were ~~$1,244~~$682 million and ~~$2,806 million, respectively, and for the three and nine months ended September 30, 2019 were $1,178 million and $2,756~~$648 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 three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, our revenues that do not qualify as revenue from contracts with customers were ~~$11~~$14 million and ~~$40 million, respectively, and for the three and nine months ended September 30, 2019 were $13 million and $45~~$14 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 Condensed Consolidated Balance Sheets as of ~~September 30, 2020~~March 31, 2021 or December 31, ~~2019.~~2020.

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.

2119

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~During~~

On March 13, 2020, due to the COVID-19 pandemic ~~and to assist customers who may be experiencing economic difficulties,~~ we voluntarily suspended ~~all service shut-offs due to nonpayment. We may experience an increase in the number~~disconnections of customers ~~needing to utilize longer-term payment plans to avoid service disruption. These changes, among others, including~~for nonpayment. The suspension of customer disconnections was extended from March 13, 2020 through December 31, 2020. Our disconnection policies are also impacted by the Summer Disconnection ~~Moratorium (defined in Note 4),~~Moratorium.The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and certain customers with past due balances were placed on eight-month payment arrangements. These circumstances and the on-going COVID-19 pandemic have impacted our allowance for doubtful accounts, including our write-off factor. ~~On September 14, 2020, APS extended the suspension of disconnection of customers for nonpayment and waiver of late payment fees related to COVID-19 until December 31, 2020.~~ We ~~will~~ continue to monitor the impacts of COVID-19, ~~and~~ our disconnection policies, onpayment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts. See Note 4 for additional details.

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


		Nine Months Ended September 30, 2020		Twelve Months Ended December 31, 2019			March 31, 2021		December 31, 2020
Allowance for doubtful accounts, balance at beginning of period	Allowance for doubtful accounts, balance at beginning of period	$	8,171	$	4,069	Allowance for doubtful accounts, balance at beginning of period	$	19,782	$	8,171
Bad debt expense	Bad debt expense	17,399		11,819		Bad debt expense	4,151		20,633
Actual write-offs	Actual write-offs	(7,501)		(7,717)		Actual write-offs	(3,528)		(9,022)
Allowance for doubtful accounts, balance at end of period	Allowance for doubtful accounts, balance at end of period	$	18,069	$	8,171	Allowance for doubtful accounts, balance at end of period	$	20,405	$	19,782

3. Long-Term Debt and Liquidity Matters

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.

Pinnacle West

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement ~~that would have matured on May 7, 2020~~ with a new 364-day $31 million term loan agreement that ~~matures~~would have matured May 4, 2021. Borrowings under the agreement ~~bear~~bore interest at Eurodollar Rate plus 1.40% per annum. At ~~September 30, 2020,~~March 31, 2021, Pinnacle West had ~~$24~~$15 million in outstanding borrowings under the current ~~agreement.~~agreement, all of which was repaid on April 27, 2021.

On ~~June 17,~~December 23, 2020, Pinnacle West ~~issued $500 million of 1.3% unsecured senior notes that mature June 15, 2025. The net proceeds from the sale were used to repay early its~~entered into a $150 million term loan facility ~~set to mature~~that matures June 2022. The proceeds were received on ~~December 21, 2020, to repay short-term indebtedness consisting of commercial paper~~January 4, 2021 and ~~replenish cash incurred or~~ used ~~to fund capital expenditures, to redeem prior to maturity our $300 million, 2.25% senior notes due November 30, 2020, and~~ for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.

At ~~September 30, 2020,~~March 31, 2021, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. 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~~West’s senior unsecured debt credit ratings. The facility is available to support Pinnacle ~~West's~~West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At ~~September 30, 2020,~~March 31, 2021, Pinnacle West had 0 outstanding borrowings under its credit facility, 0 letters of credit outstanding and ~~$34~~$0.3 million inof outstanding commercial paper borrowings.

2220

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS

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

On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050. The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.

At ~~September 30, 2020,~~March 31, 2021, APS had 2 revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s ~~$500~~$750 million commercial paper program, for bank borrowings or for issuances of letters of credit. At ~~September 30, 2020,~~March 31, 2021, APS had 0 outstanding borrowings under its revolving credit facilities, no0 letters of credit outstanding, and no$199.5 million of outstanding commercial paper borrowings.

On ~~November 27, 2018,~~December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of ~~$5.9~~$7.5 billion. On March 27, 2020, APS filed an application with the ACC to increase the long-term debt limit from $5.9 billion to $7.5 billion and to continue its authorization of short-term debt granted in the 2018 financing order. This application is pending ACC review and approval.

See ~~"Financial Assurances"~~“Financial Assurances” in Note 8 for a discussion of other outstanding letters of credit.

Debt Fair Value

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


		As of September 30, 2020				As of December 31, 2019					As of March 31, 2021				As of December 31, 2020
		Carrying Amount		Fair Value		Carrying Amount		Fair Value			Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	Pinnacle West	$	496,117	$	507,500	$	449,425	$	450,822	Pinnacle West	$	646,525	$	653,395	$	496,321	$	509,050
APS	APS	5,820,303		6,886,108		5,183,133		5,743,570		APS	5,818,520		6,436,224		5,817,945		7,103,791
Total	Total	$	6,316,420	$	7,393,608	$	5,632,558	$	6,194,392	Total	$	6,465,045	$	7,089,619	$	6,314,266	$	7,612,841

2321

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. Regulatory Matters

COVID-19 Pandemic

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. ~~In addition, APS waived all late payment fees during this current suspension period. On September 14, 2020, APS extended this~~The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and ~~waiver~~customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until ~~December 31, 2020.~~October 15, 2021. APS ~~currently estimates that the Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic~~has experienced and ~~the increased bad debt expense associated with both events will result in a negative impact~~is continuing to its 2020 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. APS is experiencingexperience an increase in bad debt expense associated with the COVID-19 pandemic, ~~but it still believes that costs associated with~~ the Summer Disconnection Moratorium (defined below) and the ~~COVID-19 disconnection suspensions and~~ related ~~bad debt expense with both events will fall within this estimated $20 million to $30 million range. These estimated impact amounts depend on certain current assumptions, including, but not limited to,~~write-offs of customer ~~behaviors, population and employment growth, and the impacts of COVID-19 on the economy. Additionally, due~~delinquent accounts. Due to COVID-19, APS also delayed the reset of the Environmental Improvement Surcharge ~~("EIS"~~(“EIS”) adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April ~~2020 (see~~2020. In February 2021, APS delayed the annual reset of the PSA. Rather than the increase being effective February 2021, the PSA reset will be implemented with 50% of the increase effective April 2021 and the remaining 50% increase effective November 2021 (see below for discussion of EIS, ~~and~~ TEAM Phase ~~II)~~II and PSA).

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 Demand Side Management ~~("DSM"~~(“DSM”) Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. ~~As of September 30, 2020,~~ APS ~~had~~has refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings (see below for discussion of the DSM Adjustor Charge).

In 2020, APS ~~has committed a total of approximately $8~~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 ~~$6.8~~$12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund iswas comprised of ~~$5.3 million~~a series of ~~non-ratepayer~~voluntary commitments of funds that ~~APS voluntarily~~are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the ACC that it would contribute to providing assistance to residential and non-residential customers that have been impacted by the COVID-19 pandemic and $1.5 million that APS had already provided to assist customers with a one-time credit of $100 on their bill.remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund ~~are~~were programs that ~~assist~~assisted customers that ~~have~~had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers ~~that have a delinquency of two or more months~~ 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. ~~Limited~~The December 2020 ACC order further assisted delinquent limited income customers ~~can qualify for assistance without restriction on the timing~~with an additional bill credit of ~~past due amounts. As of October 21, 2020,~~up to $250 or their delinquent balance, whichever was less. APS ~~had~~has distributed ~~$4.3 million~~all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS has also provided ~~$1.25~~$2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.

2422

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2019 Retail Rate Case Filing with the Arizona Corporation Commission

In accordance with the requirements of the ~~2018~~2019 rate review order described below, APS filed an application with the ACC on October 31, 2019 seeking an ~~annual~~ 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"~~(“SCR”) project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the Tax Expense Adjustment Mechanism ~~("TEAM"~~(“TEAM”). The proposed total annual revenue increase in ~~APS's~~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~~APS’s application ~~are:~~were:

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

•an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•the following proposed capital structure and costs of capital:


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

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

•a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs ("(“Base Fuel ~~Rate"~~Rate”);

•authorization to defer until ~~APS's~~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~~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 Generating Station (the ~~"Navajo Plant"~~“Navajo Plant”) (see ~~"Navajo Plant"~~“Navajo Plant” below).

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

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case. The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommends, among other things, a (i) $20.8 million

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

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 ~~is continuing to assess all~~ 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 (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components: (i) $100 million that will ~~file rebuttal testimony with updated positions no later than November 6, 2020.~~be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers. The ~~hearing for this rate case was delayed, at the request~~commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials.

On December 4, 2020, the ACC Staff and ~~RUCO,~~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 schedule concluded on April 30, 2021. In May 2021, the ACC will be discussing whether to re-open the evidentiary record in APS’s pending rate case to take additional evidence on topics raised by certain ACC Commissioners, including adjustor cost recovery mechanisms. APS believes that the rate case record is ~~currently scheduled~~sufficient, and adjustors provide substantial benefits to ~~begin December 14, 2020.~~customers by supporting critical programs and reflecting changes in utility costs that can be promptly passed along to customers. Pending this decision, the next steps in this rate case are that the Administrative Law Judge will issue a Recommended Order and Opinion and then the ACC will review and consider the matter, which is anticipated to be in the third quarter of 2021. Unfavorable ACC Staff and intervenor positions and recommendations, including modifications or elimination of APS's adjustor cost recovery mechanisms could have a material impact toon APS’s financial statements if ultimately ~~adopted.~~adopted by the ACC. APS cannot predict the outcome or timing of this proceeding.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2016 Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, RUCO, limited income advocates and private rooftop solar organizations signed a settlement agreement (the ~~"2017~~“2017 Settlement ~~Agreement"~~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. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the agreement include the following:

•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 the Four Corners Power Plant ("(“Four ~~Corners"~~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 Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party energy storage costs;

•a new AZ Sun II program (now known as ~~"APS~~“APS Solar ~~Communities"~~Communities”) for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ~~("RES"~~(“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-7 p.m. to 3 p.m.-8 p.m. Monday through Friday, excluding holidays;

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

▪non-grandfathered distributed generation ~~("DG"~~(“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.

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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On August 15, 2017, the ACC approved (by a vote of 4-1) the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the ~~"2017~~“2017 Rate Case ~~Decision"~~Decision”), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”). The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The ACC held a hearing on this matter, and the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC adopted the Administrative Law ~~Judge's~~Judge’s amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

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

ACC Review of APS 2017 Rate Case Decision

On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision. Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision.

On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following:

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

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

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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

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

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

•APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

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APS filed its rate case on October 31, 2019 (see ~~"2019~~“2019 Retail Rate Case Filing with the Arizona Corporation ~~Commission"~~Commission” above for more information). APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows.

On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision. On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning. The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable. Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened. On June 18, 2020, at an ACC Open Meeting, the matters raised in these letters were discussed. The ACC did not vote to move forward with any adjustments to APS’s current rates. ~~APS is monitoring~~On November 4, 2020, the ACC voted to administratively close this matter, but believes that the proposals are not legal and further that APS has not over-earned. APS cannot predict the outcome of this matter at this time or whether or how further action may be taken by the ACC.docket.

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

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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 June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.

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

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systems. Recovery of the costs associated with the pilot will be addressed in the 2021 Demand Side Management Implementation Plan ("(“DSM ~~Plan"~~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 residential distributed energy requirement for 2021 contained in the RES rules. 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. The ACC has not yet ruled on the 2021 RES Implementation Plan.

On July ~~15,~~30, 2020, ACC Staff issued final draft rules which, if approved, 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. APS cannot predict the outcome of this matter. See ~~"Energy~~“Energy Modernization ~~Plan"~~Plan” below for more information.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan annually for review by and approval of the ACC. Verified energy savings from ~~APS's~~APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its Lost Fixed Cost Recovery (“LFCR”) mechanism (see below for discussion of the LFCR).

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

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electrification strategies. The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. ~~As of September 30, 2020,~~ APS ~~had~~has refunded approximately $43 million to customers. The additional $7 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings. See ~~"COVID-19 Pandemic"~~“COVID-19 Pandemic” above for more information.

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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 approved in the 2020 RES Implementation Plan. The ACC has not yet ruled on the amended APS 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 has not ruled on this request.

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 following table shows the changes in the deferred fuel and purchased power regulatory asset for ~~2020~~2021 and ~~2019~~2020 (dollars in thousands):


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
Beginning balance	Beginning balance	$	70,137	$	37,164	Beginning balance	$	175,835	$	70,137
Deferred fuel and purchased power costs — current period	Deferred fuel and purchased power costs — current period	82,679		60,911		Deferred fuel and purchased power costs — current period	52,210		5,785
Amounts refunded/(charged) to customers		9,295		(38,601)
Amounts refunded to customers						Amounts refunded to customers	564		1,808
Ending balance	Ending balance	$	162,111	$	59,474	Ending balance	$	228,609	$	77,730

The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a forward component of $0.002009 per kWh and a historical component of $0.002546 per kWh. This represented a $0.004 per kWh increase over the August 19, 2017 PSA, the maximum permitted under the Plan of Administration for the PSA. This left $16.4 million of 2017 fuel and purchased power costs above this annual cap. These costs rolled over into the following year and were reflected in the 2019 reset of the PSA.

The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, ~~consisting~~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 and 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 and consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase, compared to the 2020 PSA year. These rates were to be effective on February 1, 2021 but APS delayed the effectiveness of these rates until the first billing cycle of April 2021 due to concerns of the impact on customers during COVID-19. In March 2021, the ACC voted to implement the 2021 PSA, with 50% of the rate increase effective in April 2021 and the remaining 50% of the increase effective in November 2021. The PSA rate implemented was $0.001544 per kWh and consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh. As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit to better understand the factors that contributed to the increase.

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to 2 energy storage power purchase tolling agreements through the PSA. ~~This application is pending with~~On December 29, 2020, the ~~ACC. APS cannot predict~~ACC Staff filed its report and recommended the ~~outcome of~~storage costs be included in the PSA once the systems are in-service. On January 12, 2021, the ACC approved this ~~matter.~~application.

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Environmental Improvement Surcharge. The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with

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environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. A filing is made on or before February 1 for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC. There is an overall cap of $0.0005 per kWh (approximately $13 million to $14 million per year). APS’s February 1, ~~2020~~2021 application requested an increase in the charge to ~~$8.75~~$10.3 million, or ~~$2.0~~$1.5 million over the prior-period charge ~~in effect for the 2019-2020 rate~~and it became effective ~~year. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the reset of the EIS adjustor to~~with the first billing cycle in ~~May 2020 rather than~~ April ~~2020.~~2021.

Transmission Rates, Transmission Cost Adjustor ~~("TCA"~~(“TCA”) 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~~APS’s retail customers ("(“Retail Transmission ~~Charges"~~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~~APS’s rate case ("(“2012 Settlement ~~Agreement"~~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~~APS’s actual cost of service, as disclosed in ~~APS's~~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. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Cuts and Jobs Act ("(“Tax ~~Act"~~Act”) beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. On March 17, 2020, APS made a filing to make further modifications to its annual transmission formula to provide additional transparency for excess and deficient Accumulated Deferred Income Taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes. This filing is pending with FERC.

Effective June 1, 2018, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC-approved formula. Of this amount, retail customer rates decreased by approximately $26.9 million. An adjustment to2019, APS’s ~~retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018.~~

~~Effective June 1, 2019, APS's~~ annual wholesale transmission rates for all users of its transmission system increased by approximately $25.8 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. Of this amount, retail customer rates increased by approximately $4.7 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

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Effective June 1, 2020, ~~APS's~~APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $6.1 million for the twelve-month period beginning June 1, 2020 in accordance with the FERC-approved formula. Of this amount, retail customer rates decreased by approximately $10.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.

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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 are currently 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement. The LFCR adjustment has a year-over-year cap of 1% 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, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million. On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). 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 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 requested as part of APS’s next LFCR application filing in 2022. The ACC has not yet released its order on this matter. APS does not anticipate that the order will have a material impact on its financial position, results of operations and cash flows.

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~~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 January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit ("(“TEAM Phase I"I”). On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

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

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On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020. Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be addressed for recovery as part of ~~APS's~~APS’s 2019 ACC 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 benefit of $39.5 million to customers through December 31, 2020. ~~It is currently anticipated that benefits related~~On November 20, 2020, APS filed an application to continue the ~~amortization~~TEAM Phase III monthly bill credit through the earlier of ~~depreciation related excess deferred taxes for periods beginning after~~ December 31, ~~2020 will be fully incorporated into~~2021, or at the conclusion of APS’s 2019 pending 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.

Net Metering

~~APS's~~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~~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~~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~~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~~customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

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

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018. This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019. 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

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annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export

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

On January 23, 2017, The Alliance for Solar Choice ~~("TASC"~~(“TASC”) sought rehearing of the ~~ACC's~~ACC’s decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

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

Subpoena from Former Arizona Corporation Commissioner Robert Burns

On August 25, 2016, ~~Commissioner~~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.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay ~~APS's~~APS’s obligations to comply with the subpoenas and decline to decide ~~APS's~~APS’s motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that ~~Commissioner~~ Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, ~~Commissioner~~ Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff. As part of this docket, ~~Commissioner~~ Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, ~~Commissioner~~ Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss ~~Commissioner Burns'~~Burns’ suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered ~~Commissioner~~ Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.

On August 4, 2017, ~~Commissioner~~ Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the

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~~2018, the~~ Superior Court dismissed ~~Commissioner~~ Burns’ amended complaint. On March 6, 2018, ~~Commissioner~~ Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted ~~Commissioner~~ Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. ~~Commissioner~~ Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019.

On February 13, 2019, ~~Commissioner~~ Burns filed a notice of appeal. On July 12, 2019, ~~Commissioner~~ Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The Arizona Court of Appeals originally granted the request for oral argument; however, on March 31, 2020, the court vacated the date scheduled for oral argument given the COVID-19 pandemic. The court determined that the matter could be submitted without oral argument and has taken the matter under advisement and will issue a decision without oral argument.

Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. Both APS and the ACC filed responses opposing the motion and asserting that the matter is moot. Pinnacle West and APS cannot predict the outcome of this matter.

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS, including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters. The ~~Company's~~Company’s CEO, Mr. Guldner, appeared at the ~~ACC's~~ACC’s January 14, 2020 Open Meeting regarding ACC ~~Commissioners'~~Commissioners’ questions about political spending. Mr. Guldner committed to the ACC that, during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.

Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan ~~("IRP"~~(“IRP”) process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed

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generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics.

On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020. At the March 11-12, 2020 workshop, the ACC Staff committed to filing a final draft of proposed rules by July 2020. On July 30, 2020, the ACC Staff issued final draft energy rules which ~~propose~~proposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear is defined as a clean energy resource. The proposed

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

rules also require 50% of retail energy served be renewable by the end of 2035. A new energy efficiency standard was not included in the proposed rules. APS would be required to obtain approval of its action plan included in its IRP and seek recovery of prudently incurred costs in a rate process. If approved by the ACC Commissioners, the rules would require utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023. In addition, the ACC Staff proposed changing the IRP planning horizon from 15 years to 10 years.

The ACC has discussed the final draft energy rules at several different meetings in 2020. On October 14, 2020, the ACC passed one amendment to ACC Staff’s final draft energy rules ~~which~~that will require electric utilities to obtain 35% of peak load (as measured in 2020) by 2030 from DSM resources, including traditional energy efficiency, demand response and other programs aimed at reducing energy usage, peak demand management and load shifting. This standard aligns with the proposed rules’ three-year resource planning cycle and allows recovery of costs through existing mechanisms until the ACC issues a decision in a future rate ~~process.~~proceeding. On October 29, 2020, the ACC approved an amendment ~~which~~that will require electric utilities to reduce their carbon emissions over 2016-2018 levels by 50% by 2032; 75% by 2040; and 100% by 2050. The ACC also approved an amendment ~~which~~that will require utilities to install energy storage systems with an aggregate capacity equal to 5% of each utility’s 2020 peak demand by 2035, of which 40% ~~shall~~must be derived from customer-owned or customer-leased distributed storage. Another approved amendment modifies the resource planning process, including requirements for the ACC to approve a utility’s load forecast and resource plan, and for a utility to perform an all-source request for information to guide its resource plan. ~~The~~On November 13, 2020, the ACC ~~must vote to approve~~approved a final draft energy rules ~~package,~~package. On April 19, 2021, the Administrative Law Judge issued a Recommended Order and ~~additional procedural steps in~~Opinion on the ~~rulemaking process are required~~final energy rules and the ACC will need to ~~be completed~~review and approve the Recommended Order and Opinion before the rules ~~may~~will take effect. 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. In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans. APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows. Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020. On February 20, 2020, the ACC extended the deadline for all utilities to file their IRP’s from April 1, 2020 to June 26, 2020. On 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 March 2021, the ACC Staff requested additional time to prepare its assessment of utility IRPs. The ACC has taken no action on APS’s IRP. APS cannot predict the outcome of this matter. See ~~"Energy~~“Energy Modernization ~~Plan"~~Plan” above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act ~~("PURPA")~~

~~In August 2016, APS filed an application requesting that all~~Under the Public Utility Regulatory Policies Act of ~~its contracts with~~1978 (“PURPA”), qualifying facilities over 100 kW be set at a presumptive maximum 2-year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has aare provided the right to sell energy and/or capacity to ~~the host utility. Host~~ utilities and are ~~required to purchase power~~granted relief from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 and briefing on this matter was completed in October 2019 regarding APS’s application.certain regulatory burdens. On

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December 17, 2019, the ACC ~~denied the application and~~ mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona, and established that the rate paid to ~~the~~ qualifying facilities ~~will~~must be based on the long-term avoided cost. ~~APS~~“Avoided cost” is ~~in discussions with~~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 ~~developers but has not~~on a long-term basis. During calendar year 2020, APS entered into ~~any new qualifying facility~~2 18-year power purchase agreements ~~that would be subject to~~with qualified facilities, each for 80 MW solar facilities. In March 2021, the ~~new requirements of the ACC's decision.~~

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ACC approved these agreements.

On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule ~~will go~~went into effect ~~120 days following publication in the Federal Register.~~on December 31, 2020. APS is evaluating how the revised regulations may impact its operations.

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"~~Moratorium”). During the Summer Disconnection Moratorium, APS could not charge late fees and interest on amounts that were past due from customers. Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts. In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. Although the emergency rules expired in December 2019, the Summer Disconnection Moratorium will remain in effect through utility tariffs for 2020 and beyond until the ACC adopts permanent rules or determines otherwise.

In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff ~~issued~~and ACC proposed draft amendments to the customer service disconnections rules. ~~Stakeholders submitted initial comments to the draft amendments on September 23, 2019.~~ ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules. 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 threshold (June 1 – October 15) for disconnection moratoriums. During the formal rulemaking process, the public will have an opportunity to provide input on the draft rules, before the draft rules come back to the ACC for a final vote. The Summer Disconnection Moratorium will remain in effect until the ACC formalizes the final rules package.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. ~~On September 14, 2020, APS extended this~~The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until ~~December 31, 2020.~~October 15, 2021. APS ~~currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic,~~has experienced and ~~the increased~~is continuing to experience an increase in bad debt expense associated with ~~both events will result in a negative impact to its 2020 operating results of approximately $20 million to $30 million pre-tax above~~ the ~~impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or~~ COVID-19 pandemic. These estimated impact amounts depend on certain assumptions, including, but not limited to, customer behaviors, population and employment growth, the impacts of COVID-19 on the economy and the results of final rulemaking related to the Summer Disconnection Moratorium. See ~~"COVID-19 Pandemic"~~“COVID-19 Pandemic” above for more information.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft

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rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

competition rules. On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC held a workshop on February 25-26, 2020 ~~for~~on further consideration and discussion of the retail electric competition rules. During ~~the~~a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC Commissioners are continuing to explore the retail electric competition rules. 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.

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 ~~the Company’s~~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~~APS’s financial statements. APS developed a new tool for comparing customers’ rate plan options. APS had an independent third party verify that the new rate comparison tool works correctly. In February 2020, APS launched the new online rate comparison tool, which is now available for its customers. 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~~APS’s financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict if any action will be taken by the ACC at this time.

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section ~~that seek~~(“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 is fully ~~cooperating~~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 results in APS paying $24.75 million, $24 million of which is being 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 ~~outcome of this matter.~~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. Consistent with the 2017

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Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC ~~Staff's~~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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018. The ACC has not issued a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 ~~retail rate case~~Retail Rate Case filing with the ACC. On March 18, 2020, the ACC agreed to take administrative notice to include in the pending rate case portions of the record in this prior proceeding that are relevant to the SCRs. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ~~("Cholla"~~(“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ~~("EPA"~~(“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~~APS’s plan to retire Unit 2, without expressing any view on the future recoverability of ~~APS's~~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~~APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it ~~plans~~planned to retire Cholla Unit 4 by the end of 2020. Cholla Unit 4 was retired on December 24, 2020.

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 ($6152.9 million as of ~~September 30, 2020)~~March 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. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.

On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.

Navajo Plant

The ~~co-owners of the~~ Navajo Plant ~~and the Navajo Nation agreed that the Navajo Plant would remain~~ceased operations in ~~operation until December 2019 under the existing plant lease.~~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 November 2019.~~operations.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($7469.4 million as of ~~September 30, 2020)~~March 31, 2021) plus a return on the net book value as well as other costs related to retirement and closure, ~~which are still being assessed and may be material.~~including the Navajo coal reclamation regulatory asset ($17.8 million as of March 31, 2021). APS believes it will be allowed recovery of the net book value, retirement and closure costs, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, ~~APS's~~APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery

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of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and ~~APS's~~APS’s net income, cash flows, and financial position will be negatively impacted.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Regulatory Assets and Liabilities

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


		Amortization Through	September 30, 2020				December 31, 2019					Amortization Through	March 31, 2021				December 31, 2020
			Current		Non-Current		Current		Non-Current				Current		Non-Current		Current		Non-Current
Pension	Pension	(a)	$	0	$	656,092	$	0	$	660,223	Pension	(a)	$	0	$	467,423	$	0	$	469,953
Income taxes — allowance for funds used during construction ("AFUDC") equity		2050	6,815		159,005		6,800		154,974
Deferred fuel and purchased power (b) (c)	Deferred fuel and purchased power (b) (c)	2021	162,111		0		70,137		0		Deferred fuel and purchased power (b) (c)	2022	228,609		0		175,835		0
Income taxes — allowance for funds used during construction (“AFUDC”) equity											Income taxes — allowance for funds used during construction (“AFUDC”) equity	2051	7,169		159,119		7,169		158,776
Retired power plant costs	Retired power plant costs	2033	28,182		121,259		28,182		142,503		Retired power plant costs	2033	28,182		107,169		28,181		114,214
Ocotillo deferral	Ocotillo deferral	N/A	0		80,359		0		38,144		Ocotillo deferral	N/A	0		110,820		0		95,723
SCR deferral	SCR deferral	N/A	0		74,576		0		52,644		SCR deferral	N/A	0		88,044		0		81,307
Deferred property taxes	Deferred property taxes	2027	8,569		51,769		8,569		58,196		Deferred property taxes	2027	8,569		47,484		8,569		49,626
Lost fixed cost recovery (b)	Lost fixed cost recovery (b)	2021	37,868		0		26,067		0		Lost fixed cost recovery (b)	2022	45,905		0		41,807		0
Deferred compensation	Deferred compensation	2036	0		36,481		0		36,464		Deferred compensation	2036	0		35,806		0		36,195
Four Corners cost deferral	Four Corners cost deferral	2024	8,077		26,094		8,077		32,152		Four Corners cost deferral	2024	8,077		22,056		8,077		24,075
Income taxes — investment tax credit basis adjustment	Income taxes — investment tax credit basis adjustment	2048	1,097		23,850		1,098		24,981		Income taxes — investment tax credit basis adjustment	2049	1,113		24,221		1,113		24,291
Palo Verde VIEs (Note 6)	Palo Verde VIEs (Note 6)	2046	0		21,100		0		20,635		Palo Verde VIEs (Note 6)	2046	0		21,409		0		21,255
Coal reclamation	Coal reclamation	2026	1,068		17,266		1,546		17,688		Coal reclamation	2026	1,068		16,732		1,068		16,999
Loss on reacquired debt	Loss on reacquired debt	2038	1,637		10,846		1,637		12,031		Loss on reacquired debt	2038	1,703		10,486		1,689		10,877
Mead-Phoenix transmission line contributions in aid of construction ("CIAC")		2050	332		9,463		332		9,712
Demand Side Management		2021	0		7,259		0		0
Tax expense adjuster mechanism (b) (c)		2020	6,121		0		1,612		0
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)											Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)	2050	332		9,297		332		9,380
Demand side management (b)											Demand side management (b)	2021	0		7,268		0		7,268
Tax expense adjustor mechanism (b)											Tax expense adjustor mechanism (b)	2021	5,854		0		6,226		0
Tax expense of Medicare subsidy											Tax expense of Medicare subsidy	2024	1,235		3,626		1,235		3,704
Deferred fuel and purchased power — mark-to-market (Note 7)	Deferred fuel and purchased power — mark-to-market (Note 7)	2024	0		5,664		36,887		33,185		Deferred fuel and purchased power — mark-to-market (Note 7)	2024	0		3,728		3,341		9,244
Tax expense of Medicare subsidy		2024	1,238		3,728		1,235		4,940
AG-1 deferral		2022	2,787		626		2,787		2,716
TCA balancing account (b)		2021	4,490		0		6,324		2,885

PSA interest											PSA interest	2022	46		0		4,355		0
Other	Other	Various	2,478		0		1,917		0		Other	Various	2,018		1,169		2,716		1,100
Total regulatory assets (d)	Total regulatory assets (d)		$	272,870	$	1,305,437	$	203,207	$	1,304,073	Total regulatory assets (d)		$	339,880	$	1,135,857	$	291,713	$	1,133,987

(a)This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ~~("OCI"~~(“OCI”) and result in lower future revenues. See Note 5.

(b)See ~~"Cost~~“Cost Recovery ~~Mechanisms"~~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~~“Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."”

4039

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


		Amortization Through	September 30, 2020				December 31, 2019					Amortization Through	March 31, 2021				December 31, 2020
			Current		Non-Current		Current		Non-Current				Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)	Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)	2046	$	113,206	$	952,531	$	59,918	$	1,054,053	Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)	2046	$	41,353	$	1,004,226	$	41,330	$	1,012,583
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)	Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)	2058	7,256		229,753		6,302		237,357		Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)	2058	7,240		228,690		7,240		229,147
Asset retirement obligations	Asset retirement obligations	2057	0		442,035		0		418,423		Asset retirement obligations	2057	0		519,015		0		506,049
Other postretirement benefits											Other postretirement benefits	(d)	37,705		337,853		37,705		349,588
Removal costs	Removal costs	(c)	51,519		112,168		47,356		136,072		Removal costs	(c)	55,247		89,937		52,844		103,008
Other postretirement benefits		(d)	37,575		109,035		37,575		139,634
Income taxes — change in rates											Income taxes — change in rates	2050	2,839		66,374		2,839		66,553
Four Corners coal reclamation	Four Corners coal reclamation	2038	5,461		49,151		1,059		51,704		Four Corners coal reclamation	2038	5,461		49,703		5,460		49,435
Income taxes — deferred investment tax credit											Income taxes — deferred investment tax credit	2049	2,231		48,507		2,231		48,648
Spent nuclear fuel	Spent nuclear fuel	2027	6,520		46,526		6,676		51,019		Spent nuclear fuel	2027	6,831		43,059		6,768		44,221
Income taxes — change in rates		2050	2,802		48,541		2,797		68,265
Income taxes — deferred investment tax credit		2048	2,199		47,765		2,202		50,034
Renewable energy standard (b)	Renewable energy standard (b)	2021	35,813		1,128		39,287		10,300		Renewable energy standard (b)	2022	34,460		30		39,442		103
Deferred fuel and purchased power — mark-to-market (Note 7)											Deferred fuel and purchased power — mark-to-market (Note 7)	2022	20,829		0		0		0
Property tax deferral											Property tax deferral	N/A	0		15,022		0		13,856
Sundance maintenance											Sundance maintenance	2031	2,867		11,910		2,989		11,508
Demand side management (b)	Demand side management (b)	2021	17,394		0		15,024		24,146		Demand side management (b)	2022	7,821		5,975		10,819		0
Sundance maintenance		2031	2,200		12,303		5,698		11,319
Property tax deferral		N/A	0		11,784		0		7,046
Deferred fuel and purchased power — mark-to-market (Note 7)		2024	10,894		0		0		0
FERC transmission true up	FERC transmission true up	2022	5,965		4,291		1,045		2,004		FERC transmission true up	2023	7,630		2,379		6,598		3,008
Active union medical trust		N/A	0		6,993		0		2,041
TCA balancing account (b)											TCA balancing account (b)	2022	7,315		1,754		2,902		4,672
Tax expense adjustor mechanism (b) ~~(c)~~(e)	Tax expense adjustor mechanism (b) ~~(c)~~(e)	2020	6,542		0		7,018		0		Tax expense adjustor mechanism (b) ~~(c)~~(e)	2021	7,452		0		7,089		0
Deferred gains on utility property	Deferred gains on utility property	2022	2,423		2,379		2,423		4,163		Deferred gains on utility property	2022	2,423		939		2,423		1,544
TCA balancing account (b)		2022	0		2,665		0		0
Active union medical trust											Active union medical trust	N/A	0		2,337		0		6,057
Other	Other	Various	250		275		532		255		Other	Various	524		59		409		189
Total regulatory liabilities	Total regulatory liabilities		$	308,019	$	2,079,323	$	234,912	$	2,267,835	Total regulatory liabilities		$	250,228	$	2,427,769	$	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~~“Deferred income ~~taxes"~~taxes” under Cash Flows From Operating Activities.

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

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

(d)See Note 5.

(e)Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.

5. Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit ~~plan~~plans for the employees of Pinnacle West and our subsidiaries. The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). Pinnacle West uses a December 31

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 ~~dates.~~date.

41Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. In prior years, we had been assuming a 4.75% escalation of these benefits; 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%. 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 assets from the other postretirement benefit plan into the Active Union Employee Medical Account. The Active Union Employee Medical Account is an existing trust account that holds assets restricted for paying active union employee medical costs (see Note 12). The transfer of other postretirement benefit plan 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 assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.

~~COMBINED NOTES TO CONDENSED 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 Benefits								Other Benefits									Pension Benefits					Other Benefits
		Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,				Three Months Ended March 31,
		2020		2019		2020		2019		2020		2019		2020		2019			2021		2020			2021		2020
Service cost — benefits earned during the period	Service cost — benefits earned during the period	$	14,058	$	12,476	$	42,174	$	37,427	$	5,559	$	4,593	$	16,677	$	13,777	Service cost — benefits earned during the period	$	15,679	$	14,257		$	4,557	$	5,717
Non-service costs (credits):	Non-service costs (credits):																	Non-service costs (credits):
Interest cost on benefit obligation	Interest cost on benefit obligation	29,642		34,211		88,925		102,632		6,464		7,473		19,393		22,420		Interest cost on benefit obligation	24,669		29,761			4,162		6,512
Expected return on plan assets	Expected return on plan assets	(46,861)		(42,971)		(140,582)		(128,913)		(10,019)		(9,603)		(30,057)		(28,809)		Expected return on plan assets	(50,608)		(46,806)			(10,361)		(10,019)
Amortization of:	Amortization of:																	Amortization of:
Prior service credit	Prior service credit	0		0		0		0		(9,394)		(9,456)		(28,182)		(28,366)		Prior service credit	0		0			(9,427)		(9,394)
Net actuarial loss		8,653		10,646		25,959		31,938		0		0		0		0
Net periodic benefit cost (credit)		$	5,492	$	14,362	$	16,476	$	43,084	$	(7,390)	$	(6,993)	$	(22,169)	$	(20,978)
Portion of cost (credit) charged to expense		$	736	$	7,593	$	2,349	$	22,837	$	(5,286)	$	(4,966)	$	(15,798)	$	(14,846)
Net actuarial loss (gain)																		Net actuarial loss (gain)	3,985		9,011			(2,405)		0
Net periodic benefit cost/(benefit)																		Net periodic benefit cost/(benefit)	$	(6,275)	$	6,223		$	(13,474)	$	(7,184)
Portion of cost/(benefit) charged to expense																		Portion of cost/(benefit) charged to expense	$	(8,011)	$	1,342		$	(9,528)	$	(5,456)

Contributions

We have 0t made voluntary contributions ~~of $100 million~~ to our pension plan year-to-date in ~~2020.~~2021. The minimum required contributions for the pension plan are 0 for the ~~2020-2022 period.~~next three years. We expect to make voluntary contributions up to $100 million ~~per year during this period.~~in 2021 and 0 in 2022 and 2023. We do 0t expect to make any contributions over this period to our other postretirement benefit plans.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with 3 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 ~~will~~the right to retain the assets through 2023 under 1 lease and 2033 under the other 2 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 ~~these~~the 3 leases in total of approximately ~~$23~~$21 million annually for the period ~~2020 through 2023, and $16 million annually for the period 2024~~2021 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'~~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 for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020 of $5 million, ~~and $15 million, respectively, and for the three and nine months ended September 30, 2019 of $5 million and $15 million, respectively,~~ entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Our Condensed Consolidated Balance Sheets at ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020 include the following amounts relating to the VIEs (dollars in thousands):


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation		$	99,003	$	101,906
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation						Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	97,068	$	98,036
Equity — Noncontrolling interests	Equity — Noncontrolling interests	125,789		122,540		Equity — Noncontrolling interests	124,164		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 condensed 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 Nuclear Regulatory Commission ~~("NRC"~~(“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 ~~$304~~$307 million beginning in ~~2020,~~2021, and up to ~~$456~~$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 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and in 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 ~~fuels.~~natural gas. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed 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 sheets as an asset or liability and are measured at fair value. See Note 11 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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.

~~As of September 30, 2020 and December 31, 2019, we had~~The following table shows the ~~following~~ outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Quantity

Commodity

Unit of Measure

September 30, 2020

December 31, 2019

Commodity

Unit of Measure

March 31, 2021

December 31, 2020

Power

GWh

142

193

Power

GWh

368

Gas

Billion cubic feet

213

257

Gas

Billion cubic feet

211

205

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Gains and Losses from Derivative Instruments

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


		Financial Statement Location		Three Months Ended September 30,					Nine Months Ended September 30,							Financial Statement Location		Three Months Ended March 31,
Commodity Contracts	Commodity Contracts		2020		2019		2020			2019		Commodity Contracts					2021		2020

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)		Fuel and purchased power (b)		$	0	$	(289)		$	(763)		$	(1,263)	Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)		Fuel and purchased power (b)		$	0	$	(414)

(a)During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ we had 0 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 no0 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.

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


		Financial Statement Location		Three Months Ended September 30,					Nine Months Ended September 30,							Financial Statement Location		Three Months Ended March 31,
Commodity Contracts	Commodity Contracts		2020		2019		2020			2019		Commodity Contracts					2021		2020
Net Gain (Loss) Recognized in Income	Net Gain (Loss) Recognized in Income		Fuel and purchased power (a)		$	49,611	$	(28,249)		$	14,639		$	(69,765)	Net Gain (Loss) Recognized in Income		Fuel and purchased power (a)		$	26,859	$	(30,078)

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

Derivative Instruments in the Condensed 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.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed 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.

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 and other assets lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2020:
(dollars in thousands)
Gross
Recognized
Derivatives
(a)
Amounts
Offset
(b)
Net
Recognized
Derivatives
Other
(c)
Amount Reported on Balance Sheets
Current assets $ 15,505 $ (1,630) $ 13,875 $ 0 $ 13,875
Investments and other assets 5,008 (1,579) 3,429 0 3,429
Total assets 20,513 (3,209) 17,304 0 17,304
Current liabilities (4,611) 1,630 (2,981) (1,285) (4,266)
Deferred credits and other (10,671) 1,579 (9,092) 0 (9,092)
Total liabilities (15,282) 3,209 (12,073) (1,285) (13,358)
Total $ 5,231 $ 0 $ 5,231 $ (1,285) $ 3,946

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


As of March 31, 2021: (dollars in thousands)	Gross Recognized Derivatives (a)		Amounts Offset (b)		Net Recognized Derivatives		Other (c)		Amount Reported on Balance Sheet
Current assets	$	25,703	$	(3,092)	$	22,611	$	0	$	22,611
Investments and other assets	3,990		(790)		3,200		0		3,200
Total assets	29,693		(3,882)		25,811		0		25,811

Current liabilities	(4,874)		3,092		(1,782)		(1,285)		(3,067)
Deferred credits and other	(7,718)		790		(6,928)		0		(6,928)
Total liabilities	(12,592)		3,882		(8,710)		(1,285)		(9,995)
Total	$	17,101	$	0	$	17,101	$	(1,285)	$	15,816

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

(b)NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c)Represents cash collateral that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions or collateral posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~


As of December 31, 2019: (dollars in thousands)		Gross Recognized Derivatives (a)		Amounts Offset (b)		Net Recognized Derivatives		Other (c)		Amount Reported on Balance Sheets
As of December 31, 2020: (dollars in thousands)												As of December 31, 2020: (dollars in thousands)	Gross Recognized Derivatives (a)		Amounts Offset (b)		Net Recognized Derivatives		Other (c)		Amount Reported on Balance Sheet
Current assets	Current assets	$	584	$	(474)	$	110	$	405	$	515	Current assets	$	5,870	$	(2,939)	$	2,931	$	0	$	2,931

Investments and other assets												Investments and other assets	3,150		(1,332)		1,818		0		1,818
Total assets												Total assets	9,020		(4,271)		4,749		0		4,749

Current liabilities	Current liabilities	(38,235)		474		(37,761)		(1,185)		(38,946)		Current liabilities	(9,211)		2,939		(6,272)		(1,285)		(7,557)
Deferred credits and other	Deferred credits and other	(33,186)		0		(33,186)		0		(33,186)		Deferred credits and other	(12,394)		1,332		(11,062)		0		(11,062)
Total liabilities	Total liabilities	(71,421)		474		(70,947)		(1,185)		(72,132)		Total liabilities	(21,605)		4,271		(17,334)		(1,285)		(18,619)
Total	Total	$	(70,837)	$	0	$	(70,837)	$	(780)	$	(71,617)	Total	$	(12,585)	$	0	$	(12,585)	$	(1,285)	$	(13,870)

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

(b)NaN 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 ~~$1,185 and cash margin provided to counterparties of $405.~~$1,285.

COMBINED NOTES TO CONDENSED 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 ~~September 30, 2020,~~March 31, 2021, we have ~~two counterparties~~one counterparty for which our exposure represents approximately ~~37%~~59% of Pinnacle ~~West's $17~~West’s $26 million of risk management assets. This exposure relates to a master ~~agreements~~agreement with ~~the counterparties, which are both~~a counterparty that is 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'~~counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies 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).

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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


	~~September 30, 2020~~March 31, 2021
Aggregate fair value of derivative instruments in a net liability position	$	~~15,282~~11,520
Cash collateral posted	0
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	~~5,054~~6,674

(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 ~~$89~~$86 million if our debt credit ratings were to fall below investment grade.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. 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 the United States Department of Energy ~~("DOE"~~(“DOE”) in the United States Court of Federal Claims ("(“Court of Federal ~~Claims"~~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"~~Contract”) for failing to accept Palo ~~Verde's~~Verde’s spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, ~~2019. On 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 56 claims pursuant to the terms of the August 18, 2014 settlement agreement, for 56 separate time periods during July 1, 2011 through June 30, ~~2018.~~2019. The DOE has approved and paid ~~$84.3~~$99.7 million for these claims (APS’s share is ~~$24.5~~$29.0 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 ~~October 31, 2019,~~November 2, 2020, APS filed its ~~sixth~~7th claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of ~~$16~~$12.2 million (APS’s share is ~~$4.7~~$3.6 million). On ~~February 11, 2020,~~March 15, 2021, the DOE approved a payment of ~~$15.4~~$12.1 million ~~(APS's~~(APS’s share is ~~$4.5~~$3.5 million) and on April ~~20, 2020,~~16, 2021, APS received this payment.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("(“Price-Anderson ~~Act"~~Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately ~~$13.8~~$13.7 billion per occurrence. Palo Verde maintains the

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ~~("ANI"~~(“ANI”). The remaining balance of approximately ~~$13.3~~$13.2 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 3 Palo Verde units, APS’s maximum retrospective premium per incident for all 3 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 insurance for a sudden and unforeseen accidental outage of any of the 3 units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ~~("NEIL"~~(“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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

policies totals approximately ~~$25.8~~$22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately ~~$75.1~~$63.3 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

~~During 2020,~~As of March 31, 2021, our fuel and purchased power commitments have increased from the information provided in our ~~2019~~2020 Form 10-K. The increase is primarily due to new ~~fuel~~purchased power and ~~purchased power~~energy storage commitments of approximately ~~$600~~$550 million. The majority of the changes relate to ~~2025~~2026 and thereafter.

Other than the item described above, there have been no material changes, as of ~~September 30, 2020,~~March 31, 2021, outside the normal course of business in contractual obligations from the information provided in our ~~2019~~2020 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations.

Superfund-Related Matters

The Comprehensive Environmental Response Compensation and Liability Act ~~("Superfund"~~(“Superfund” or ~~"CERCLA"~~“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”). PRPs may be strictly, and often are 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"~~(“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"~~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 byduring the ~~end~~second quarter of ~~2020.~~2021. We estimate that our costs related to this investigation and study will be approximately $3 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

On August 6, 2013, the Roosevelt Irrigation District ~~("RID"~~(“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ~~("ADEQ"~~(“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, 2 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

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by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase ~~APS's~~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~~RID’s CERCLA claims concerning both past and future cost recovery. ~~APS's~~APS’s share of this settlement was immaterial. In addition, the 2 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 results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ~~("CCRs"~~(“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 best available retrofit technology ~~("BART"~~(“BART”) to lessen the impacts of emissions on visibility surrounding the plant. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, ~~APS's~~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 Electric Company ("(“El ~~Paso"~~Paso”) entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El ~~Paso's~~Paso’s 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ~~("NTEC"~~(“NTEC”) purchased the interest

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

from 4CA on July 3, 2018. See ~~"Four~~“Four Corners -— 4CA ~~Matter"~~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.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cholla. ~~APS believed that EPA’s original 2012~~In early 2017, EPA approved a final rule ~~establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving~~containing a revision to Arizona’s State Implementation Plan ~~("SIP"~~(“SIP”) ~~and promulgating a FIP~~for Cholla that ~~was inconsistent~~implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements.In conjunction with the ~~state’s considered BART determinations under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close~~closure of Cholla Unit 2 ~~and cease burning~~in 2015, APS has committed to ceasing coal atcombustion within Units 1 and 3 by April 2025.PacifiCorp retired Cholla Unit 4 at the ~~mid-2020s.~~end of 2020. (See ~~"Cholla"~~“Cholla” in Note 4 for information regarding future plans for ~~the~~ Cholla ~~plant~~ and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.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"~~(“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 ~~that is contaminating groundwater above a regulated constituent’s groundwater protection standard~~ 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"~~“forced closure” or ~~"closure~~“closure for ~~cause"~~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:

•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.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

•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; such disposal units ~~must close~~were closed as ~~soon as technically feasible, but no later than~~of April ~~22,~~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~~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

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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.

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 ~~$22~~$27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately ~~$15~~$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~~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 Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must ~~cease~~have ceased operating and ~~initiate~~initiated closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to ~~late-2020.~~late-2021. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. 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~~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 ~~those~~such rules would have had far broader impact on the electric power sector than the ACE regulations. The ACE regulations had been stayed pending judicial ~~review.~~review and 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. While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision.

The ACE regulations are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines.

We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits in the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition, to the extent that the ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet.OtherOther 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.

~~Federal Agency Environmental Lawsuit Related to Four Corners~~

On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. The Ninth Circuit denied this petition for rehearing on December 11, 2019. On March 24, 2020, the environmental group plaintiffs filed a Petition for a Writ of Certiorari with the U.S. Supreme Court seeking review of the Ninth Circuit decision. This petition was denied by the U.S. Supreme Court on June 29, 2020. No further legal proceedings related to this matter are expected at this time.

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

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ~~("EAB"~~(“EAB”) concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018.The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018.Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis.The EAB thereafter dismissed the environmental group appeal on February 12, 2019.EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. ~~This permit is now subject to a petition for review before the EAB, based~~Based upon a November 1, 2019 filing by several environmental ~~groups.~~ groups, the EAB again took up review of the Four Corners NPDES Permit.Oral argument on this appeal was held on September 3, 2020 and the EAB denied the environmental group petition on September 30, 2020. ~~Judicial appeal rights to~~On January 22, 2021, the ~~Ninth Circuit~~environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals ~~are available to~~for the ~~environmental groups.~~Ninth Circuit. We cannot predict ~~whether~~the outcome of these ~~groups will~~ appeal ~~the EAB decision~~proceedings and, if such appeal ~~occurs,~~is successful, whether ~~the appeal~~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 ~~September 30, 2020,~~March 31, 2021, the note has a remaining balance of ~~$31~~$23 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~~NTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle ~~West's~~West’s guarantee is secured by a portion of ~~APS's~~APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

a specified rate of return, offset by revenue generated by 4CA’s power sales. The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) was approximately $10 million, which was due to 4CA on December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations of which the prepayment has been fully utilized as of June 2020.

Financial Assurances

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 ~~September 30, 2020,~~March 31, 2021, standby letters of credit totaled ~~$4.9~~$5.2 million and ~~will expire~~would have expired in ~~2021.~~2021, subsequently in April of 2021 an extension was effective that reset the expiration dates to 2022. As of ~~September 30, 2020,~~March 31, 2021, surety bonds expiring through ~~2021~~2022 totaled $16 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.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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.

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at ~~September 30, 2020.~~March 31, 2021. In connection with the sale of ~~4CA's~~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~~“Four Corners -— 4CA ~~Matter"~~Matter” above for information related to this ~~guarantee.)~~guarantee). Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements. The Equity Contribution Guarantees remaining as of March 31, 2021 are ~~currently anticipated to be terminated upon completion of construction of the respective projects, which is anticipated to occur prior to December 31, 2020,~~immaterial in amount (approximately $2 million) and the PTC Guarantees (approximately ~~$39~~$38 million as of ~~September 30, 2020)~~March 31, 2021) are currently expected to be terminated ten years following the commercial operation date of the applicable project.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. Other Income and Other Expense

The following table ~~provides~~provides detail of Pinnacle ~~West's~~West’s Consolidated other income and other expense (dollars in thousands):

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
Other income:
Interest income $ 2,956 $ 2,694 $ 8,988 $ 7,695
Investment gains (losses) - net 0 0 2,594 0
Debt return on Four Corners SCR deferrals (Note 4) 4,260 4,920 11,649 14,651
Debt return on Ocotillo modernization project (Note 4) 6,663 7,555 19,511 12,849
Miscellaneous 2 22 146 50
Total other income $ 13,881 $ 15,191 $ 42,888 $ 35,245
Other expense:
Non-operating costs $ (2,453) $ (2,647) $ (7,401) $ (8,832)
Investment gains (losses) — net (291) (716) 0 (1,445)
Miscellaneous (3,094) (2,377) (7,025) (4,171)
Total other expense $ (5,838) $ (5,740) $ (14,426) $ (14,448)


	Three Months Ended March 31,
	2021		2020
Other income:
Interest income	$	1,948	$	3,277

Debt return on Four Corners SCR deferrals (Note 4)	4,086		3,140
Debt return on Ocotillo modernization project (Note 4)	6,392		6,144
Miscellaneous	3		8
Total other income	$	12,429	$	12,569
Other expense:
Non-operating costs	(1,937)		(2,658)
Investment gains (losses) — net	(343)		60
Miscellaneous	(1,573)		(2,186)
Total other expense	$	(3,853)	$	(4,784)

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

The following table provides detail of APS’s other income and other expense (dollars in thousands):

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
Other income:
Interest income $ 2,403 $ 2,037 $ 6,927 $ 5,091
Debt return on Four Corners SCR deferrals (Note 4) 4,260 4,920 11,649 14,651
Debt return on Ocotillo modernization project (Note 4) 6,663 7,555 19,511 12,849
Miscellaneous 2 22 146 50
Total other income $ 13,328 $ 14,534 $ 38,233 $ 32,641
Other expense:
Non-operating costs $ (1,906) $ (2,448) $ (6,501) $ (7,965)
Miscellaneous (893) (378) (4,825) (2,167)
Total other expense $ (2,799) $ (2,826) $ (11,326) $ (10,132)


	Three Months Ended March 31,
	2021		2020
Other income:
Interest income	$	1,481	$	2,341
Debt return on Four Corners SCR deferrals (Note 4)	4,086		3,140
Debt return on Ocotillo modernization project (Note 4)	6,392		6,144
Miscellaneous	1		8
Total other income	$	11,960	$	11,633
Other expense:
Non-operating costs	(1,778)		(2,482)
Miscellaneous	(1,572)		(2,186)
Total other expense	$	(3,350)	$	(4,668)

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10. 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):


		Three Months Ended September 30,					Nine Months Ended September 30,						Three Months Ended March 31,
			2020		2019			2020		2019				2021		2020
Net income attributable to common shareholders	Net income attributable to common shareholders		$	346,372	$	312,276		$	569,950	$	474,339	Net income attributable to common shareholders		$	35,641	$	29,993
Weighted average common shares outstanding — basic	Weighted average common shares outstanding — basic		112,679		112,463			112,639		112,408		Weighted average common shares outstanding — basic		112,829		112,594
Net effect of dilutive securities:	Net effect of dilutive securities:											Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	Contingently issuable performance shares and restricted stock units		308		283			273		331		Contingently issuable performance shares and restricted stock units		264		268
Weighted average common shares outstanding — diluted	Weighted average common shares outstanding — diluted		112,987		112,746			112,912		112,739		Weighted average common shares outstanding — diluted		113,093		112,862
Earnings per weighted-average common share outstanding	Earnings per weighted-average common share outstanding											Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	Net income attributable to common shareholders — basic		$	3.07	$	2.78		$	5.06	$	4.22	Net income attributable to common shareholders — basic		$	0.32	$	0.27
Net income attributable to common shareholders — diluted	Net income attributable to common shareholders — diluted		$	3.07	$	2.77		$	5.05	$	4.21	Net income attributable to common shareholders — diluted		$	0.32	$	0.27

11. 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).

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Certain instruments have been valued using the concept of Net Asset Value ~~("NAV"~~(“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~~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 in the ~~2019~~2020 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.

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.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds

The ~~Nuclear Decommissioning Trusts~~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 12 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~~agent’s internal operating controls and valuation processes.

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.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Equity Securities

The Nuclear Decommissioning Trusts's equity security investments are held indirectly through commingled funds. The commingled funds are valued using the ~~funds'~~funds’ NAV as a practical expedient. The ~~funds'~~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'~~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.

5857

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at ~~September 30, 2020~~March 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			Level 1		Level 2		Level 3		Other			Total
Assets	Assets												Assets
Cash equivalents		$	146,680	$	0	$	0	$	—		$	146,680

Risk management activities — derivative instruments:	Risk management activities — derivative instruments:												Risk management activities — derivative instruments:
Commodity contracts	Commodity contracts	$	0	$	20,206	$	307	$	(3,209)	(a)	$	17,304	Commodity contracts	$	0	$	14,353	$	15,340	$	(3,882)	(a)	$	25,811
Nuclear decommissioning trust:	Nuclear decommissioning trust:												Nuclear decommissioning trust:
Equity securities	Equity securities	24,537		0		0		(14,148)		(b)	10,389		Equity securities	22,160		0		0		(15,538)		(b)	6,622
U.S. commingled equity funds	U.S. commingled equity funds	0		0		0		545,845		(c)	545,845		U.S. commingled equity funds	0		0		0		648,199		(c)	648,199
U.S. Treasury debt	U.S. Treasury debt	153,213		0		0		—			153,213		U.S. Treasury debt	175,707		0		0		—			175,707
Corporate debt	Corporate debt	0		146,682		0		—			146,682		Corporate debt	0		143,876		0		—			143,876
Mortgage-backed securities	Mortgage-backed securities	0		101,456		0		—			101,456		Mortgage-backed securities	0		110,073		0		—			110,073
Municipal bonds	Municipal bonds	0		99,192		0		—			99,192		Municipal bonds	0		64,479		0		—			64,479
Other fixed income	Other fixed income	0		13,060		0		—			13,060		Other fixed income	0		10,743		0		—			10,743
Subtotal nuclear decommissioning trust	Subtotal nuclear decommissioning trust	177,750		360,390		0		531,697			1,069,837		Subtotal nuclear decommissioning trust	197,867		329,171		0		632,661			1,159,699

Other special use funds:	Other special use funds:												Other special use funds:
Equity securities	Equity securities	8,090		0		0		1,444		(b)	9,534		Equity securities	19,211		0		0		1,401		(b)	20,612
U.S. Treasury debt	U.S. Treasury debt	245,156		0		0		—			245,156		U.S. Treasury debt	323,589		0		0		—			323,589
Municipal bonds	Municipal bonds	0		13,602		0		—			13,602		Municipal bonds	0		13,305		0		—			13,305
Subtotal other special use funds	Subtotal other special use funds	253,246		13,602		0		1,444			268,292		Subtotal other special use funds	342,800		13,305		0		1,401			357,506

Total assets	Total assets	$	577,676	$	394,198	$	307	$	529,932		$	1,502,113	Total assets	$	540,667	$	356,829	$	15,340	$	630,180		$	1,543,016
Liabilities	Liabilities												Liabilities
Risk management activities — derivative instruments:	Risk management activities — derivative instruments:												Risk management activities — derivative instruments:
Commodity contracts	Commodity contracts	$	0	$	(10,737)	$	(4,546)	$	1,925	(a)	$	(13,358)	Commodity contracts	$	0	$	(11,668)	$	(924)	$	2,597	(a)	$	(9,995)

(a)Represents counterparty netting, margin, and collateral. See Note 7.

(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.

5958

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, ~~2019~~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			Level 1		Level 2		Level 3		Other			Total
Assets	Assets												Assets

Risk management activities — derivative instruments:	Risk management activities — derivative instruments:												Risk management activities — derivative instruments:
Commodity contracts	Commodity contracts	$	0	$	551	$	33	$	(69)	(a)	$	515	Commodity contracts	$	0	$	9,016	$	4	$	(4,271)	(a)	$	4,749
Nuclear decommissioning trust:	Nuclear decommissioning trust:												Nuclear decommissioning trust:
Equity securities	Equity securities	10,872		0		0		2,401		(b)	13,273		Equity securities	29,796		0		0		(17,828)		(b)	11,968
U.S. commingled equity funds	U.S. commingled equity funds	0		0		0		518,844		(c)	518,844		U.S. commingled equity funds	0		0		0		610,055		(c)	610,055
U.S. Treasury debt	U.S. Treasury debt	160,607		0		0		—			160,607		U.S. Treasury debt	164,514		0		0		—			164,514
Corporate debt	Corporate debt	0		115,869		0		—			115,869		Corporate debt	0		149,509		0		—			149,509
Mortgage-backed securities	Mortgage-backed securities	0		118,795		0		—			118,795		Mortgage-backed securities	0		99,623		0		—			99,623
Municipal bonds	Municipal bonds	0		73,040		0		—			73,040		Municipal bonds	0		89,705		0		—			89,705
Other fixed income	Other fixed income	0		10,347		0		—			10,347		Other fixed income	0		13,061		0		—			13,061
Subtotal nuclear decommissioning trust	Subtotal nuclear decommissioning trust	171,479		318,051		0		521,245			1,010,775		Subtotal nuclear decommissioning trust	194,310		351,898		0		592,227			1,138,435

Other special use funds:	Other special use funds:												Other special use funds:
Equity securities	Equity securities	7,142		0		0		474		(b)	7,616		Equity securities	37,337		0		0		504		(b)	37,841
U.S. Treasury debt	U.S. Treasury debt	232,848		0		0		—			232,848		U.S. Treasury debt	203,220		0		0		—			203,220
Municipal bonds	Municipal bonds	0		4,631		0		—			4,631		Municipal bonds	0		13,448		0		—			13,448
Subtotal other special use funds	Subtotal other special use funds	239,990		4,631		0		474			245,095		Subtotal other special use funds	240,557		13,448		0		504			254,509

Total assets	Total assets	$	411,469	$	323,233	$	33	$	521,650		$	1,256,385	Total assets	$	434,867	$	374,362	$	4	$	588,460		$	1,397,693
Liabilities	Liabilities												Liabilities
Risk management activities — derivative instruments:	Risk management activities — derivative instruments:												Risk management activities — derivative instruments:
Commodity contracts	Commodity contracts	$	0	$	(67,992)	$	(3,429)	$	(711)	(a)	$	(72,132)	Commodity contracts	$	0	$	(20,498)	$	(1,107)	$	2,986	(a)	$	(18,619)

(a)Represents counterparty netting, margin, and collateral. See Note 7.

(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).

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.

6059

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 3 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 ~~$31~~$22.7 million as of ~~September 30, 2020~~March 31, 2021 and ~~$44~~$27.1 million as of December 31, ~~2019,~~2020, as presented on the Condensed 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 8 for more information on 4CA matters.

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

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal ~~Mine~~ 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 Condensed Consolidated Balance Sheets. See Note 11 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 ~~Mine~~ 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 mine 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 2020 and 2019, APS was reimbursed $14 million and $15 million, respectively, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. 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 5).

6160

COMBINED NOTES TO CONDENSED 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~~APS’s nuclear decommissioning trusts and other special use fund assets (dollars in thousands):


		September 30, 2020															March 31, 2021
		Fair Value							Total Unrealized Gains					Total Unrealized Losses			Fair Value											Total Unrealized Gains			Total Unrealized Losses
Investment Type:	Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total					Investment Type:		Nuclear Decommissioning Trusts					Other Special Use Funds				Total
Equity securities	Equity securities	$	570,382	$	8,090	$	578,472				$	359,112					$	(36)	Equity securities	$	670,359		$	19,211			$	689,570		$	457,442		$	0
Available for sale-fixed income securities	Available for sale-fixed income securities	513,603		258,758		772,361		(a)	47,158					(674)		Available for sale-fixed income securities	504,878				336,894			841,772		(a)		27,338			(3,203)
Other	Other	(14,148)		1,444		(12,704)		(b)	0					0		Other	(15,538)				1,401			(14,137)		(b)		0			0
Total	Total	$	1,069,837	$	268,292	$	1,338,129		$	406,270				$	(710)	Total	$	1,159,699			$	357,506		$	1,517,205			$	484,780		$	(3,203)

(a)As of ~~September 30, 2020,~~March 31, 2021, the amortized cost basis of these available-for-sale investments is ~~$726~~$818 million.

(b)Represents net pending securities sales and purchases.


		December 31, 2019															December 31, 2020
		Fair Value							Total Unrealized Gains					Total Unrealized Losses			Fair Value											Total Unrealized Gains			Total Unrealized Losses
Investment Type:	Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total					Investment Type:		Nuclear Decommissioning Trusts					Other Special Use Funds				Total
Equity securities	Equity securities	$	529,716	$	7,142	$	536,858				$	337,681					$	0	Equity securities	$	639,851		$	37,337			$	677,188		$	421,666		$	0
Available for sale-fixed income securities	Available for sale-fixed income securities	478,658		237,479		716,137		(a)	25,795					(669)		Available for sale-fixed income securities	516,412				216,668			733,080		(a)		46,581			(398)
Other	Other	2,401		474		2,875		(b)	0					0		Other	(17,828)				504			(17,324)		(b)		0			0
Total	Total	$	1,010,775	$	245,095	$	1,255,870		$	363,476				$	(669)	Total	$	1,138,435			$	254,509		$	1,392,944			$	468,247		$	(398)

(a)As of December 31, ~~2019,~~2020, the amortized cost basis of these available-for-sale investments is ~~$691~~$687 million.

(b)Represents net pending securities sales and purchases.

6261

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following ~~tables set~~table sets forth ~~APS's~~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):


		Three Months Ended September 30,							Three Months Ended March 31,
		Nuclear Decommissioning Trusts		Other Special Use Funds		Total			Nuclear Decommissioning Trusts		Other Special Use Funds		Total
2021								2021
Realized gains								Realized gains	$	2,968	$	0	$	2,968
Realized losses								Realized losses	(4,148)		0		(4,148)
Proceeds from the sale of securities (a)								Proceeds from the sale of securities (a)	234,728		145,250		379,978
2020	2020							2020
Realized gains	Realized gains	$	2,933	$	0	$	2,933	Realized gains	$	3,313	$	0	$	3,313
Realized losses	Realized losses	(750)		(15)		(765)		Realized losses	(2,227)		0		(2,227)
Proceeds from the sale of securities (a)	Proceeds from the sale of securities (a)	178,919		37,107		216,026		Proceeds from the sale of securities (a)	178,196		16,891		195,087
2019
Realized gains		$	4,732	$	4	$	4,736
Realized losses		(2,360)		0		(2,360)
Proceeds from the sale of securities (a)		155,386		56,255		211,641

(a) Proceeds are reinvested in the ~~Nuclear Decommissioning Trusts~~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.

Nine Months Ended September 30,
Nuclear Decommissioning Trusts Other Special Use Funds Total
2020
Realized gains $ 10,746 $ 0 $ 10,746
Realized losses (4,598) (15) (4,613)
Proceeds from the sale of securities (a) 534,057 73,828 607,885
2019
Realized gains $ 8,478 $ 4 $ 8,482
Realized losses (5,465) 0 (5,465)
Proceeds from the sale of securities (a) 371,538 149,458 520,996

(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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

The fair value of ~~APS's~~APS’s fixed income securities, summarized by contractual maturities, at ~~September 30, 2020,~~March 31, 2021, is as follows (dollars in thousands):


		Nuclear Decommissioning Trust		Coal Mine Reclamation Escrow Account		Active Union Employee Medical Account		Total			Nuclear Decommissioning Trust		Coal Reclamation Escrow Account		Active Union Employee Medical Account		Total
Less than one year	Less than one year	$	23,079	$	34,578	$	40,506	$	98,163	Less than one year	$	25,048	$	26,259	$	40,469	$	91,776
1 year – 5 years	1 year – 5 years	146,885		29,041		142,938		318,864		1 year – 5 years	147,347		34,936		160,324		342,607
5 years – 10 years	5 years – 10 years	122,619		2,772		0		125,391		5 years – 10 years	137,479		2,708		63,477		203,664
Greater than 10 years	Greater than 10 years	221,020		8,923		0		229,943		Greater than 10 years	195,004		8,721		0		203,725
Total	Total	$	513,603	$	75,314	$	183,444	$	772,361	Total	$	504,878	$	72,624	$	264,270	$	841,772

~~13. New Accounting Standards~~

~~ASU 2016-13, Financial Instruments: Measurement of Credit Losses~~

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. See Note 2 for allowance for doubtful accounts related credit loss disclosures.

6462

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~14.~~13. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle ~~West's~~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
Three Months Ended September 30
Balance June 30, 2020 $ (56,326) $ (1,549) $ (57,875)
OCI (loss) before reclassifications 0 (659) (659)
Amounts reclassified from accumulated other comprehensive loss 1,043 (a) 0 1,043
Balance September 30, 2020 $ (55,283) $ (2,208) $ (57,491)
Balance June 30, 2019 $ (46,657) $ (979) $ (47,636)
Amounts reclassified from accumulated other comprehensive loss 880 (a) 218 (b) 1,098
Balance September 30, 2019 $ (45,777) $ (761) $ (46,538)


		Pension and Other Postretirement Benefits			Derivative Instruments			Total			Pension and Other Postretirement Benefits			Derivative Instruments			Total
Nine Months Ended September 30
Three Months Ended March 31										Three Months Ended March 31
Balance December 31, 2020										Balance December 31, 2020	$	(60,725)		$	(2,071)		$	(62,796)
OCI (loss) before reclassifications										OCI (loss) before reclassifications	0			262			262
Amounts reclassified from accumulated other comprehensive loss										Amounts reclassified from accumulated other comprehensive loss	1,022		(a)	0			1,022
Balance March 31, 2021										Balance March 31, 2021	$	(59,703)		$	(1,809)		$	(61,512)

Balance December 31, 2019	Balance December 31, 2019	$	(56,522)		$	(574)		$	(57,096)	Balance December 31, 2019	$	(56,522)		$	(574)		$	(57,096)
OCI (loss) before reclassifications	OCI (loss) before reclassifications	(2,008)			(1,916)			(3,924)		OCI (loss) before reclassifications	0			292			292
Amounts reclassified from accumulated other comprehensive loss	Amounts reclassified from accumulated other comprehensive loss	3,247		(a)	282		(b)	3,529		Amounts reclassified from accumulated other comprehensive loss	1,205		(a)	20		(b)	1,225
Balance September 30, 2020		$	(55,283)		$	(2,208)		$	(57,491)

Balance December 31, 2018		$	(45,997)		$	(1,711)		$	(47,708)
OCI (loss) before reclassifications		(2,422)			0			(2,422)
Amounts reclassified from accumulated other comprehensive loss		2,642		(a)	950		(b)	3,592

Balance September 30, 2019		$	(45,777)		$	(761)		$	(46,538)
Balance March 31, 2020										Balance March 31, 2020	$	(55,317)		$	(262)		$	(55,579)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5.

(b) These amounts primarily 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 7.

6563

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in ~~APS's~~APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~ (dollars in thousands):

Pension and Other Postretirement Benefits Derivative Instruments Total
Three Months Ended September 30
Balance June 30, 2020 $ (35,025) $ 0 $ (35,025)
Amounts reclassified from accumulated other comprehensive loss 900 (a) 0 900
Balance September 30, 2020 $ (34,125) $ 0 $ (34,125)
Balance June 30, 2019 $ (26,297) $ (979) $ (27,276)
Amounts reclassified from accumulated other comprehensive loss 755 (a) 218 (b) 973
Balance September 30, 2019 $ (25,542) $ (761) $ (26,303)


		Pension and Other Postretirement Benefits			Derivative Instruments			Total			Pension and Other Postretirement Benefits			Derivative Instruments			Total
Nine Months Ended September 30
Three Months Ended March 31										Three Months Ended March 31
Balance December 31, 2020										Balance December 31, 2020	$	(40,918)		$	0		$	(40,918)

Amounts reclassified from accumulated other comprehensive loss										Amounts reclassified from accumulated other comprehensive loss	927		(a)	0			927
Balance March 31, 2021										Balance March 31, 2021	$	(39,991)		$	0		$	(39,991)

Balance December 31, 2019	Balance December 31, 2019	$	(34,948)		$	(574)		$	(35,522)	Balance December 31, 2019	$	(34,948)		$	(574)		$	(35,522)
OCI (loss) before reclassifications	OCI (loss) before reclassifications	(1,951)			292			(1,659)		OCI (loss) before reclassifications	0			292			292
Amounts reclassified from accumulated other comprehensive loss	Amounts reclassified from accumulated other comprehensive loss	2,774		(a)	282		(b)	3,056		Amounts reclassified from accumulated other comprehensive loss	1,013		(a)	20		(b)	1,033
Balance September 30, 2020		$	(34,125)		$	0		$	(34,125)

Balance December 31, 2018		$	(25,396)		$	(1,711)		$	(27,107)
OCI (loss) before reclassifications		(2,414)			0			(2,414)
Amounts reclassified from accumulated other comprehensive loss		2,268		(a)	950		(b)	3,218

Balance September 30, 2019		$	(25,542)		$	(761)		$	(26,303)
Balance March 31, 2020										Balance March 31, 2020	$	(33,935)		$	(262)		$	(34,197)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5.

(b) These amounts primarily 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 7.

6664

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~15.~~14. Income Taxes

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~~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 ~~has~~ recorded $14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities inas 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. ~~As of September 30, 2020, the~~The Company ~~has~~ recorded ~~$24~~$6 million and $6 million of income tax benefit related to amortization of these depreciation related ~~liabilities.~~net excess deferred tax liabilities as of March 31, 2021 and March 31, 2020, respectively. See Note 4 for more details.

In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018. However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018.

In September 2020, U.S. Treasury issued final regulations, which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The final regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 continues to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. These final regulations do not materially impact any tax position taken or expected to be taken by the Company for property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is no0 income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 6 for additional details related to the Palo Verde sale leaseback VIEs.

As of the balance sheet date, the tax year ended December 31, 2017 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before ~~2015.~~2016.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~16.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 2020 through 2050. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with 3 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 6 for a discussion of VIEs.

On June 1, 2020, APS had 2 separate purchased power lease contracts that commenced. The lease terms end on September 30, 2025 and September 30, 2026, respectively. Both of these leases allow APS the right to the generation capacity from certain natural-gas fueled generators during the months of June through September over the contract term. APS does not operate or maintain these leased assets. APS controls the dispatch of the leased assets during the months of June through September and is required to pay a fixed monthly capacity payment during these periods of use. 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 tables provide information related to our lease costs (dollars in thousands):~~

Three Months Ended
September 30, 2020 Three Months Ended
September 30, 2019
Purchased Power Lease Contracts Land, Property & Equipment Leases Total Purchased Power Lease Contracts Land, Property & Equipment Leases Total
Operating lease cost $ 51,662 $ 4,655 $ 56,317 $ 21,095 $ 4,581 $ 25,676
Variable lease cost 40,658 232 40,890 36,917 183 37,100
Short-term lease cost 0 1,038 1,038 0 812 812
Total lease cost $ 92,320 $ 5,925 $ 98,245 $ 58,012 $ 5,576 $ 63,588

Nine Months Ended
September 30, 2020 Nine Months Ended
September 30, 2019
Purchased Power Lease Contracts Land, Property & Equipment Leases Total Purchased Power Lease Contracts Land, Property & Equipment Leases Total
Operating lease cost $ 68,883 $ 13,959 $ 82,842 $ 35,159 $ 13,343 $ 48,502
Variable lease cost 102,052 730 102,782 95,736 543 96,279
Short-term lease cost 0 2,824 2,824 0 3,477 3,477
Total lease cost $ 170,935 $ 17,513 $ 188,448 $ 130,895 $ 17,363 $ 148,258

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Condensed 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 fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements, we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.

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

September 30, 2020
Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total
2020 (remaining three months of 2020) $ 14,889 $ 3,294 $ 18,183
2021 66,658 13,402 80,060
2022 68,325 9,781 78,106
2023 70,033 7,443 77,476
2024 71,784 5,162 76,946
2025 73,578 3,457 77,035
Thereafter 36,759 36,961 73,720
Total lease commitments 402,026 79,500 481,526
Less imputed interest 15,565 18,407 33,972
Total lease liabilities $ 386,461 $ 61,093 $ 447,554

We recognize lease assets and liabilities upon lease commencement. At September 30, 2020, we have additional lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to purchased power lease contracts with lease commencement dates beginning in May 2021 with terms ending in October 2027. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $258 million over the term of the arrangements.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

Nine Months Ended
September 30, 2020 Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows: $ 56,896 $ 51,980
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 436,587 8,759

September 30, 2020 December 31, 2019
Weighted average remaining lease term 7 years 13 years
Weighted average discount rate (a) 1.69 % 3.71 %

(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.

~~17.Asset Retirement Obligations~~

During the nine months ended September 30, 2020, the Company 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 Navajo Plant relating to corrective action and water monitoring costs (see additional details in Notes 4 and 8).

~~The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2020 (dollars in thousands):~~


	~~2020~~
~~Asset retirement obligations at January 1, 2020~~	$	~~657,218~~
~~Changes attributable to:~~
~~Accretion expense~~	~~29,454~~
~~Settlements~~	~~(5,611)~~
~~Estimated cash flow revisions~~	~~5,190~~
~~Asset retirement obligations at September 30, 2020~~	$	~~686,251~~

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.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Combined Notes that appear in Item 1 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see ~~"Forward-Looking Statements"~~“Forward-Looking Statements” at the front of this report and ~~"Risk Factors"~~“Risk Factors” in Part 1, Item 1A of the ~~2019~~2020 Form 10-K, ~~Part II, Item 1A of the 2020 1st and 2nd Quarter 10-Q~~ and Part II, Item 1A of this report.

OVERVIEW

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about $20 billion. For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS. APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.3 million retail customers in 11 of Arizona’s 15 counties. APS is also the operator and co-owner of Palo Verde — a primary source of electricity for the southwest United States and the largest nuclear power plant in the United States.

COVID-19 Pandemic

The COVID-19 pandemic continues to be ~~a rapidly~~an evolving situation. ~~It has led to economic disruption and volatility in financial markets worldwide.~~ The Company is operating under long-standing ~~crisis~~pandemic and business continuity plans that exist to address situations including pandemics like COVID-19. We are focused on ensuring the health and safety of our employees, contractors and the general public by helping limit the spread of this virus and ensuring continued, safe and reliable electric service for APS customers.

We have identified business-critical positions in our operations and support organizations, with backup personnel ready to assist if an issue were to arise. Additionally, efforts to ensure the health and safety of our employees have resulted in bifurcated control rooms, thus reducing the number of employees in mission-critical ~~locations,~~locations. We also established COVID-19 safety protocols, social distancing practices including limiting one employee per vehicle ~~for social distancing~~ and offering virtual options whenever possible. The Company also took rapid action to implement an all Company COVID-19 hotline, a focused COVID-19 team, and procured on-site COVID-19 testing at key facilities early in the pandemic. Through this testing, case management and contact tracing, the Company has been able to significantly limit COVID-19 transmission in the workplace. As a result of these efforts, we have been able to maintain the continuity of the essential services that we provide to our customers, while also managing the spread of the virus and promoting the health, physical and mental well-being and safety of our employees, customers and communities.

Essential planned work and capital investments are continuing during the pandemic with ~~some non-essential planned work postponed~~priority to ~~the fourth quarter of 2020. The Company conducted a contract review~~support fire mitigation and summer preparedness. APS has continuous discussions with suppliers on manpower and supply issues pertaining to ~~confirm adequacy of needed summer resources~~COVID-19 and has measures in place to continue to monitor resource needs and supply chain adequacy. At this time, ~~the Company~~APS does not believe it has any material supply chain risks due to COVID-19 that would impact its ability to serve customers’ needs.

The ~~Company's~~Company’s operations and maintenance expenses, exclusive of bad debt expense, increased by approximately ~~$14~~$3 million for the ~~nine months~~period ended ~~September 30, 2020~~March 31, 2021 due to costs for personal protective equipment and other health and safety-related costs related to COVID-19. We expect the Company’s operation and maintenance expenses will continue to be impacted for ~~the remainder of 2020~~2021 by the need for additional personal protective equipment and other health and safety-related costs related to COVID-19.

While the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. From March 13 through September 30, 2020, the cumulative impact in weather-normalized usage was negative 1%. During that period, APS’s retail electric residential weather-normalized sales increased 6%, and its retail electric commercial and industrial weather-normalized sales decreased 7% in the aggregate. APS expects ~~the reduction in electric demand from commercial and industrial customers and increased demand from residential customers~~sales trends to normalize somewhat ~~during the remainder of 2020 and into~~in 2021 as business activity continues to recover and more people return to work. Based on past experience, a 1% variation in our annual kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.

On March 31, 2020, a stay at home order became effective for the state of Arizona and remained in effect until May 16, 2020, when it was lifted and Arizona began reopening. In June 2020, Arizona saw an increase in the number of COVID-19 cases, hospitalizations, and deaths. Accordingly, on June 29, 2020, the governor of Arizona closed bars, indoor gyms and fitness clubs or centers, indoor movie theaters, water parks and tubing operations until July 27, 2020 as a partial reversal of the state’s reopening and to mitigate the spread of COVID-19. On July 23, 2020, the governor of Arizona extended these closures and they remained in place until August 27, when bars, gyms and movie theaters reopened with certain restrictions. We cannot predict the impact of the spread of COVID-19 in Arizona, whether there will be additional reclosures and how any such reclosures will impact our financial position, results of operations or cash flows. We are continuing to monitor the impacts of COVID-19.

As a result of the COVID-19 pandemic, in mid-March 2020, the commercial paper markets failed to function normally and we were unable to utilize commercial paper as our primary method of acquiring short-term capital, which resulted in us drawing on our revolving credit facilities during the first quarter of 2020. In mid-April 2020, we were again able to utilize the commercial paper market and we have paid down the entire amount of the revolving credit facilities that were utilized as a result of the commercial paper market failure.

The Coronavirus Aid, Relief, and Economic Security (CARES) Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020 through December 31, 2020. We ~~are deferring~~deferred the cash payment of the ~~employer's~~employer’s portion of Social Security payroll taxes for the period July 1, 2020 through December 31, 2020 that ~~we expect will be in the range of $15 million to $20~~was approximately $18 million. We will pay half of this cash deferral by December 31, 2021 and the remainder by December 31, 2022.

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. 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 both 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 ~~will~~did not have a material impact on our financial statements. See Note ~~1 in our 2019 Form 10-K for information on the accounting treatment for AFUDC.~~1.

nonpayment ended on January 1, 2021 and ~~waiver~~customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until ~~December 31, 2020.~~October 15, 2021. APS ~~currently estimates that the Summer Disconnection Moratorium (see Note 4), the suspension of disconnections during the COVID-19 pandemic~~has experienced and ~~the increased bad debt expense associated with both events will result in a negative impact~~is continuing to its 2020 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. APS is experiencingexperience an increase in bad debt expense associated with the COVID-19 pandemic, ~~but it still believes that costs associated with~~ the Summer Disconnection Moratorium and the ~~COVID-19 disconnection suspensions and~~ related ~~bad debt expense with both events will fall within this estimated $20 million to $30 million range.~~write-offs of customer delinquent accounts. APS ~~also~~ currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with this will result in a negative impact to its 2021 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection ~~Moratorium.~~Moratorium or COVID-19 pandemic. These estimated impact amounts for ~~2020 and~~ 2021 depend on certain current assumptions, including, but not limited to, customer behaviors, population and employment growth, and the impacts of COVID-19 on the economy. ~~Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 (see~~See Note ~~4).~~4.

programs, directly to customers through a bill credit in June 2020 (see Note 4). ~~As of September 30, 2020,~~ APS ~~had~~has refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020. In February 2021, APS delayed the annual reset of the PSA. Rather than the increase being effective February 2021, the PSA reset will be implemented with 50% of the increase effective April 2021 and the remaining 50% increase effective November 2021. See Note 4.

More detailed discussion of the impacts and future uncertainties related to the COVID‑19 pandemic can be found throughout this ~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Combined Notes to Pinnacle ~~West's~~West’s and ~~APS's~~APS’s financial statements that appear in Item ~~1of this report and "Risk Factors" in Part II, Item 1A of the 2020 1st and 2nd Quarter 10-Q and Part II, Item 1A~~1 of this report.

Strategic Overview

Our strategy is to deliver shareholder value by creating a sustainable energy future for Arizona by serving our customers with clean, reliable and affordable energy.

Clean Energy Commitment

We are committed to doing our part to make the future clean and carbon-free. Our vision for APS and Arizona presents an opportunity to engage with customers, communities, employees, policymakers, shareholders and others to achieve a shared, sustainable vision for Arizona. This goal is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for ~~APS's~~APS’s customers.

~~APS's~~APS’s new clean energy goals consist of three parts:

•A 2050 goal to provide 100% clean, carbon-free electricity;

•A 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and

•A commitment to end APS’s use of coal-fired generation by 2031.

~~APS's~~

APS’s ability to successfully execute its clean energy commitment is dependent upon a number of important external factors, some of which include a supportive regulatory environment, sales and customer growth, development of clean energy technologies and continued access to capital markets.

2050 Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration. The 2050 goal will involve new thinking and depends on improved and new technologies.

2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of ~~APS's~~APS’s generation portfolio coming from renewable energy. ~~“Clean”~~“Clean” is measured as percent of energy mix which includes all carbon-free resources like nuclear and demand-side management, and “renewable” is expressed as a percent of retail sales. This target will serve as a checkpoint for our resource planning, investment strategy, and customer affordability efforts as APS moves toward 100% clean, carbon-free energy mix by 2050.

~~APS~~ understands that closing its coal-fired power plants will significantly impact employees as well as the surrounding communities. APS will continue to engage in meaningful dialogue with these stakeholders in order to explore, better understand and prepare to address a range of potential effects, including environmental, social and economic impacts.

2031 Goal: End ~~APS's~~APS’s Use of Coal-Fired Generation. ~~The~~Our commitment to end ~~APS's~~APS’s use of coal-fired generation by 2031 will require APS to cease use of coal-generation at Four Corners. APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity. These closures and other measures taken by APS have resulted in a total reduction of carbon emissions of ~~26%~~33% since 2005. In addition, APS has committed to end the use of coal at its remaining Cholla units by 2025.

APS understands that the transition away from coal-fired power plants toward a clean energy future will pose unique economic challenges for the communities around these plants. We worked collaboratively with stakeholders and leaders of the Navajo Nation to consider the impacts of ceasing operation of APS coal-fired power plants on the communities surrounding those facilities to propose a comprehensive Coal Community Transition (“CCT”) plan. The proposed framework provides substantial financial and economic development support to build new economic opportunities and addresses a transition strategy for plant employees. We are committed to continuing our long-running partnership with the Navajo Nation in other areas as well, including expanding electrification and developing tribal renewable projects. Our proposed CCT plan supports the Navajo Nation, where the Four Corners Power Plant is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which is impacted by closure of the Navajo Plant. The CCT plan is currently pending ACC approval. See Note 4 for a discussion of the CCT plan.

In March 2021, APS announced that it had agreed on the terms of an agreement among the owners of Four Corners to operate Four Corners seasonally beginning in Fall 2023, subject to the necessary approvals. Under seasonal operation, APS is planning that one of Four Corners’ two remaining units will operate only throughout the summer season of June through October when customers’ energy needs are the highest across the region. APS believes that operating Four Corners seasonally will bring environmental benefits and ensure continued service reliability for its customers, especially during Arizona’s hot summer months, as APS transitions to ceasing to use coal-fired generation by 2031. By moving to seasonal operations, Four Corners will become a more flexible resource that supports increasing amounts of clean energy, helping to compensate for the intermittent output of renewable resources. This change also helps ensure reliability of a critical energy source while reducing operations and maintenance costs. APS estimates that the shift to seasonal operations will reduce annual carbon emissions at Four Corners by an estimated 20-25%, as compared to current conditions.

Renewables. APS intends to strengthen its already diverse energy mix by increasing its investments in carbon-free resources. Its near-term actions include competitive solicitations to procure clean energy resources such as solar, wind, energy storage, demand response and DSM resources, all of which lead to a cleaner grid.

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APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas. ~~APS's~~APS’s clean energy strategy includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS. The following table summarizes the resources in ~~APS's~~APS’s renewable energy portfolio that are in operation and under development as of ~~September 30, 2020.~~March 31, 2021. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.


		Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)			Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar	Total APS Owned: Solar	244	—		Total APS Owned: Solar	246	—
Purchased Power Agreements:	Purchased Power Agreements:				Purchased Power Agreements:
Solar	Solar	310	—		Solar	310	160
Solar + Energy Storage		—	50
Wind (a)	Wind (a)	289	110		Wind (a)	289	110
Geothermal	Geothermal	10	—		Geothermal	10	—
Biomass	Biomass	14	—		Biomass	14	—
Biogas	Biogas	3	—		Biogas	3	—
Total Purchased Power Agreements	Total Purchased Power Agreements	626	160		Total Purchased Power Agreements	626	270
Total Distributed Energy: Solar (b)	Total Distributed Energy: Solar (b)	1,050	45	(c)	Total Distributed Energy: Solar (b)	1,122	45	(c)
Total Renewable Portfolio	Total Renewable Portfolio	1,920	205		Total Renewable Portfolio	1,994	315

(a) Includes 90 MW wind power purchase agreement that is currently in operation that will be decommissioned in 2021 and rebuilt in the same year, together with an additional 110 MW, for a total of 200 MW, as a result of a power purchase agreement executed in September 2020.

(b) Includes rooftop solar facilities owned by third parties. Distributed generation is produced in Direct Current and is converted to ACAlternating Current for reporting purposes.

In September 2019, APS ~~has developed and owns solar resources through the ACC-approved AZ Sun Program. APS also~~ issued ~~two Requests for Proposal ("RFP") in September 2019. The first~~a RFP seeks competitive proposals for up to 150 MW of APS-owned solar resources to be in service by 2021. This solar generation will be designed with the flexibility to add energy storage as a future option. Negotiations pursuant to this RFP are ongoing, with results expected in the fourth quarter of 2020. A second RFPthat requested up to 250 MW of wind resources to be in service as soon as possible, but no later than 2022.As a result of this RFP, APS executed a 200 MW power purchase agreement for a wind resource that is expected to be in service in the fourth quarter of 2021. Also in September 2019, APS issued a RFP that sought competitive proposals for up to 150 MW of APS-owned solar resources, designed with the flexibility to add energy storage as a future option. Negotiations pursuant to this RFP were terminated in March 2021. In December 2020, APS issued two additional RFPs: one to acquire both renewable energy and additional peaking capacity resources, and the other to install more battery energy storage at two existing APS solar plants. In April 2021, the RFPs that were issued in December 2020 were expanded to seek development of a solar generating resource to be sited on APS land and owned by APS.

Palo Verde. Palo Verde, the nation’s largest carbon-free, clean energy resource, will continue to be a foundational part of ~~APS's~~APS’s resource portfolio. The plant currently supplies nearly 70% of our clean energy and provides the foundation for the reliable and affordable service for APS customers. Palo Verde is not just the cornerstone of our current clean energy mix, it also is a significant provider of clean energy to the southwest United States. The ~~plant’s~~plant is a critical asset to the Southwest, generating more than 32 million megawatt-hours annually – enough power for more than 4 million people. Its continued operation is important to a carbon-free and clean energy future for Arizona and the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy.

7570

Affordable

We believe it is ~~APS's~~APS’s responsibility to deliver electric services to customers in the most cost-effective manner. Since January 2018 through ~~September 2020,~~April 2021, the average residential bill decreased by ~~7.3%~~6.2%, or ~~$10.95.~~$9.28 due to net reductions in cost recovery adjustor mechanisms.

Building upon existing cost management efforts, APS launched a customer affordability initiative in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and internal efficiencies. Through the initiative and existing cost management practices, in 2020, APS ~~identified $20 million in possible cost savings for 2020 and, as~~met its goal of ~~September 30, 2020, has surpassed~~ $20 million in cost ~~savings that will be realized by year-end 2020.~~savings. In 2021, APS continues to drive this initiative to identify opportunities to streamline its business processes and deliver sustainable cost savings.

Participation in the EIM continues to be an effective tool for creating savings for ~~our~~APS’s customers from the real-time, voluntary market. ~~As of September 30, 2020, the EIM has delivered approximately $181 million in gross benefits~~APS continues to ~~APS customers since APS began participating~~expect that its participation in EIM will lower its fuel and purchased-power costs, improve visibility and situational awareness for system operations in ~~2016.~~the Western Interconnection power grid, and improve integration of APS’s renewable resources. APS continues to evaluate opportunities that benefit our customers and is in discussions with the EIM operator, ~~CAISO,~~California Independent System Operator, Inc. (“CAISO”), and other EIM participants about the feasibility of creating a voluntary day-ahead market to achieve more cost savings and use the region’s renewable resources more efficiently.

Reliable

While our energy mix evolves, the obligation to deliver reliable service to our customers remains. ~~Excluding voluntary outages~~Notwithstanding the challenges presented by the COVID-19 pandemic as well as the hottest summer on record, APS continued to provide reliable service to its customers in 2020, setting a new all-time high peak energy demand of 7,660 MW, exceeding the prior peak set in 2017 by nearly 300 MW and ~~proactive fire mitigation efforts, APS finished 2019 with its best score for frequency of customer power outages.~~achieved strong reliability results.

Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth and enabling more renewable energy resources. Our advanced distribution management system allows operators to locate outages, control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid. The system also integrates a new meter data management system that increases grid visibility and gives customers access to more of their energy usage data.

Wildfire safety remains a critical focus for APS and other utilities. We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, build partnerships with government entities and first responders and educate customers and communities. These programs contribute to customer reliability, responsible forest management and safe communities.

The new units at our modernized Ocotillo ~~power plant~~Power Plant provide cleaner-running and more efficient units. They support reliability by responding quickly to the variability of solar generation and delivering energy in the late afternoon and early evening, when solar production declines as the sun sets and customer demand peaks.

In February 2021, Texas experienced extreme cold weather. Wellheads and gas production infrastructure froze, sharply reducing gas supply at the same time as demand for gas was at a record high due to the frigid weather. As a result, natural gas prices and market electricity prices spiked to historic highs, with gas prices exceeding 100 times the prices seen the preceding weeks. In addition, APS experienced

interruptions or curtailments with six of our natural gas suppliers due to the weather event in Texas. These interruptions and curtailments did not impact APS’s ability to deliver power to its customers. APS does not believe that the Texas event materially impacted its financial position, results of operations, or cash flows.

In April 2021, the CAISO sought FERC authorization for certain tariff changes intended to try to address risks associated with high heat weather events. Although APS is generally supportive of some of these changes, others would change the load, export, and wheeling priorities in a way that would unfairly benefit California entities at the expense of non-California entities. As such, APS intends to formally oppose these changes in front of FERC. APS cannot predict the outcome of these proceedings. Nor can PNW or APS predict whether energy shortages, market priorities, and/or price spikes due to extreme weather conditions will have an impact on its financial position, results of operations or cash flows.

APS’s key elements to delivering reliable power include resource planning, sufficient reserve margins, customer partnerships to manage peak demand, fire mitigation, and operational preparedness. Seasonal readiness procedures at APS also include walkdowns to ensure good material conditions and critical control system surveys. APS also plans for the unexpected by conducting emergency operations drills and coordinating on fire and emergency management with federal, state, and local agencies.

Customer-Focused

Customers are at the core of what APS does every day and ~~APS is committed to providing options that make it easier for~~its focus remains on its customers and the communities it serves. It is APS’s goal to do business with them. In 2019, APS launched its redesigned aps.com website and mobile app, giving customers upgraded access to their energy usage data and billing information. APS's Customer Care team is using speech analytics to enrich advisors’ interactions with customers over the telephone, and customers can also communicate with APS throughachieve an ~~online chat.~~industry-leading best-in-class customer experience.

In 2020, APS ~~expanded financial help~~adopted a number of changes to improve customer experience. It transitioned to a 24/7 care center operation to better serve its customers around the clock. APS improved its call center performance, answering nearly 75% of its more than 1.5 million telephone calls in 30 seconds or less. APS has also made many improvements to its digital experience through its aps.com site, and its overall digital experience continues to improve for its ~~most vulnerable customers~~customers. APS has also implemented a project to redesign and improve its customer bills, completing the customer research portion of this project in ~~2019, allocating $2.75 million in crisis bill assistance and increasing~~ the individual benefit for qualifying customers from $400 to $800 per year. The APS Solar Communities program has allowed more than 600 limited- and moderate-income customers to support clean energy and save money by hosting APS-owned solar systems on their residences in exchange for a monthly bill credit.first quarter of 2021.

APS continues to develop and deploy innovative programs that connect customers with advanced technologies to help them manage their bills and encourage energy use during midday, when solar power is most abundant. Three energy storage programs incorporating smart thermostats, connected water heaters and batteries are helping customers shift energy use to times when they can take advantage of low-cost, abundant energy and reduce peak demand on APS's system.

~~In 2020, APS~~also convened a customer advisory board and stakeholder committee in 2020 to serve as a vehicle for gathering valuable qualitative insights, directly from customers and stakeholders, that ~~will~~intends to keep APS apprised of customer needs, wants, and perspectives. Additionally, the customer advisory board is leveraged to identify and diagnose potential customer pain points and to help shape and co-create customer solutions.

~~Also~~ The customer advisory board completed two engagements in ~~2020, APS created~~ the ~~CARE Team,~~ ~~a group~~first quarter of ~~customer service advisors in conjunction with local human services agencies,~~ ~~to provide direct support to customers through field events throughout the state. The CARE Team~~ ~~will resume providing in-person customer support in communities APS serves once it is safe to do so because of the COVID-19 pandemic.~~2021, addressing rate plan simplification and bill redesign.

APS is also providing assistance to residential and business customers that have been impacted by the COVID-19 pandemic. See ~~"COVID-19 Pandemic"~~“COVID-19 Pandemic” above for more information about ~~pandemic relief.~~customer support during COVID-19.

~~Emerging~~

Developing Clean Energy Technologies

Energy Storage

APS deploys a number of advanced technologies on its system, including energy storage. Storage can provide capacity, improve power quality, be utilized for system regulation, integrate renewable generation, and in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage can also aid in integrating higher levels of renewables by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to benefit customers, to increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid. We are preparing for additional energy storage in the future.

In early 2018, APS entered into a 15-year power purchase agreement for a 65 MW solar facility that charges a 50 MW solar-fueled battery. Service under ~~this~~the agreement iswas scheduled to begin in ~~2021.~~2021; however, APS terminated the agreement, effective February 16, 2021, because project development could not be sufficiently advanced to support the expected in-service date. In 2018, APS issued an RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon ~~our~~its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. ~~We originally anticipated such~~These battery storage facilities ~~could~~are expected to be in service by ~~mid-2020.~~June 2022. Additionally, in February 2019, APS signed two 20-year ~~power purchase agreements~~PPAs for energy storage totaling 150 MW. In April 2019, a battery module in APS’s McMicken battery energy storage facility experienced an equipment failure, which prompted an internal investigation to determine the cause. APS has now completed its investigation of the McMicken battery incident and is ~~continuing to determine the timing of future deployment of batteries on APS's system. Due to the McMicken battery incident, APS is~~ working with all counterparties to ~~determine appropriate timing~~ensure that the learnings from the investigation, and ~~paths forward. Service under~~the corresponding safety requirements, are incorporated into all battery storage projects going forward, including the projects associated with the two ~~power purchase agreements, which was~~above-referenced PPAs. These PPAs were also ~~dependent on the results of the McMicken battery incident investigation, requires~~subject to ACC approval ~~from the ACC~~in order to allow for cost recovery ~~of these agreements~~ through the PSA.

APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to begin in 2022.

We currently plan to install at least 850 MW of energy storage by 2025, including the energy storage projects under ~~power purchase agreements~~PPAs and AZ Sun retrofits described above. The ~~additional~~remaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS has two RFPs in the ~~retrofits associated with our~~market that seek energy storage resources: (i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites ~~as described above, along with current~~that were not included in the 2018 RFP referenced in the preceding paragraph; and ~~future RFPs for~~(ii) an ‘all source’ RFP that solicits both standalone energy storage and ~~solar~~renewable energy plus energy storage ~~projects. Given the April 2019 event, we continue~~resources. Such resources are expected to ~~evaluate the appropriate timing~~be in service during 2023 and ~~path forward to support the overall capacity goals for our system and associated energy storage requirements.~~2024.

Electric Vehicles

APS ~~plans to make~~is making electric vehicle charging more accessible for its customers and ~~help~~helping Arizona businesses, schools and governments electrify their fleets. In ~~2019,~~2020, APS ~~implemented~~expanded its Take Charge AZ Pilot ~~Program.~~Program and installed 84 dual-plug Level 2 charging stations at business customer locations with more stations expected to be added through 2021. The program provides charging equipment, installation, and maintenance to business customers, government agencies, and multifamily housing communities. ~~Rates are designed~~In addition to ~~encourage~~the Level 2 charging ~~overnight~~stations, APS will begin construction of direct current fast charging stations that will be owned and ~~during daytime off-peak hours when solar energy~~operated by APS at five locations in Arizona. This project is ~~abundant.~~projected to be completed by the end of 2021 with each location including 2-150 kilowatt and 2-350 kilowatt DC fast charging stations. These stations will be accessible through the Electrify America charging network.

The ACC ordered the state’s public service corporations, including APS, to develop a long-term, comprehensive Statewide Transportation Electrification Plan (“TE Plan”) for Arizona. The TE Plan is intended

to provide a roadmap for Transportation Electrification in Arizona, focused on realizing the associated air quality and economic development benefits for all residents in the state along with understanding the impact of electric vehicle charging on the grid. APS is actively participating in this process, which ~~is scheduled to be completed by the end of 2020 and~~was submitted in April 2021 to the ACC for review and approval.

Hydrogen Production

Palo Verde, in partnership with Idaho National Laboratory (“INL”) and ~~two other utilities,~~Energy Harbor Corporation and Xcel Energy Incorporated, has been chosen by the ~~DOE's~~DOE’s Office of Nuclear Energy to participate in a hydrogen production project with the goal to improve the long-term economic competitiveness of the nuclear power industry. The multi-phase project is planned for 2020 through 2023. In the first phase, ~~Idaho National Laboratory will perform~~INL performed a technical and economic assessment of using electricity generated at Palo Verde to produce hydrogen that could be blended for co-firing in natural-gas-fired combustion turbines during times of the day when photovoltaic solar energy sources are not available and energy reserves in the southwest United States are low.hydrogen.

~~Experience~~Based on the experience from Palo ~~Verde's~~Verde’s utility partners’ demonstration projects and from the Palo Verde-specific technical and economic assessment ~~will offer insights into methods~~performed by INL, PNW Hydrogen LLC, a subsidiary of Pinnacle West, recently submitted a request for ~~flexible transitions between electricity and~~funding to the DOE’s Office of Nuclear Energy to support moving forward with a hydrogen ~~generation in solar-dominated electricity markets, and demonstrate how hydrogen may be used as energy storage to provide electricity during operating periods when solar is not available.~~production pilot.

Carbon Capture

Carbon capture technologies can isolate CO2 and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. Carbon capture technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired. APS will continue to monitor this emerging technology.

Regulatory Overview

On October 31, 2019, APS filed an application with the ACC seeking an ~~annual~~ increase in annual retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners SCR project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” in Note 4). 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~~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~~APS’s application ~~are:~~were:

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

•an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•the following proposed capital structure and costs of capital:


	Capital Structure		Cost of Capital
Long-term debt	45.3	%	4.1	%
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 Base Fuel Rate of $0.030168 per kWh;

•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~~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 Note 4 discussion 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 Note 4 for details related to the resulting regulatory asset).

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

construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

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 ~~is continuing to assess all~~ 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 (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) the CCT plan related to the closure or future closure of coal-fired generation facilities of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components: (i) $100 million that will ~~file rebuttal testimony with updated positions no later than November 6, 2020.The hearing~~be paid over 10 years to the Navajo Nation for ~~this rate case was delayed, at~~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 ~~request~~Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7

million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers.

See Note 4 for information regarding additional regulatory matters.

Arizona Attorney General Matter

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 results in APS paying $24.75 million, $24 million of which is being 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.

Financial Strength and Flexibility

Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Other Subsidiaries

Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. ~~BCE's~~BCE’s strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry. In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.

On December 20, 2019, BCE acquired minority ownership positions in two wind farms under development by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek wind farm in Missouri ("(“Clear ~~Creek"~~Creek”) and the 250 MW Nobles 2 wind farm in Minnesota ("(“Nobles 2"2”). Clear Creek achieved commercial operation in May 2020 and Nobles 2 ~~is expected to achieve~~achieved commercial operation in ~~2020 and deliver power later this year.~~December 2020. Both wind farms deliver power under long-term power purchase agreements. BCE indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.

El Dorado. El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures. El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund.

Key Financial Drivers

In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Electric Operating Revenues. For the years ~~2017~~2018 through ~~2019,~~2020, retail electric revenues comprised approximately 95% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased ~~2.3%~~2.1% for the ~~nine-month~~three-month period ended ~~September 30, 2020~~March 31, 2021 compared with the prior-year period. For the three years ~~2017~~2018 through ~~2019,~~2020, APS’s customer growth averaged ~~1.8%~~2.0% per year. We currently project annual customer growth to be ~~1.5 -~~1.5% to 2.5% for ~~2020~~2021 and for ~~2020~~2021 through ~~2022~~2023 based on our assessment of steady population growth in Arizona.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased ~~0.4%~~0.5% for the ~~nine-month~~three-month period ended ~~September 30, 2020~~March 31, 2021 compared with the prior-year period. While steady customer growth was offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong residential sales due to work-from-home policies, ~~and~~ a gradual improvement in sales to commercial and industrial ~~sales (although commercial~~

customers, and ~~industrial sales are still negative for~~ the ~~year).~~ramp-up of new data center customers. Though the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. From March 13 through September 30, 2020, the cumulative impact in weather-normalized usage was negative 1%. During that period, APS’s retail electric residential weather-normalized sales increased 6%, and its retail electric commercial and industrial weather-normalized sales decreased 7% in the aggregate. APS expects ~~the reduction in electric demand from commercial and industrial customers and increased demand from residential customers~~sales trends to normalize somewhat ~~during the remainder of 2020 and~~ into 2021 as business activity continues to recover and more people return to work.

For the three years ~~2017~~2018 through ~~2019,~~2020, annual retail electricity sales were about flat, adjusted to exclude the effects of weather variations. We currently project that annual retail electricity sales in kWh will ~~have flat~~increase in the range of 0.5% to ~~1.0% growth~~1.5% for ~~2020~~2021 and increase on average in the range of ~~0.5 - 1.5%~~1.0% to 2.0% during ~~2020~~2021 through ~~2022,~~2023, including the effects of customer conservation, energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations and excluding the impacts of several new, large ~~data centers~~manufacturing facilities opening operations in Metro Phoenix. The impact of the new, large ~~data centers could raise~~manufacturing facilities is likely to increase the ~~range of~~ expected annual sales growth rate ~~over the 2020 to~~as early as 2022, ~~period,~~ but demand from these customers remains uncertain at this ~~time.~~point. This projected sales growth range also includes our estimated contributions of several large data centers, but not all, and we will continue to estimate contributions and evaluate sales guidance as these customers develop more usage history. These estimates could be further impacted by slower than expected growth of the Arizona economy, slower than expected ramp-up of the new data centers, or acceleration of the expected effects of customer conservation, energy efficiency, or distributed renewable generation initiatives.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, ramp-up of data centers, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Based on past experience, a 1% variation in our annual kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.

Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historically, extreme weather variations have resulted in annual variations in

net income in excess of $25 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $15 million.

Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Condensed Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.

Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See ~~"Liquidity~~“Liquidity and Capital ~~Resources"~~Resources” below for information regarding the planned additions to our facilities.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was ~~10.9%~~10.8% of the assessed value for 2020, 10.9% for 2019 and 11.0% for ~~2018 and 11.2% for 2017.~~2018. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units and transmission and distribution facilities.

Pension and other postretirement non-service credits - net. Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 3). The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.

Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Act was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. ~~(See~~See Note 1514 for details of the impacts on the Company as of ~~September 30, 2020.)~~March 31, 2021. In ~~APS's~~APS’s 2017 rate case decision, the ACC approved a Tax Expense Adjustor Mechanism which will be

used to pass through the income tax effects to retail customers of the Tax Act. (See Note 4 for details of the TEAM.)

RESULTS OF OPERATIONS

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

Operating Results — Three-month period ended ~~September 30, 2020~~March 31, 2021 compared with three-month period ended ~~September 30, 2019.~~March 31, 2020.

Our consolidated net income attributable to common shareholders for the three months ended ~~September 30, 2020~~March 31, 2021 was ~~$346~~$36 million, compared with consolidated net income attributable to common shareholders of ~~$312~~$30 million for the prior-year period. The results reflect an increase of approximately ~~$35~~$6 million for the regulated electricity segment primarily due to higher revenue driven by lower refunds in the current year related to the Tax Act, the effects of weather and higher transmission revenue, higher pension and other postretirement non-service credits, ~~and higher revenue from customer growth,~~ partially offset by higher income ~~taxes. Weather had a significant impact on our result~~taxes, including lower amortization of excess deferred taxes and higher operations ~~due to the hotter than normal weather in 2020 compared to the same period in 2019.~~and maintenance expense.

The following table presents net income attributable to common shareholders by business segment compared with the prior-year period:


		Three Months Ended September 30,							Three Months Ended March 31,
		2020		2019		Net Change			2021		2020		Net Change
		(dollars in millions)							(dollars in millions)
Regulated Electricity Segment:	Regulated Electricity Segment:							Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	Operating revenues less fuel and purchased power expenses	$	900	$	845	$	55	Operating revenues less fuel and purchased power expenses	$	497	$	472	$	25
Operations and maintenance	Operations and maintenance	(235)		(238)		3		Operations and maintenance	(229)		(221)		(8)
Depreciation and amortization	Depreciation and amortization	(153)		(149)		(4)		Depreciation and amortization	(158)		(154)		(4)
Taxes other than income taxes	Taxes other than income taxes	(55)		(53)		(2)		Taxes other than income taxes	(59)		(57)		(2)
Pension and other postretirement non-service credits - net	Pension and other postretirement non-service credits - net	14		6		8		Pension and other postretirement non-service credits - net	28		14		14
All other income and expenses, net	All other income and expenses, net	16		14		2		All other income and expenses, net	15		16		(1)
Interest charges, net of allowance for borrowed funds used during construction	Interest charges, net of allowance for borrowed funds used during construction	(57)		(54)		(3)		Interest charges, net of allowance for borrowed funds used during construction	(57)		(55)		(2)
Income taxes	Income taxes	(77)		(53)		(24)		Income taxes	4		20		(16)
Less income related to noncontrolling interests (Note 6)	Less income related to noncontrolling interests (Note 6)	(5)		(5)		—		Less income related to noncontrolling interests (Note 6)	(5)		(5)		—
Regulated electricity segment income	Regulated electricity segment income	348		313		35		Regulated electricity segment income	36		30		6
All other	All other	(2)		(1)		(1)		All other	—		—		—
Net Income Attributable to Common Shareholders	Net Income Attributable to Common Shareholders	$	346	$	312	$	34	Net Income Attributable to Common Shareholders	$	36	$	30	$	6

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were ~~$55~~$25 million higher for the three months ended ~~September 30, 2020~~March 31, 2021 compared with the prior-year period. The following table summarizes the major components of this change:


		Increase (Decrease)							Increase (Decrease)
		Operating revenues		Fuel and purchased power expenses		Net change			Operating revenues		Fuel and purchased power expenses		Net change
		(dollars in millions)							(dollars in millions)

Lower refunds in the current year related to the Tax Act (Note 4)								Lower refunds in the current year related to the Tax Act (Note 4)	$	19	$	—	$	19
Effects of weather	Effects of weather	$	53	$	14	$	39	Effects of weather	5		1		4
Refunds due to tax reform (Note 4)		16		—		16
Higher retail revenue due to customer growth and changes in customer usage patterns, including the impacts of COVID-19, partially offset by the impacts of energy efficiency and distributed generation		13		3		10

Higher transmission revenues (Note 4)								Higher transmission revenues (Note 4)	4		—		4

Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(3)		(5)		2		Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	6		7		(1)
Lower renewable energy regulatory surcharges, partially offset by operations and maintenance costs		(3)		(1)		(2)
Lower transmission revenues (Note 4)		(8)		—		(8)
Miscellaneous items, net	Miscellaneous items, net	(5)		(3)		(2)		Miscellaneous items, net	—		1		(1)
Total	Total	$	63	$	8	$	55	Total	$	34	$	9	$	25

Operations and maintenance. Operations and maintenance expenses ~~decreased $3~~increased $8 million for the three months ended ~~September 30, 2020~~March 31, 2021 compared with the prior-year period primarily because of:

•An increase of $7 million in fossil generation costs primarily due to higher planned outages and higher operating costs;

•An increase of $6 million related to employee benefits;

•A decrease of $4 million in nuclear generation costs;

•~~A decrease of $4 million related to consulting costs;~~

•~~A decrease of $4 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;~~

•~~An increase of $7 million primarily related to personal protective equipment and other health and safety-related costs for COVID-19 response;~~

•~~An increase of $3 million related to customer bad debt expenses primarily related to the Summer Disconnection Moratorium and COVID-19 disconnect suspensions (see Note 4);~~ and

•A decrease of $1 million for other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $4 million higher for the three months ended ~~September 30, 2020~~March 31, 2021 compared to the prior-year period primarily due to increased plant in service of ~~$8 million, partially offset by the regulatory deferrals for the Four Corners SCR project and Ocotillo modernization project of $4 million.~~

~~Pension and other postretirement non-service credits, net.~~ Pension and other postretirement non-service credits, net were $8 million higher for the three months ended September 30, 2020 compared to the prior-year period primarily due to higher market returns in 2019.

~~Income taxes.~~ Income taxes were $24 million higher for the three months ended September 30, 2020 compared with the prior-year period primarily due to higher pre-tax income and reduced amortization of excess deferred taxes (see Note 15).

~~Operating Results~~ — ~~Nine-month period ended September 30, 2020 compared with nine-month period ended September 30, 2019.~~

Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2020 was $570 million, compared with consolidated net income attributable to common shareholders of $474 million for the prior-year period. The results reflect an increase of approximately $94 million for the regulated electricity segment primarily due to higher revenue driven by the effects of weather, lower operations and maintenance expense and higher pension and other postretirement non-service credits, partially offset by higher income taxes and depreciation expense. Weather had a significant impact on our result of operations due to the hotter than normal weather in 2020 compared to the same period in 2019.

~~The following table presents net income attributable to common shareholders by business segment compared with the prior-year period:~~

Nine Months Ended September 30,
2020 2019 Net Change
(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses $ 2,062 $ 1,980 $ 82
Operations and maintenance (674) (710) 36
Depreciation and amortization (459) (446) (13)
Taxes other than income taxes (168) (164) (4)
Pension and other postretirement non-service credits - net 42 17 25
All other income and expenses, net 49 46 3
Interest charges, net of allowance for borrowed funds used during construction (170) (161) (9)
Income taxes (98) (72) (26)
Less income related to noncontrolling interests (Note 6) (15) (15) —
Regulated electricity segment income 569 475 94
All other 1 (1) 2
Net Income Attributable to Common Shareholders $ 570 $ 474 $ 96

~~Operating revenues less fuel and purchased power expenses.~~ Regulated electricity segment operating revenues less fuel and purchased power expenses were $82 million higher for the nine months ended September 30, 2020 compared with the prior-year period. The following table summarizes the major components of this change:

Increase (Decrease)
Operating
revenues Fuel and
purchased
power expenses Net change
(dollars in millions)
Effects of weather $ 120 $ 29 $ 91
Refunds due to tax reform (Note 4) 7 — 7
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals (56) (61) 5
Lower retail revenue due to the impacts of energy efficiency, distributed generation and changes in customer usage patterns, including the impacts of COVID-19, partially offset by higher customer growth (2) 3 (5)
Lower renewable energy regulatory surcharges, partially offset by operations and maintenance costs (9) — (9)
Lower transmission revenues (Note 4) (9) — (9)
Miscellaneous items, net (6) (8) 2
Total $ 45 $ (37) $ 82

~~Operations and maintenance. Operations and maintenance expenses decreased $36 million for the nine months ended September 30, 2020 compared with the prior-year period primarily because of:~~

•~~A decrease of $19 million primarily related to an increased recovery from contributions of administrative and general costs from Palo Verde owners;~~

•~~A decrease of $13 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;~~

•~~A decrease of $11 million in fossil generation costs primarily due to lower planned outages and lower operating costs due to the Navajo Plant closure (see Note 4);~~

•~~A decrease of $10 million related to consulting costs;~~

•~~A decrease of $4 million for customer outreach costs;~~

•~~An increase of $14 million primarily related to personal protective equipment and other health and safety-related costs for COVID-19 response;~~

•~~An increase of $8 million related to customer bad debt expenses primarily related to the Summer Disconnection Moratorium and COVID-19 disconnect suspensions (see Note 4);~~

•~~An increase of $6 million for costs related to information technology; and~~

•~~A decrease of $7 million for corporate resources and other miscellaneous factors.~~

~~Depreciation and amortization.~~ ~~Depreciation and amortization expenses were $13 million higher for the nine months ended September 30, 2020 compared to the prior-year period primarily due to increased plant in service of $29~~$5 million, partially offset by the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of ~~$16~~$1 million.

Pension and other postretirement non-service credits, net.Pension and other postretirement non-service credits, net were ~~$25~~$14 million higher for the ~~nine~~three months ended ~~September 30, 2020~~March 31, 2021 compared to the prior-year period primarily due to ~~higher~~actual market returns exceeding estimated returns in ~~2019.~~

~~Interest charges, net of allowance for borrowed funds used during construction.~~ Interest charges, net of allowance for borrowed funds used during construction were $9 million higher for the nine months ended September 30, 2020 compared to the prior-year period primarily due to higher debt balances in the current period.2020.

Income taxes. Income taxes were ~~$26~~$16 million higher for the ~~nine~~three months ended ~~September 30, 2020~~March 31, 2021 compared with the prior-year period primarily due to lower amortization of excess deferred taxes and higher pre-tax ~~net~~ income, partially offset by ~~higher tax credits.~~a net operating loss carryback benefit that the Company recognized during the first quarter of 2021.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.

Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At ~~September 30, 2020,~~March 31, 2021, APS’s common equity ratio, as defined, was 51%. Its total shareholder equity was approximately $6.3 billion, and total capitalization was approximately ~~$12.3~~$12.2 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.9 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.

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Summary of Cash Flows

Our consolidated change in cash and cash equivalents for the period ended March 31, 2021 compared to December 31, 2020 was a decrease of $43 million. The change is primarily driven by an increase in cash used for capital expenditures, which is partially offset by cash retained as a result of lower operations and maintenance cost, higher receipts of electric revenues and lower long-term debt repayments. The following tables present net cash provided by (used for) operating, investing and financing activities (dollars in millions):

Pinnacle West Consolidated


		Nine Months Ended September 30,				Net			Three Months Ended March 31,				Net
		2020		2019		Change			2021		2020		Change
Net cash flow provided by operating activities	Net cash flow provided by operating activities	$	773	$	835	$	(62)	Net cash flow provided by operating activities	$	202	$	184	$	18
Net cash flow used for investing activities	Net cash flow used for investing activities	(956)		(832)		(124)		Net cash flow used for investing activities	(348)		(341)		(7)
Net cash flow provided by financing activities	Net cash flow provided by financing activities	355		21		334		Net cash flow provided by financing activities	103		210		(107)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	$	172	$	24	$	148	Net change in cash and cash equivalents	$	(43)	$	53	$	(96)

Arizona Public Service Company


		Nine Months Ended September 30,				Net			Three Months Ended March 31,				Net
		2020		2019		Change			2021		2020		Change
Net cash flow provided by operating activities	Net cash flow provided by operating activities	$	771	$	830	$	(59)	Net cash flow provided by operating activities	$	203	$	194	$	9
Net cash flow used for investing activities	Net cash flow used for investing activities	(961)		(844)		(117)		Net cash flow used for investing activities	(352)		(343)		(9)
Net cash flow provided by financing activities	Net cash flow provided by financing activities	362		38		324		Net cash flow provided by financing activities	106		192		(86)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	$	172	$	24	$	148	Net change in cash and cash equivalents	$	(43)	$	43	$	(86)

Operating Cash Flows

~~Nine-month~~Three-month period ended ~~September 30, 2020~~March 31, 2021 compared with ~~nine-month~~three-month period ended ~~September 30, 2019.~~March 31, 2020. Pinnacle West’s consolidated net cash provided by operating activities was ~~$773~~$202 million in 2021, compared to $184 million in 2020, ~~compared to $835 million in 2019, a decrease~~an increase of ~~$62~~$18 million in net cash provided by operating activities primarily due to ~~higher fuel~~$41 million lower payments for operations and ~~purchased power costs, lower~~maintenance cost, $32 million higher cash receipts from electric revenues, partially offset by ~~lower operations~~$52 million higher fuel and ~~maintenance cost, lower pension contributions, income tax payments~~purchased power costs and ~~interest expense. The difference between APS and Pinnacle West's net cash provided by operating activities primarily relates to APS's lower income tax payments.~~other changes in working capital.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 ~~("ERISA"~~(“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was ~~117%~~124% funded as of January 1, ~~2020~~2021 and ~~112%~~117% as of January 1, ~~2019.~~2020. Under GAAP, the qualified pension plan was 104% funded as of January 1, 2021 and 97% funded as of January 1, ~~2020 and 90% funded as of January 1, 2019.~~2020. See Note 5 for additional details. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We have not made voluntary contributions ~~of $100 million~~ to our pension plan ~~year-to-date~~ in ~~2020.~~2021. The minimum required contributions for the pension plan are zero for the ~~2020-2022 period.~~next three years. We expect to make voluntary contributions up to $100 million ~~per year during this period.~~in 2021 and zero in 2022 and 2023. We

do not expect to make any contributions over this ~~period~~period to our other postretirement benefit plans. We continue to monitor COVID-19 and its impact on our retirement plans and other postretirement benefits but

we believe, due to our liability driven investment strategy, which helps to minimize the impact of market volatility on our plan’s funded status, our pension plan’s funded status, as measured for GAAP purposes, is still above 95% funded as of ~~September 30, 2020.~~March 31, 2021.

Investing Cash Flows

Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years:

Capital Expenditures

(dollars in millions)


		Estimated for the Year Ended December 31,							Estimated for the Year Ended December 31,
		2020		2021		2022			2021		2022		2023
APS	APS							APS
Generation:	Generation:							Generation:
Clean:	Clean:							Clean:
Nuclear Generation	Nuclear Generation	$	129	$	123	$	123	Nuclear Generation	$	114	$	116	$	125
Renewables and Energy Storage Systems ("ESS") (a)		12		490		671
Environmental		39		53		44
Renewables and Energy Storage Systems (“ESS”) (a)								Renewables and Energy Storage Systems (“ESS”) (a)	200		276		281

Other Generation(b)	Other Generation(b)	152		154		121		Other Generation(b)	203		190		187
Distribution	Distribution	588		444		446		Distribution	577		556		549
Transmission	Transmission	173		201		205		Transmission	185		181		179
Other ~~(b)~~(c)	Other ~~(b)~~(c)	170		185		115		Other ~~(b)~~(c)	221		181		179
Total APS	Total APS	$	1,263	$	1,650	$	1,725	Total APS	$	1,500	$	1,500	$	1,500

(a)APS Solar Communities program, energy storage, renewable projects, and other clean energy projects

(b)Includes generation environmental projects

(c)Primarily information systems and facilities projects

Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include improvements to existing fossil plants. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewable and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers and environmental equipment. We

are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Financing Cash Flows and Liquidity

~~Nine-month~~Three-month period ended ~~September 30, 2020~~March 31, 2021 compared with ~~nine-month~~three-month period ended ~~September 30, 2019.~~March 31, 2020. Pinnacle West’s consolidated net cash provided by financing activities was ~~$355~~$103 million in 2021, compared to $210 million in 2020, ~~compared to $21 million in 2019, an increase~~a decrease of ~~$334~~$107 million in net cash provided. The ~~increase~~decrease in net cash provided by financing activities includes ~~$689~~a net decrease in short-term borrowing of $403 million, partially offset by $150 million in higher issuances of long-term debt ~~partially offset by higher~~and lower long-term debt repayments of ~~$300 million, a net increase in short-term borrowing repayments of $38 million and a higher dividend payment of $16~~$150 million.

APS’s consolidated net cash provided by financing activities was ~~$362~~$106 million in 2021, compared to $192 million in 2020, ~~compared to $38 million in 2019, an increase~~a decrease of ~~$324~~$86 million in net cash provided. The ~~increase~~decrease in net cash provided by financing activities includes ~~$192~~a net decrease in short-term borrowing of $231 million, ~~in higher issuances of long-term debt and~~partially offset by lower long-term debt repayments of $150 ~~million, partially offset by higher dividend payment of $16~~ million.

Significant Financing Activities. On ~~October 22, 2020,~~April 21, 2021, the Pinnacle West Board of Directors declared a dividend of $0.83 per share of common stock, payable on ~~December~~June 1, ~~2020~~2021 to shareholders of record on ~~November 2, 2020. This represents an increase in the indicated annual dividend from $3.13 per share to $3.32 per share.~~May 3, 2021.

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

At ~~September 30, 2020,~~March 31, 2021, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. 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~~West’s senior unsecured debt credit ratings. The facility is available to support Pinnacle ~~West's~~West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At ~~September 30, 2020,~~March 31, 2021, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and ~~$34~~$0.3 million inof outstanding commercial paper borrowings.

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

On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility, and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050. The net proceeds from the sale will be used to pay or reimburse payment of existing or future eligible green expenditures, such as expenditures related to the following categories: (i) renewables and energy storage, (ii) energy efficiency, (iii) climate change adaptation and (iv) clean transportation, that include those funded during the period from 24 months prior to the issue date of the notes and those funded any time following the issue date of the notes until the maturity date of the notes. To the extent that the net proceeds from the sale of the notes are allocated to amounts previously invested in existing eligible green expenditures, such proceeds will replenish the amounts previously invested and be used for general corporate purposes. To the extent that the net proceeds are to be allocated to future eligible green expenditures, such proceeds will be deposited into APS's general corporate funds and, pending the incurrence of such costs, managed accordingly to APS's typical treasury liquidity practices.

At ~~September 30, 2020,~~March 31, 2021, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s ~~$500~~$750 million commercial paper program, for bank borrowings or for issuances of letters of credit. At ~~September 30, 2020,~~March 31, 2021, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding, and no$199.5 million of outstanding commercial paper borrowings.

As a result of the COVID-19 pandemic, in mid-March 2020 the commercial paper markets failed to function normally and we were unable to utilize commercial paper as our primary method of acquiring short-term capital, which resulted in us drawing on our revolving credit facilities during the first quarter of 2020. In mid-April 2020, we were again able to utilize the commercial paper market and we have paid down the revolving credit facilities completely. We do not believe this will have a material impact on our financial position, results of operations or cash flows.

See ~~"Financial Assurances"~~“Financial Assurances” in Note 8 for a discussion of separate outstanding letters of credit and surety bonds.

Other Financing Matters. See Note 7 for information related to the change in our margin and collateral accounts.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At ~~September 30, 2020,~~March 31, 2021, the ratio was approximately ~~53%~~54% for Pinnacle West and ~~48%~~49% 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"~~“cross-default” other debt. See further discussion of ~~"cross-default"~~“cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain ~~"rating triggers"~~“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"~~“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"~~“cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

On ~~November 27, 2018,~~December 17, 2020, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit from ~~$5.1~~$5.9 billion to ~~$5.9~~$7.5 billion, and authorized APS’s short-term debt ~~limit~~authorization equal to athe 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). On March 27, 2020, APS filed an application with the ACC to increase the long-term debt limit from $5.9 billion to $7.5 billion and to continue its authorization of short-term debt granted in the 2018 financing order. This application is pending ACC review and approval.

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Credit Ratings

The ratings of securities of Pinnacle West and APS as of ~~October 23, 2020~~April 28, 2021 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

Moody’s

Standard & Poor’s

Fitch

Pinnacle West

Corporate credit rating

A-

Senior unsecured

BBB+

A-

Commercial paper

P-2

A-2

Outlook

Negative

Stable

Negative

APS

Corporate credit rating

A-

Senior unsecured

A-

Commercial paper

P-1

A-2

Outlook

Negative

Stable

Negative

Off-Balance ~~Sheets~~Sheet Arrangements

See Note 6 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

Contractual Obligations

9386

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. There have been no changes to our critical accounting policies since our ~~2019~~2020 Form 10-K. See ~~"Critical~~“Critical Accounting ~~Policies"~~Policies” in Item 7 of the ~~2019~~2020 Form 10-K for further details about our critical accounting policies.

~~OTHER ACCOUNTING MATTERS~~

On January 1, 2020, we adopted ASU 2016-13, and related amendments, pertaining to the measurement of credit losses on financial instruments. See Note 13 for additional information related to new accounting standards.

MARKET AND CREDIT RISKS

Market Risks

Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our Nuclear Decommissioning Trusts, other special use funds and benefit plan assets.

Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our Nuclear Decommissioning Trusts, other special use funds (see Note 11 and Note 12), and benefit plan assets. The Nuclear Decommissioning Trusts, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and ~~fuels.~~natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

The following table shows the net pretax changes in mark-to-market of our derivative positions (dollars in millions):


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
Mark-to-market of net positions at beginning of period	Mark-to-market of net positions at beginning of period	$	(71)	$	(59)	Mark-to-market of net positions at beginning of period	$	(13)	$	(71)
Decrease (Increase) in regulatory asset	Decrease (Increase) in regulatory asset	76		(13)		Decrease (Increase) in regulatory asset	30		(14)
Recognized in OCI:	Recognized in OCI:					Recognized in OCI:
Mark-to-market losses realized during the period	Mark-to-market losses realized during the period	—		1		Mark-to-market losses realized during the period	—		—
Change in valuation techniques	Change in valuation techniques	—		—		Change in valuation techniques	—		—
Mark-to-market of net positions at end of period	Mark-to-market of net positions at end of period	$	5	$	(71)	Mark-to-market of net positions at end of period	$	17	$	(85)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at ~~September 30, 2020~~March 31, 2021 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, ~~"Derivative Accounting"~~“Derivative Accounting” and ~~"Fair~~“Fair Value ~~Measurements"~~Measurements” in Item 8 of our ~~2019~~2020 Form 10-K and Note 11 for more discussion of our valuation methods.


Source of Fair Value	Source of Fair Value	2020		2021		2022		2023		2024		Total Fair Value		Source of Fair Value	2021		2022		2023		2024		2025		Total Fair Value
Observable prices provided by other external sources	Observable prices provided by other external sources	$	(2)	$	16	$	(1)	$	(4)	$	—	$	9	Observable prices provided by other external sources	$	3	$	1	$	(1)	$	—	$	—	$	3
Prices based on unobservable inputs	Prices based on unobservable inputs	(2)		—		—		—		(2)		(4)		Prices based on unobservable inputs	14		—		—		—		—		14
Total by maturity	Total by maturity	$	(4)	$	16	$	(1)	$	(4)	$	(2)	$	5	Total by maturity	$	17	$	1	$	(1)	$	—	$	—	$	17

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets (dollars in millions):


		September 30, 2020				December 31, 2019					March 31, 2021				December 31, 2020
		Gain (Loss)				Gain (Loss)					Gain (Loss)				Gain (Loss)
		Price Up 10%		Price Down 10%		Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%		Price Up 10%		Price Down 10%
Mark-to-market changes reported in:	Mark-to-market changes reported in:									Mark-to-market changes reported in:
Regulatory asset (a)
Regulatory asset (liability) (a)										Regulatory asset (liability) (a)
Electricity	Electricity	$	—	$	—	$	—	$	—	Electricity	$	6	$	(6)	$	4	$	(4)
Natural gas	Natural gas	53		(53)		55		(55)		Natural gas	45		(45)		49		(49)
Total	Total	$	53	$	(53)	$	55	$	(55)	Total	$	51	$	(51)	$	53	$	(53)

(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 7 for a discussion of our credit valuation adjustment policy.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See ~~"Key~~“Key Financial ~~Drivers"~~Drivers” and ~~"Market~~“Market and Credit ~~Risks"~~Risks” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

The term ~~"disclosure~~“disclosure controls and ~~procedures"~~procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the ~~"Exchange Act"~~“Exchange Act”) (15 U.S.C. 78a et seq.), is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of ~~September 30, 2020.~~March 31, 2021. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of APS’s disclosure controls and procedures as of ~~September 30, 2020.~~March 31, 2021. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

The term ~~"internal~~“internal control over financial ~~reporting"~~reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended ~~September 30, 2020~~March 31, 2021 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

9689

PART II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See ~~"Business~~“Business of Arizona Public Service Company — Environmental ~~Matters"~~Matters” in Item 1 of the ~~2019~~2020 Form 10-K with regard to pending or threatened litigation and other ~~disputes.~~matters.

See Note 4 for ACC and FERC-related matters.

See Note 8 for information regarding environmental matters, Superfund-related matters and ~~Superfund-related matters.~~other disputes.

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A — Risk Factors in the ~~2019~~2020 Form 10-K, ~~and Part II, Item 1A of the 2020 1st and 2nd Quarter 10-Q,~~ which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS. The risks described in the ~~2019~~2020 Form 10-K ~~and the 2020 1st and 2nd Quarter 10-Q~~ are not the only risks facing Pinnacle West and APS. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.

~~The risk factor below is an update to our 2019 Form 10-K and 2020 1st and 2nd Quarter 10-Q.~~

~~The outbreak of the Coronavirus (“COVID-19”) pandemic could negatively affect our business.~~

The recent outbreak of COVID-19 is a rapidly developing situation around the globe that has led to economic disruption and volatility in the financial markets. The continued spread of COVID-19 and efforts to contain the virus could decrease demand for energy, lower economic growth, impact our employees and contractors, cause disruptions in our supply chain, increase certain costs, further increase volatility in the capital markets (and result in increases in the cost of capital or an inability to access the capital markets or draw on available credit facilities), delay the completion of capital or other construction projects and other operations and maintenance activities, delay payments or increase uncollectable accounts or cause other unpredictable events, each of which could adversely affect our business, results of operations, cash flows or financial condition.

As a result of the COVID-19 pandemic, from March through September 2020, we have experienced a decrease in demand from commercial and industrial customers and an increase in demand from residential customers which has resulted in a net decrease in weather normalized retail electricity sales as compared to 2019. APS is also experiencing an increase in bad debt expense associated with the COVID-19 pandemic that has resulted in a negative impact to our 2020 operating results. In mid-March 2020, we drew on our revolving credit facilities as a result of the commercial paper markets failing to function normally due to COVID-19, but we were subsequently able to utilize the commercial paper market in April 2020 and we have paid down the revolving credit facilities completely. We are also experiencing increased operations and maintenance expenses due to the need for personal protective equipment and other health and safety-related costs related to COVID-19.

Despite our efforts to manage the impacts, the degree to which the COVID-19 pandemic and related actions ultimately impact our business, financial position, results of operations and cash flows will depend on factors beyond our control including the duration, spread and severity of the outbreak, the actions taken to

contain COVID-19 and mitigate its public health effects, the impact on the U.S. and global economies and demand for energy, and how quickly and to what extent normal economic and operating conditions resume.

Item 5. OTHER INFORMATION

None.

9890

Item 6. EXHIBITS

(a) Exhibits

Exhibit No.

Registrant(s)

Description

10.1

Pinnacle West APS

Amendment No. 4, dated April 1, 2021, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to the First National Bank of Boston, as Lessor, and APS, as Lessee

31.1

Pinnacle West

Certificate of Jeffrey B. Guldner, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.2

Pinnacle West

Certificate of Theodore N. Geisler, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.3

APS

Certificate of Jeffrey B. Guldner, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.4

APS

Certificate of Theodore N. Geisler, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

32.1*

Pinnacle West

Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*

APS

Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS

Pinnacle West

APS

XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.

101.SCH

Pinnacle West

APS

XBRL Taxonomy Extension Schema Document

101.CAL

Pinnacle West

APS

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB

Pinnacle West

APS

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

Pinnacle West

APS

XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF

Pinnacle West

APS

XBRL Taxonomy Definition Linkbase Document

104

Pinnacle West

APS

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*Furnished herewith as an Exhibit.

9991

In addition, Pinnacle West and APS hereby incorporate the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:

Exhibit No.

Registrant(s)

Description

Previously Filed as Exhibit(1)

Date Filed

3.1

Pinnacle West

Pinnacle West Capital Corporation Bylaws, amended as of February 19, 2020

3.1 to Pinnacle West/APS February 25, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473

2/25/2020

3.2

Pinnacle West

Articles of Incorporation, restated as of May 21, 2008

3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/7/2008

3.3

APS

Articles of Incorporation, restated as of May 25, 1988

4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473

9/29/1993

3.4

APS

Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012

3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473

5/22/2012

3.5

APS

Arizona Public Service Company Bylaws, amended as of December 16, 2008

3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473

2/20/2009

(1) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

~~100~~92

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PINNACLE WEST CAPITAL CORPORATION

(Registrant)

Dated:

~~October 30, 2020~~May 5, 2021

By:

/s/ Theodore N. Geisler

Theodore N. Geisler

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer and

Officer Duly Authorized to sign this Report)

ARIZONA PUBLIC SERVICE COMPANY

(Registrant)

Dated:

~~October 30, 2020~~May 5, 2021

By:

/s/ Theodore N. Geisler

Theodore N. Geisler

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer and

Officer Duly Authorized to sign this Report)

~~101~~93


		Page

Forward-Looking Statements		2
Part I		4
Item 1.	Financial Statements	4
	Pinnacle West Capital Corporation	5
	Arizona Public Service Company	1211
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	7166
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	9688
Item 4.	Controls and Procedures	9689

Part II		9790
Item 1.	Legal Proceedings	9790
Item 1A.	Risk Factors	9790
Item 5.	Other Information	9890
Item 6.	Exhibits	9991
Signatures		~~101~~93


	Nine Months Ended September 30, 2020
	Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
	Shares	Amount		Shares	Amount
Balance, January 1, 2020	112,540,126	$	2,659,561	(103,546)	$	(9,427)	$	2,837,610	$	(57,096)	$	122,540	$	5,553,188
Net income		—			—		569,950		—		14,620		584,570
Other comprehensive loss		—			—		—		(395)		—		(395)
Dividends on common stock ($1.57 per share)		—			—		(176,079)		—		—		(176,079)
Issuance of common stock	83,497	10,797			—		—		—		—		10,797
Purchase of treasury stock (a)		—		(34,569)	(3,119)		—		—		—		(3,119)
Reissuance of treasury stock for stock-based compensation and other		—		104,398	9,580		0		—		—		9,580
Capital activities by noncontrolling interests		—			—		0		—		(11,372)		(11,372)
Other							4				1		5
Balance, September 30, 2020	112,623,623	$	2,670,358	(33,717)	$	(2,966)	$	3,231,485	$	(57,491)	$	125,789	$	5,967,175


	Nine Months Ended September 30, 2019
	Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
	Shares	Amount		Shares	Amount
Balance, January 1, 2019	112,159,896	$	2,634,265	(58,135)	$	(4,825)	$	2,641,183	$	(47,708)	$	125,790	$	5,348,705
Net income		—			—		474,339		—		14,620		488,959
Other comprehensive income		—			—		—		1,170		—		1,170
Dividends on common stock ($1.48 per share)		—			—		(165,631)		—		—		(165,631)
Issuance of common stock	243,855	20,165			—		—		—		—		20,165
Purchase of treasury stock (a)		—		(75,894)	(6,892)		—		—		—		(6,892)
Reissuance of treasury stock for stock-based compensation and other		—		76,082	6,600		0		—		—		6,600
Capital activities by noncontrolling interests		—			—		0		—		(11,372)		(11,372)
Other		—			—		—		—		1		1
Balance, September 30, 2019	112,403,751	$	2,654,430	(57,947)	$	(5,117)	$	2,949,891	$	(46,538)	$	129,039	$	5,681,705


	Three Months Ended September 30, 2020						Three Months Ended September 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total		Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	51,662	$	4,655	$	56,317	$	21,095	$	4,581	$	25,676
Variable lease cost	40,658		232		40,890		36,917		183		37,100
Short-term lease cost	0		1,038		1,038		0		812		812
Total lease cost	$	92,320	$	5,925	$	98,245	$	58,012	$	5,576	$	63,588


	Nine Months Ended September 30, 2020						Nine Months Ended September 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total		Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	68,883	$	13,959	$	82,842	$	35,159	$	13,343	$	48,502
Variable lease cost	102,052		730		102,782		95,736		543		96,279
Short-term lease cost	0		2,824		2,824		0		3,477		3,477
Total lease cost	$	170,935	$	17,513	$	188,448	$	130,895	$	17,363	$	148,258


	September 30, 2020
Year	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
2020 (remaining three months of 2020)	$	14,889	$	3,294	$	18,183
2021	66,658		13,402		80,060
2022	68,325		9,781		78,106
2023	70,033		7,443		77,476
2024	71,784		5,162		76,946
2025	73,578		3,457		77,035
Thereafter	36,759		36,961		73,720
Total lease commitments	402,026		79,500		481,526
Less imputed interest	15,565		18,407		33,972
Total lease liabilities	$	386,461	$	61,093	$	447,554


	Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows:	$	56,896	$	51,980
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	436,587		8,759


	September 30, 2020		December 31, 2019
Weighted average remaining lease term	7 years		13 years
Weighted average discount rate (a)	1.69	%	3.71	%