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 March 31, ~~2019~~2020



☐	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~~			~~86-0512431~~
	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~~			~~86-0011170~~
	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	~~Yes~~ ☒	No	☐☐
ARIZONA PUBLIC SERVICE COMPANY	Yes	~~Yes~~ ☒	No	☐☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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	~~Yes~~ ☒	No	☐☐
ARIZONA PUBLIC SERVICE COMPANY	Yes	~~Yes~~ ☒	No	☐☐

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 accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth 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	☒☐	~~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	☐	No	~~Yes~~ ☐☒ No ☒
ARIZONA PUBLIC SERVICE COMPANY	Yes	☐	No	~~Yes~~ ☐☒ No ☒

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 ~~April 24, 2019: 112,277,359~~May 1, 2020:	112,493,458
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of ~~April 24, 2019:~~ May 1, 2020:	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") and Arizona Public Service Company ("APS"). Any use of the words "Company," "we," and "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,"~~project"~~ "anticipate," "goal," "seek," "strategy," "likely," "should," "will," "could," and similar ~~words~~.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, ~~2018~~2019 ("~~2018~~2019 Form 10-K"), Part II, Item 1A of this report and in Part I, Item 2 — "Management’s Discussion and Analysis of Financial Condition and Results of 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, those described in Part II, Item 1A "Risk Factors" herein;

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), ~~and~~ the effects of energy conservation measures and distributed ~~generation;~~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 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, including returns on and of debt and equity capital investment;

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

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 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") orders.

These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our ~~2018~~2019 Form 10-K, in Part II, Item 1A of this report, and in Part I, Item 2 — "Management’s Discussion and Analysis of Financial Condition and Results of 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 Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	5
Pinnacle West Condensed Consolidated Statements of Comprehensive Income for Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	6
Pinnacle West Condensed Consolidated Balance Sheets as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019	7
Pinnacle West Condensed Consolidated Statements of Cash Flows for Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	9
Pinnacle West Condensed Consolidated Statements of Changes in Equity for Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	10

APS Condensed Consolidated Statements of Income for Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	11
APS Condensed Consolidated Statements of Comprehensive Income for Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	12
APS Condensed Consolidated Balance Sheets as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019	13
APS Condensed Consolidated Statements of Cash Flows for Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	15
APS Condensed Consolidated Statements of Changes in Equity for Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	16

Combined Notes to Condensed Consolidated Financial Statements	17
Note 1. Consolidation and Nature of Operations	17
Note 2. Revenue	18
Note 3. Long-Term Debt and Liquidity Matters	1920
Note 4. Regulatory Matters	2021
Note 5. Retirement Plans and Other Postretirement Benefits	3438
Note 6. Palo Verde Sale Leaseback Variable Interest Entities	3539
Note 7. Derivative Accounting	3640
Note 8. Commitments and Contingencies	4145
Note 9. Other Income and Other Expense	4952
Note 10. Earnings Per Share	5053
Note 11. Fair Value Measurements	5053
Note 12. Investment in Nuclear Decommissioning ~~Trusts~~Trust and Other Special Use Funds	5659
Note 13. New Accounting Standards	5961
Note 14. Changes in Accumulated Other Comprehensive Loss	6062
Note 15. Income Taxes	6163
Note 16. ~~Leases~~Asset Retirement Obligations	6364

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019

OPERATING REVENUES (NOTE 2)	$	740,530		$	692,714		$	661,930		$	740,530

OPERATING EXPENSES
Fuel and purchased power	230,588			197,110			188,521			230,588
Operations and maintenance	245,634			265,682			221,318			245,634
Depreciation and amortization	148,707			144,825			154,079			148,707
Taxes other than income taxes	55,090			53,600			56,768			55,090
Other expenses	427			163			822			427
Total	680,446			661,380			621,508			680,446
OPERATING INCOME	60,084			31,334			40,422			60,084
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	11,188			14,079			7,697			11,188
Pension and other postretirement non-service credits - net	5,114			12,859			13,911			5,114
Other income (Note 9)	7,169			3,985			12,569			7,169
Other expense (Note 9)	(4,358		)	(3,229		)	(4,784		)	(4,358		)
Total	19,113			27,694			29,393			19,113
INTEREST EXPENSE
Interest charges	60,653			58,954			59,234			60,653
Allowance for borrowed funds used during construction	(6,665		)	(6,755		)	(4,076		)	(6,665		)
Total	53,988			52,199			55,158			53,988
INCOME BEFORE INCOME TAXES	25,209			6,829			14,657			25,209
INCOME TAXES	2,418			(1,265		)	(20,209		)	2,418
NET INCOME	22,791			8,094			34,866			22,791
Less: Net income attributable to noncontrolling interests (Note 6)	4,873			4,873			4,873			4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	17,918		$	3,221		$	29,993		$	17,918

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	112,337			112,017			112,594			112,337
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,735			112,493			112,862			112,735

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	0.16		$	0.03		$	0.27		$	0.16
Net income attributable to common shareholders — diluted	$	0.16		$	0.03		$	0.27		$	0.16

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 March 31,					Three Months Ended March 31,
	2019		2018			2020		2019

NET INCOME	$	22,791	$	8,094		$	34,866	$	22,791

OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $0 and $96	—		(96		)
Reclassification of net realized loss, net of tax benefit of $108 and $82	328		409
Pension and other postretirement benefits activity, net of tax expense of $288 and $443	879		900
Net unrealized gain, net of tax expense of $292 and $0						292		—
Reclassification of net realized loss, net of tax benefit of $394 and $108						20		328
Pension and other postretirement benefits activity, net of tax expense of $245 and $288						1,205		879
Total other comprehensive income	1,207		1,213			1,517		1,207

COMPREHENSIVE INCOME	23,998		9,307			36,383		23,998
Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873			4,873		4,873

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	19,125	$	4,434		$	31,510	$	19,125

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

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)


	March 31, 2019			December 31, 2018			March 31, 2020			December 31, 2019
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	6,109		$	5,766		$	63,139		$	10,283
Customer and other receivables	249,568			267,887			258,874			266,426
Accrued unbilled revenues	114,077			137,170			93,434			128,165
Allowance for doubtful accounts	(2,455		)	(4,069		)	(8,366		)	(8,171		)
Materials and supplies (at average cost)	280,857			269,065			323,545			331,091
Fossil fuel (at average cost)	26,294			25,029			16,930			14,829
Income tax receivable							20,599			21,727
Assets from risk management activities (Note 7)	763			1,113			2,108			515
Deferred fuel and purchased power regulatory asset (Note 4)	7,583			37,164			77,730			70,137
Other regulatory assets (Note 4)	127,642			129,738			147,741			133,070
Other current assets	65,951			56,128			82,573			61,958
Total current assets	876,389			924,991			1,078,307			1,030,030
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	919,309			851,134			920,426			1,010,775
Other special use funds (Notes 11 and 12)	238,207			236,101			252,723			245,095
Other assets	99,446			103,247			97,822			96,953
Total investments and other assets	1,256,962			1,190,482			1,270,971			1,352,823
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	18,763,499			18,736,628			19,930,983			19,836,292
Accumulated depreciation and amortization	(6,398,512		)	(6,366,014		)	(6,784,467		)	(6,637,857		)
Net	12,364,987			12,370,614			13,146,516			13,198,435
Construction work in progress	1,233,018			1,170,062			942,258			808,133
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	104,808			105,775			100,938			101,906
Intangible assets, net of accumulated amortization	267,998			262,902			279,238			290,564
Nuclear fuel, net of accumulated amortization	142,610			120,217			168,457			123,500
Total property, plant and equipment	14,113,421			14,029,570			14,637,407			14,522,538
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,507			1,342,941			1,302,448			1,304,073
Operating lease right-of-use assets (Note 16)	193,897			—
Operating lease right-of-use assets							144,380			145,813
Assets for other postretirement benefits (Note 5)	52,674			46,906			96,243			90,570
Other	39,257			129,312			32,004			33,400
Total deferred debits	1,607,335			1,519,159			1,575,075			1,573,856

TOTAL ASSETS	$	17,854,107		$	17,664,202		$	18,561,760		$	18,479,247

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

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)


	March 31, 2019			December 31, 2018			March 31, 2020			December 31, 2019
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	263,656		$	277,336		$	301,325		$	346,448
Accrued taxes	199,949			154,819			194,732			144,899
Accrued interest	50,074			61,107			53,608			53,534
Common dividends payable	—			82,675			—			87,982
Short-term borrowings (Note 3)	244,050			76,400			563,000			114,675
Current maturities of long-term debt (Note 3)	250,000			500,000			650,000			800,000
Customer deposits	87,263			91,174			54,965			64,908
Liabilities from risk management activities (Note 7)	33,289			35,506			54,784			38,946
Liabilities for asset retirements	22,823			19,842			10,095			11,025
Operating lease liabilities (Note 16)	65,435			—
Operating lease liabilities							12,360			12,713
Regulatory liabilities (Note 4)	260,404			165,876			279,105			234,912
Other current liabilities	114,361			184,229			121,514			168,323
Total current liabilities	1,591,304			1,648,964			2,295,488			2,078,365
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)	4,886,108			4,638,232			4,833,324			4,832,558
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,811,689			1,807,421			2,016,770			1,992,339
Regulatory liabilities (Note 4)	2,272,082			2,325,976			2,067,801			2,267,835
Liabilities for asset retirements	712,885			706,703			649,226			646,193
Liabilities for pension benefits (Note 5)	384,492			443,170			273,284			280,185
Liabilities from risk management activities (Note 7)	14,844			24,531			32,577			33,186
Customer advances	155,894			137,153			212,545			215,330
Coal mine reclamation	214,037			212,785			166,796			165,695
Deferred investment tax credit	200,052			200,405			196,002			196,468
Unrecognized tax benefits	26,042			22,517			6,400			6,189
Operating lease liabilities (Note 16)	53,704			—
Operating lease liabilities							51,198			51,872
Other	149,249			147,640			163,517			159,844
Total deferred credits and other	5,994,970			6,028,301			5,836,116			6,015,136
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,340,322 and 112,159,896 issued at respective dates	2,644,063			2,634,265
Treasury stock at cost; 63,271 and 58,135 shares at respective dates	(5,586		)	(4,825		)
Common stock, no par value; authorized 150,000,000 shares, 112,563,610 and 112,540,126 issued at respective dates							2,664,387			2,659,561
Treasury stock at cost; 72,302 and 103,546 shares at respective dates							(7,000		)	(9,427		)
Total common stock	2,638,477			2,629,440			2,657,387			2,650,134
Retained earnings	2,659,086			2,641,183			2,867,610			2,837,610
Accumulated other comprehensive loss	(46,501		)	(47,708		)	(55,579		)	(57,096		)
Total shareholders’ equity	5,251,062			5,222,915			5,469,418			5,430,648
Noncontrolling interests (Note 6)	130,663			125,790			127,414			122,540
Total equity	5,381,725			5,348,705			5,596,832			5,553,188

TOTAL LIABILITIES AND EQUITY	$	17,854,107		$	17,664,202		$	18,561,760		$	18,479,247

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)


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	22,791		$	8,094		$	34,866		$	22,791
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	167,801			163,566			173,168			167,801
Deferred fuel and purchased power	16,709			(18,950		)	(5,785		)	16,709
Deferred fuel and purchased power amortization	12,872			20,002			(1,808		)	12,872
Allowance for equity funds used during construction	(11,188		)	(14,079		)	(7,697		)	(11,188		)
Deferred income taxes	3,620			(229		)	(18,086		)	3,620
Deferred investment tax credit	(353		)	(147		)	(465		)	(353		)
Stock compensation	12,074			10,537			6,282			12,074
Changes in current assets and liabilities:
Customer and other receivables	15,476			89,518			25,575			15,476
Accrued unbilled revenues	23,093			(6,555		)	34,731			23,093
Materials, supplies and fossil fuel	(13,057		)	(16,607		)	5,445			(13,057		)
Income tax receivable							1,128			—
Other current assets	(10,115		)	(664		)	(20,202		)	(10,115		)
Accounts payable	26,593			(25,738		)	(5,192		)	26,593
Accrued taxes	45,130			45,984			49,833			45,130
Other current liabilities	(86,250		)	(12,030		)	(63,096		)	(86,250		)
Change in other long-term assets	(65,470		)	(3,765		)	81,143			(65,470		)
Change in other long-term liabilities	13,706			(72,065		)	(106,212		)	13,706
Net cash flow provided by operating activities	173,432			166,872			183,628			173,432
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(259,792		)	(361,037		)	(340,014		)	(259,792		)
Contributions in aid of construction	7,938			8,569			3,152			7,938
Allowance for borrowed funds used during construction	(6,665		)	(6,755		)	(4,076		)	(6,665		)
Proceeds from nuclear decommissioning trust sales and other special use funds	179,048			130,456			195,087			179,048
Investment in nuclear decommissioning trust and other special use funds	(179,618		)	(131,027		)	(195,658		)	(179,618		)
Other	4,576			(1,299		)	349			4,576
Net cash flow used for investing activities	(254,513		)	(361,093		)	(341,160		)	(254,513		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324			—			—			497,324
Short-term borrowing and payments — net	172,650			263,500			(76,675		)	172,650
Short-term debt borrowings under revolving credit facility	—			36,000
Short-term debt repayments under revolving credit facility	(5,000		)	(25,000		)
Short-term debt borrowings							751,690			—
Short-term debt repayments							(226,690		)	(5,000		)
Dividends paid on common stock	(80,897		)	(75,903		)	(86,257		)	(80,897		)
Repayment of long-term debt	(500,000		)	—			(150,000		)	(500,000		)
Common stock equity issuance - net of purchases	(2,653		)	(2,828		)	(1,680		)	(2,653		)
Net cash flow provided by financing activities	81,424			195,769			210,388			81,424
NET INCREASE IN CASH AND CASH EQUIVALENTS	343			1,548			52,856			343
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,766			13,892			10,283			5,766
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	6,109		$	15,440		$	63,139		$	6,109

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 March 31, 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		—				—			29,993			—			4,873		34,866
Other comprehensive income		—				—			—			1,517			—		1,517
Dividends on common stock		—				—			8			—			—		8
Issuance of common stock	23,484	4,826							—			—			—		4,826
Purchase of treasury stock (a)		—		(20,724	)	(2,086		)	—			—			—		(2,086		)
Reissuance of treasury stock for stock-based compensation and other		—		51,968		4,513			—			—			—		4,513
Other		—		—		—			(1		)	—			1		—
Balance, March 31, 2020	112,563,610	$	2,664,387	(72,302	)	$	(7,000	)	$	2,867,610		$	(55,579	)	$	127,414	$	5,596,832


	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total			Three Months Ended March 31, 2019
	Shares	Amount		Shares		Amount														Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total
Balance, January 1, 2018	111,816,170	$	2,614,805	(64,463	)	$	(5,624	)	$	2,442,511		$	(45,002	)	$	129,040	$	5,135,730
Net income		—				—			3,221			—			4,873		8,094
Other comprehensive income		—				—			—			1,213			—		1,213
Dividends on common stock		—				—			(16		)	—			—		(16		)
Issuance of common stock	145,793	5,456				—			—			—			—		5,456
Purchase of treasury stock (a)		—		(81,177	)	(6,277		)	—			—			—		(6,277		)
Reissuance of treasury stock for stock-based compensation and other		—		116,543		9,470			—			—			1		9,471
Reclassification of income tax effects related to new tax reform (b)		—				—			8,552			(8,552		)	—		—
Balance, March 31, 2018	111,961,963	$	2,620,261	(29,097	)	$	(2,431	)	$	2,454,268		$	(52,341	)	$	133,914	$	5,153,671
																				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		112,159,896	$	2,634,265	(58,135	)	$	(4,825	)	$	2,641,183		$	(47,708	)	$	125,790	$	5,348,705
Net income		—				—			17,918			—			4,873		22,791				—				—			17,918			—			4,873		22,791
Other comprehensive income		—				—			—			1,207			—		1,207				—				—			—			1,207			—		1,207
Dividends on common stock		—				—			(15		)	—			—		(15		)		—				—			(15		)	—			—		(15		)
Issuance of common stock	180,426	9,798				—			—			—			—		9,798			180,426	9,798				—			—			—			—		9,798
Purchase of treasury stock (a)		—		(75,791	)	(6,882		)	—			—			—		(6,882		)		—		(75,791	)	(6,882		)	—			—			—		(6,882		)
Reissuance of treasury stock for stock-based compensation and other		—		70,655		6,121			—			—			—		6,121				—		70,655		6,121			—			—			—		6,121
Balance, March 31, 2019	112,340,322	$	2,644,063	(63,271	)	$	(5,586	)	$	2,659,086		$	(46,501	)	$	130,663	$	5,381,725		112,340,322	$	2,644,063	(63,271	)	$	(5,586	)	$	2,659,086		$	(46,501	)	$	130,663	$	5,381,725


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


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

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

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019

OPERATING REVENUES	$	740,530		$	692,006
OPERATING REVENUES (NOTE 2)							$	661,930		$	740,530

OPERATING EXPENSES
Fuel and purchased power	230,588			202,010			188,521			230,588
Operations and maintenance	240,375			254,601			218,265			240,375
Depreciation and amortization	148,685			144,112			154,058			148,685
Taxes other than income taxes	55,078			53,242			56,758			55,078
Other expenses	427			163			822			427
Total	675,153			654,128			618,424			675,153
OPERATING INCOME	65,377			37,878			43,506			65,377
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	11,188			14,079			7,697			11,188
Pension and other postretirement non-service credits - net	5,499			13,197			14,262			5,499
Other income (Note 9)	6,416			3,772			11,633			6,416
Other expense (Note 9)	(3,878		)	(2,945		)	(4,668		)	(3,878		)
Total	19,225			28,103			28,924			19,225
INTEREST EXPENSE
Interest charges	56,665			56,158			55,736			56,665
Allowance for borrowed funds used during construction	(6,665		)	(6,755		)	(4,076		)	(6,665		)
Total	50,000			49,403			51,660			50,000
INCOME BEFORE INCOME TAXES	34,602			16,578			20,770			34,602
INCOME TAXES	1,453			2,106			(19,448		)	1,453
NET INCOME	33,149			14,472			40,218			33,149
Less: Net income attributable to noncontrolling interests (Note 6)	4,873			4,873			4,873			4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	28,276		$	9,599		$	35,345		$	28,276

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

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)


	Three Months Ended March 31,					Three Months Ended March 31,
	2019		2018			2020		2019

NET INCOME	$	33,149	$	14,472		$	40,218	$	33,149

OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $0 and $96	—		(96		)
Reclassification of net realized loss, net of tax benefit of $108 and $82	328		409
Pension and other postretirement benefits activity, net of tax expense of $247 and $306	752		857
Net unrealized gain, net of tax expense of $292 and $0						292		—
Reclassification of net realized loss, net of tax benefit of $394 and $108						20		328
Pension and other postretirement benefits activity, net of tax expense of $237 and $247						1,013		752
Total other comprehensive income	1,080		1,170			1,325		1,080

COMPREHENSIVE INCOME	34,229		15,642			41,543		34,229
Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873			4,873		4,873

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	29,356	$	10,769		$	36,670	$	29,356

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, 2019			December 31, 2018			March 31, 2020			December 31, 2019
ASSETS

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	18,760,012		$	18,733,142		$	19,927,522		$	19,832,805
Accumulated depreciation and amortization	(6,395,265		)	(6,362,771		)	(6,781,228		)	(6,634,597		)
Net	12,364,747			12,370,371			13,146,294			13,198,208

Construction work in progress	1,233,018			1,170,062			942,258			808,133
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	104,808			105,775			100,938			101,906
Intangible assets, net of accumulated amortization	267,842			262,746			279,082			290,409
Nuclear fuel, net of accumulated amortization	142,610			120,217			168,457			123,500
Total property, plant and equipment	14,113,025			14,029,171			14,637,029			14,522,156

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	919,309			851,134			920,426			1,010,775
Other special use funds (Notes 11 and 12)	238,207			236,101			252,723			245,095
Other assets	42,090			40,817			44,681			43,781
Total investments and other assets	1,199,606			1,128,052			1,217,830			1,299,651

CURRENT ASSETS
Cash and cash equivalents	6,080			5,707			53,351			10,169
Customer and other receivables	238,270			257,654			258,457			255,479
Accrued unbilled revenues	114,077			137,170			93,434			128,165
Allowance for doubtful accounts	(2,455		)	(4,069		)	(8,366		)	(8,171		)
Materials and supplies (at average cost)	280,857			269,065			323,545			331,091
Fossil fuel (at average cost)	26,294			25,029			16,930			14,829
Income tax receivable							8,724			7,313
Assets from risk management activities (Note 7)	763			1,113			2,108			515
Deferred fuel and purchased power regulatory asset (Note 4)	7,583			37,164			77,730			70,137
Other regulatory assets (Note 4)	127,642			129,738			147,741			133,070
Other current assets	44,417			35,111			57,471			38,895
Total current assets	843,528			893,682			1,031,125			981,492

DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,507			1,342,941			1,302,448			1,304,073
Operating lease right-of-use assets (Note 16)	191,957			—
Operating lease right-of-use assets							142,647			144,024
Assets for other postretirement benefits (Note 5)	48,961			43,212			92,391			86,736
Other	38,299			128,265			31,282			32,591
Total deferred debits	1,600,724			1,514,418			1,568,768			1,567,424

TOTAL ASSETS	$	17,756,883		$	17,565,323		$	18,454,752		$	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)


	March 31, 2019			December 31, 2018			March 31, 2020			December 31, 2019
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162		$	178,162		$	178,162		$	178,162
Additional paid-in capital	2,721,696			2,721,696			2,721,696			2,721,696
Retained earnings	2,816,532			2,788,256			3,047,269			3,011,927
Accumulated other comprehensive loss	(26,027		)	(27,107		)	(34,197		)	(35,522		)
Total shareholder equity	5,690,363			5,661,007			5,912,930			5,876,263
Noncontrolling interests (Note 6)	130,663			125,790			127,414			122,540
Total equity	5,821,026			5,786,797			6,040,344			5,998,803
Long-term debt less current maturities (Note 3)	4,437,155			4,189,436			4,833,743			4,833,133
Total capitalization	10,258,181			9,976,233			10,874,087			10,831,936
CURRENT LIABILITIES
Short-term borrowings (Note 3)	157,500			—			430,000			—
Current maturities of long-term debt (Note 3)	250,000			500,000			200,000			350,000
Accounts payable	257,124			266,277			294,037			338,006
Accrued taxes	230,591			176,357			190,571			136,328
Accrued interest	47,585			60,228			51,042			52,619
Common dividends payable	—			82,700			—			88,000
Customer deposits	87,263			91,174			54,965			64,908
Liabilities from risk management activities (Note 7)	33,289			35,506			54,784			38,946
Liabilities for asset retirements	22,823			19,842			10,095			11,025
Operating lease liabilities (Note 16)	65,267			—
Operating lease liabilities							12,224			12,549
Regulatory liabilities (Note 4)	260,404			165,876			279,105			234,912
Other current liabilities	114,665			178,137			133,497			164,736
Total current liabilities	1,526,511			1,576,097			1,710,320			1,492,029
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,815,368			1,812,664			2,057,824			2,033,096
Regulatory liabilities (Note 4)	2,272,082			2,325,976			2,067,801			2,267,835
Liabilities for asset retirements	712,885			706,703			649,226			646,193
Liabilities for pension benefits (Note 5)	367,296			425,404			255,749			262,243
Liabilities from risk management activities (Note 7)	14,844			24,531			32,577			33,186
Customer advances	155,894			137,153			212,545			215,330
Coal mine reclamation	214,037			212,785			166,796			165,695
Deferred investment tax credit	200,052			200,405			196,002			196,468
Unrecognized tax benefits	42,084			41,861			40,399			40,188
Operating lease liabilities (Note 16)	51,805			—
Operating lease liabilities							49,442			50,092
Other	125,844			125,511			141,984			136,432
Total deferred credits and other	5,972,191			6,012,993			5,870,345			6,046,758
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
TOTAL LIABILITIES AND EQUITY	$	17,756,883		$	17,565,323		$	18,454,752		$	18,370,723

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

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	33,149		$	14,472		$	40,218		$	33,149
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	167,779			162,853			173,147			167,779
Deferred fuel and purchased power	16,709			(18,950		)	(5,785		)	16,709
Deferred fuel and purchased power amortization	12,872			20,002			(1,808		)	12,872
Allowance for equity funds used during construction	(11,188		)	(14,079		)	(7,697		)	(11,188		)
Deferred income taxes	(1,205		)	533			(17,782		)	(1,205		)
Deferred investment tax credit	(353		)	(147		)	(465		)	(353		)
Changes in current assets and liabilities:
Customer and other receivables	16,541			90,647			15,045			16,541
Accrued unbilled revenues	23,093			(6,555		)	34,731			23,093
Materials, supplies and fossil fuel	(13,057		)	(16,747		)	5,445			(13,057		)
Income tax receivable							(1,411		)	—
Other current assets	(9,598		)	(1,237		)	(18,164		)	(9,598		)
Accounts payable	30,774			(24,592		)	(4,038		)	30,774
Accrued taxes	54,234			54,106			54,243			54,234
Other current liabilities	(81,627		)	(15,771		)	(49,149		)	(81,627		)
Change in other long-term assets	(64,516		)	3,722			82,178			(64,516		)
Change in other long-term liabilities	14,525			(70,928		)	(105,117		)	14,525
Net cash flow provided by operating activities	188,132			177,329			193,591			188,132
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(259,446		)	(355,039		)	(340,014		)	(259,446		)
Contributions in aid of construction	7,938			8,569			3,152			7,938
Allowance for borrowed funds used during construction	(6,665		)	(6,755		)	(4,076		)	(6,665		)
Proceeds from nuclear decommissioning trust sales and other special use funds	179,048			130,456			195,087			179,048
Investment in nuclear decommissioning trust and other special use funds	(179,618		)	(131,027		)	(195,658		)	(179,618		)
Other	(1,140		)	(1,183		)	(900		)	(1,140		)
Net cash flow used for investing activities	(259,883		)	(354,979		)	(342,409		)	(259,883		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324			—			—			497,324
Short-term borrowings and payments — net	157,500			255,500			—			157,500
Short-term debt borrowings under revolving credit facility	—			25,000			540,000			—
Short-term debt repayments under revolving credit facility	—			(25,000		)	(110,000		)	—
Repayment of long-term debt	(500,000		)	—			(150,000		)	(500,000		)
Dividends paid on common stock	(82,700		)	(77,700		)	(88,000		)	(82,700		)
Net cash flow provided by financing activities	72,124			177,800			192,000			72,124
NET INCREASE IN CASH AND CASH EQUIVALENTS	373			150			43,182			373
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,707			13,851			10,169			5,707
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	6,080		$	14,001		$	53,351		$	6,080

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)

Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount
Balance, January 1, 2018 71,264,947
$ 178,162
$ 2,571,696
$ 2,533,954
$ (26,983 ) $ 129,040
$ 5,385,869
Net income —
—
9,599
—
4,873
14,472
Other comprehensive income —
—
—
1,170
—
1,170
Other —
—
—
—
1
1
Reclassification of income tax effects related to new tax reform (a) —
—
5,038
(5,038 ) —
—
Balance, March 31, 2018 71,264,947
$ 178,162
$ 2,571,696
$ 2,548,591
$ (30,851 ) $ 133,914
$ 5,401,512

Balance, January 1, 2019 71,264,947
$ 178,162
$ 2,721,696
$ 2,788,256
$ (27,107 ) $ 125,790
$ 5,786,797
Net income —
—
28,276
—
4,873
33,149
Other comprehensive income —
—
—
1,080
—
1,080
Balance, March 31, 2019 71,264,947
$ 178,162
$ 2,721,696
$ 2,816,532
$ (26,027 ) $ 130,663
$ 5,821,026



	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


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



	Three Months Ended March 31, 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		—		—		28,276		—			4,873		33,149
Other comprehensive income		—		—		—		1,080			—		1,080
Balance, March 31, 2019	71,264,947	$	178,162	$	2,721,696	$	2,816,532	$	(26,027	)	$	130,663	$	5,821,026

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

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"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El 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") sale leaseback variable interest entities ("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"). 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"), 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 ~~2018~~2019 Form 10-K.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2020			2019
Cash paid during the period for:
Income taxes, net of refunds	$	1	$	—	$	(3,002	)	$	1
Interest, net of amounts capitalized	63,764		56,026		53,723			63,764
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	95,879	$	86,991	$	100,868		$	95,879
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	2,293		—		2,311			2,293

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2020		2019
Cash paid during the period for:
Income taxes, net of refunds	$	—	$	—	$	—	$	—
Interest, net of amounts capitalized	61,387		54,873		52,034		61,387
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	95,879	$	86,944	$	100,868	$	95,879
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	2,293		—		2,311		2,293

2. Revenue

Sources of Revenue

~~We derive our revenues from contracts with customers primarily from sales~~The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):



	Three Months Ended March 31,
	2020		2019
Retail Electric Revenue
Residential	$	325,073	$	351,566
Non-Residential	303,351		332,668
Wholesale energy sales	14,668		36,452
Transmission services for others	15,927		15,249
Other sources	2,911		4,595
Total operating revenues	$	661,930	$	740,530

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Retail Electric Revenue. Pinnacle West's retail electric revenue is generated by wholly owned regulated subsidiary APS's sale of electricity to our regulated ~~retail customers. Our retail electric services and~~customers within the authorized service territory at tariff rates ~~are regulated~~approved by the ~~ACC.~~ ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC").

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~The following table provides detail of Pinnacle West's consolidated revenue disaggregated~~In the electricity business, some contracts to purchase energy are settled by ~~revenue sources (dollars~~netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in ~~thousands):~~

Three Months Ended March 31,
2019 2018
Retail residential electric service $ 351,566
$ 316,675
Retail non-residential electric service 332,668
343,189
Wholesale energy sales 36,452
12,089
Transmission services for others 15,249
14,845
Other sources 4,595
5,916
Total operating revenues $ 740,530
$ 692,714

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 ~~are~~ primarily ~~derived from~~consist of activities that are classified as revenues from contracts with customers. ~~This includes~~We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers ~~and~~also include wholesale and transmission activities. Our revenues from contracts with customers for the three months ended March 31, 2020 and 2019 ~~and 2018~~ were ~~$721~~$648 million and ~~$683~~$721 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 months ended March 31, ~~2019~~2020 and ~~2018,~~2019, our revenues that do not qualify as revenue from contracts with customers were ~~$20~~$14 million and ~~$10~~$20 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 March 31, ~~2019~~2020 or December 31, ~~2018.~~2019.

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. The allowance 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.

During March 2020, due to the Coronavirus ("COVID-19") pandemic, and to assist customers who may be experiencing economic difficulties, we suspended all service shut-offs due to nonpayment. We are expecting an

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

increase in the number of customers needing to utilize longer-term payment plans to avoid service disruption. These changes, among others including the Summer Disconnection Moratorium (defined in Note 4), impacted our write-off factor during the period. We continue to monitor COVID-19 and its impact on our allowance for doubtful accounts, which may impact our write-off factor for upcoming 2020 financial statements. See Note 4 for additional details.

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



	March 31, 2020			December 31, 2019
Allowance for doubtful accounts, balance at beginning of period	$	8,171		$	4,069
Bad debt expense	3,122			11,819
Actual write-offs	(2,927		)	(7,717		)
Allowance for doubtful accounts, balance at end of period	$	8,366		$	8,171


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

At March 31, ~~2019~~,2020, Pinnacle West had a ~~364-day $150~~$200 million revolving credit facility that matures June 27, 2019. Borrowings under the facility bear interest at LIBOR plus 0.70% per annum. At March 31, 2019, Pinnacle West had $49 million in outstanding borrowings under the facility.

~~At March 31, 2019, 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 senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, ~~2019,~~2020, Pinnacle West had $100 million outstanding borrowings under its credit facility, 0 letters of credit outstanding and 0 commercial paper borrowings.

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 on May 4, 2021. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR") plus 1.40% per annum. At March 31, 2020, Pinnacle West had $33 million in outstanding borrowings under the prior agreement.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $38 million of commercial paper borrowings.~~

APS

On ~~February 26, 2019, APS~~ entered into a $200 million term loan agreement that matures August 26, 2020. APS used the proceeds to repay existing indebtedness. Borrowings under the agreement bear interest at LIBOR plus 0.50% per annum.

On ~~February~~ 28, 2019, APS issued $300 million of 4.25% unsecured senior notes that mature on March 1, 2049. The net proceeds from the sale, together with funds made available from the term loan described above, were used to repay existing indebtedness.

~~On March 1, 2019,~~January 15, 2020, APS repaid at maturity ~~$500~~the remaining $150 million of the $250 million aggregate principal amount of its ~~8.75% senior notes.~~2.2% Senior Notes.

At March 31, ~~2019,~~2020, APS had ~~two~~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 million commercial paper program, for bank borrowings or for issuances of letters of credit. At March 31, ~~2019,~~2020, APS had ~~$158~~$430 million ~~of commercial paper outstanding and no~~ outstanding borrowings ~~or letters of credit~~ under its revolving credit ~~facilities.~~facilities and 0 letters of credit outstanding or commercial paper borrowings.

On November 27, 2018, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $5.9 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.

See "Financial Assurances" in Note 8 for a discussion of ~~APS’s~~ 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 March 31, 2019				As of December 31, 2018				As of March 31, 2020				As of December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	448,953	$	446,835	$	448,796	$	443,955	$	449,581	$	448,449	$	449,425	$	450,822
APS	4,687,155		4,942,057		4,689,436		4,789,608		5,033,743		5,634,265		5,183,133		5,743,570
Total	$	5,136,108	$	5,388,892	$	5,138,232	$	5,233,563	$	5,483,324	$	6,082,714	$	5,632,558	$	6,194,392

4.Regulatory Matters

COVID-19 Pandemic

Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. In addition, APS has waived all late payment fees during this current moratorium. 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 and the increased bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 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.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS is anticipating 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 to $30 million range. These estimated impact amounts depend on certain assumptions, including customer behaviors and the impacts of COVID-19 on the economy not extending into 2021. APS also established a customer support fund of $1.5 million to assist customers with a one-time credit of up to $100 on their bill with a priority given to customers on limited-income service plans. Additionally, due to COVID-19, APS delayed the reset of the Environmental Improvement Surcharge ("EIS") adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 (see below for discussion of EIS and TEAM Phase II).

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 has been collected through the Demand Side Management ("DSM") Adjustor Clause, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020 (see below for discussion of the DSM Adjustor Clause). Also, on May 5, 2020, APS also voluntarily committed to the ACC to contribute $5.3 million of non-ratepayer funds to provide assistance to residential and business customers that have been impacted by the COVID-19 pandemic.

2019 Retail Rate Case Filing with the Arizona Corporation Commission

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ("SCR") project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the Tax Expense Adjustment Mechanism ("TEAM"). The proposed total revenue increase in APS's application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS's application are:

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;

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

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


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


▪	~~Regulatory Matters~~additional $1.25 million in funding for APS's limited-income crisis bill program; and

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


▪	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") (see "Navajo Plant" below).

APS requested that the increase become effective December 1, 2020. The hearing for this rate case was delayed by 75 days, at the request of ACC Staff, and is currently scheduled to begin September 30, 2020. APS cannot predict the outcome of its request.

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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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 agreement by APS not to file another general retail rate case application before June 1, 2019;

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 ~~selective catalytic reduction ("SCR")~~SCR equipment at the Four Corners Power Plant ("Four Corners");

a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;

an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party ~~battery~~energy storage costs;

•

~~a new AZ Sun II program~~ ~~(now known as "APS Solar 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"), to be no less than $10 million per year, and not more than $15 million per year;

a new AZ Sun II program (now known as "APS Solar 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"), 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:

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


▪	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;


▪	non-grandfathered distributed generation ("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 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated, and APS requested and was granted intervention. Mr. Woodward filed his opening brief on March 28, 2018. The ACC and APS filed responsive briefs on June 21, 2018. The Arizona Court of Appeals issued a Memorandum Decision on December 11, 2018 affirming the ACC decisions challenged by Mr. Woodward. Mr. Woodward filed a petition for review with the Arizona Supreme Court on January 9, 2019. Review by the Arizona Supreme Court is discretionary. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact on our financial position, results of operations or cash flows.

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”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation.. The Complaint ~~alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an~~was later amended ~~Complaint~~ alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. The ACC held a hearing on this matter ~~beginning in September 2018~~ and the hearing was concluded on October 1, ~~2018. Post-hearing briefing was concluded on December 14,~~ 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On ~~April 22,~~July 3, 2019, the Administrative Law Judge issued ~~a proposed~~an amendment to the Recommended Opinion and Order ~~which proposes~~ that ~~APS credit back to customers~~incorporated the ~~$5 million Demand Side Management Adjustor Charge ("DSMAC") funds used by APS to educate ratepayers on~~requirements of the ~~new rates~~rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC adopted the Administrative Law Judge's amended Recommended Opinion and ~~that APS ratepayers will be held harmless from expenditures made by APS for targeted outreach~~Order along with several ACC Commissioner amendments and ~~education in any future~~an amendment incorporating the results of the rate ~~case. APS cannot predict~~review and resolved the ~~outcome of this matter.~~Complaint.

On ~~January 9,~~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 ~~voted to open a docket for this matter. On April 23, 2019,~~approved the proposed ACC Staff ~~indicated that they may need some additional time beyond May 3,~~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, ~~to file~~using a June 30, 2019 test-year;

until the ~~requested report. APS does not believe that~~conclusion of the rate ~~review will have~~case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a ~~material impact~~customer would pay on ~~our current financial position, results~~their most economical rate given their actual usage during each month;

APS customers can switch rate plans during an open enrollment period of ~~operations or cash flows. However, depending~~six months;

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~upon~~APS must identify customers whose bills have increased by more than 9% and that are not on the ~~results~~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 ~~the~~changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate ~~review, the ACC may take further actions, including potentially reopening the 2017 Rate Case Decision.~~ plans and to reduce energy usage.

APS cannot predict the outcome or impact of ~~this matter.~~the rate case filed on October 31, 2019. 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.

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 ~~utility~~ compliance with the RES.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million. APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

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, ~~buildings of~~ non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. ~~On June 12, 2018, the ACC approved the 2018 RES Implementation Plan including a waiver of the distributed energy requirements for the 2018 implementation year.~~

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. The ACC has not yet ruled on the ~~2019~~2020 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. On January 30, 2018, ACC Commissioner Tobin proposed a plan in this proceeding which would broaden the RES to include a series of energy policies tied to clean energy sources (the "Energy Modernization Plan"). ~~The Energy Modernization Plan would~~ replace the current RES standard with a new standard called the Clean Resource Energy Standard and Tariff ("CREST"), which incorporates the proposals in the Energy Modernization Plan. A set of draft CREST rules for the ACC’s consideration was issued by Commissioner Tobin’s office on July 5, 2018. See "Energy Modernization Plan" below for more information.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On July 2, 2019, ACC Staff issued draft rules, which propose a RES goal of 45% of retail energy served be renewables by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035. The draft rules would also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. On February 18, 2020, ACC Staff issued revised draft rules which would change the RES and clean energy goals to standards and would provide additional reporting and compliance requirements. Certain ACC Commissioners have proposed different options with different implementation dates of these rules. APS cannot predict the outcome of this matter. See "Energy Modernization Plan" below for more information.

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

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes 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 seeks a requested budget of $52.6 million and requests 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. The ACC has not yet ruled on the APS 2018 amended DSM Plan.

On December 31, 2018, APS filed its 2019 DSM Plan, which requests a budget of $34.1 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan.

On December 31, 2019, APS filed its 2020 DSM Plan, which requests a budget of $51.9 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addresses all components of the 2018 and 2019 DSM plans, which enables the ACC to review the 2020 DSM Plan only. The ACC has not yet ruled on the APS 2020 DSM Plan.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 ~~(liability)~~ for ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020		2019
Beginning balance	$	37,164		$	75,637		$	70,137	$	37,164
Deferred fuel and purchased power costs — current period	(16,709		)	18,950			5,785		(16,709		)
Amounts charged to customers	(12,872		)	(20,002		)	1,808		(12,872		)
Ending balance	$	7,583		$	74,585		$	77,730	$	7,583

The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017 the PSA rate was revised to $0.000555 per kWh ~~as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh.~~

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 ~~until~~into the following year and were reflected in the 2019 reset of the PSA.

~~On November 30, 2018, APS filed its~~The PSA rate for the PSA year beginning February 1, ~~2019. That rate~~2019 was ~~$0.001658~~$0.001658 per kWh ~~and consisted~~, consisting of a ~~forward component~~Forward Component of ~~$0.000536~~$0.000536 per kWh and a ~~historical~~

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~~component~~Historical Component of $0.001122 per kWh. ~~The 2019 PSA rate is~~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 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 the ACC. APS cannot predict the outcome of this matter.

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 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 1st 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 - 14 million per year). APS’s February 1, 2020 application requested an increase in the charge to $8.75 million, or $2.0 million over the charge in effect for the 2019-2020 rate effective year. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the reset of the EIS adjustor to the first billing cycle in May 2020 rather than April 2020.

Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters. In July 2008, FERC approved ana modification to APS’s Open Access Transmission Tariff ~~for~~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

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transmission services to serve APS's retail customers ("Retail Transmission Charges"). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the settlement agreement entered into in 2012 regarding APS's rate case ~~(the "2012~~("2012 Settlement Agreement"), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2017.

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") 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. An adjustment to 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 $4.9 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. 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

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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.

APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million. On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its 2018 annual LFCR ~~Adjustment,~~adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 ~~million (a $3 million per year decrease from 2017 levels).~~million. On February 6, 2019, the ACC approved the 2018 annual LFCR

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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). ~~The~~On July 10, 2019, the ACC ~~has not yet ruled on~~approved APS’s 2019 LFCR adjustment ~~request. Because~~as filed, effective with the next billing cycle of July 2019. On February 14, 2020, APS filed its 2020 annual LFCR ~~mechanism has a balancing account~~adjustment, requesting that ~~trues up any under or over recoveries,~~effective May 1, 2020, the ~~delay~~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 ~~implementation does not have an adverse effect on APS.~~May 2020.

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

On 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 ~~reduces~~reduced rates by $119.1 million annually through an equal cents per kWh credit ("TEAM Phase I"). On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018.

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

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("TEAM Phase II"). The ACC approved this request on March 13, 2019, effective the first billing cycle in April ~~2019. The impact~~2019 through the last billing cycle in March 2020. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II ~~is expected~~until the first billing cycle in May 2020. Amounts credited to customers after the last billing cycle in March 2020 will be ~~earnings neutral~~recorded as ~~both~~a part of the balancing account and will be addressed for recovery as part of 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 ~~addresses~~addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period consistent with IRS normalization rules (“TEAM Phase III”). ~~Over~~On October 29, 2019, the ~~first 36 months,~~ACC approved TEAM Phase III ~~is expected~~providing both (i) a one-time bill credit of $64 million which was credited to ~~return $34.5~~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 ~~annually, and APS has proposed this refund begin July 1, 2019. The Company~~through December 31, 2020. It is currently ~~in the process of seeking IRS guidance affirming~~anticipated that benefits related to the amortization ~~method and period applicable to these~~of depreciation related excess deferred ~~taxes. The ACC has not yet approved TEAM Phase III.~~taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case.

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Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

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

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

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh iswas 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 ~~tariff~~rate rider became effective on October 1, ~~2018.~~2019.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona

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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

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appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

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

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner 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 obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that 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' 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 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.

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

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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 ~~subsequent~~and responded to various follow-on requests from ACC Commissioners on these ~~matters and continues to respond to such follow-on requests.~~matters. Pinnacle West and APS cannot predict the outcome of these matters.

~~Renewable Energy Ballot Initiative~~ The Company's CEO, Mr. Guldner, appeared at the ACC's January 14, 2020 Open Meeting regarding ACC 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.

On February 20, 2018, a renewable energy advocacy organization filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to provide at least 50% of their annual retail sales of electricity from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The initiative was placed on the November 2018 Arizona elections ballot. On November 6, 2018, the initiative failed to receive adequate voter support and was defeated.

Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which ~~consists~~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 ~~plans~~plan ("IRP") process. The Energy Modernization Plan includes replacing the current RES standard with a new standard called the CREST, which incorporates the proposals in the Energy Modernization Plan. On July 5, 2018, ACC Commissioner Tobin’s office issued a set of draft CREST rules for the ACC’s consideration, which proposes an electricity generating portfolio of at least 80% clean energy sources (including nuclear generation) by 2050, a target of 3,000 megawatts of deployed energy storage by 2030, and a plan to implement a new Energy Efficiency Standard when the current standard sunsets in 2020.

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 ~~Renewable Energy Standard,~~RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On ~~April 26,~~July 2, 2019, ~~Commissioner Dunn~~the ACC Staff issued a revised set of draft rules, which propose a RES goal of 45% of retail energy served be renewable by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035. The draft rules also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. The ACC held various stakeholder meetings and workshops on ACC Staff’s draft energy rules in July through September 2019. On February 18, 2020, the ACC Staff issued a revised proposed set of draft rules ~~with regards~~which would change the RES and clean energy goals to ~~the Energy Modernization Plan. APS cannot predict the outcome of this matter.~~

standards and would provide additional reporting and compliance requirements. In addition, ACC Staff proposed

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changing the IRP planning horizon from 15 years to 10 years. Certain ACC Commissioners have proposed different options with different implementation dates of these rules. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop ~~fifteen-year~~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 iswas originally required to file ~~a Preliminary Resource Plan by April 1, 2019 and~~ its ~~final~~next IRP by April 1, 2020. On February ~~25, 2019, APS filed a request to extend~~20, 2020, the ACC extended the deadline for all utilities to file ~~its Preliminary Integrated Resource Plan~~their IRP’s from April 1, 2020 to June 26, 2020. See "Energy Modernization Rules" above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act

In August 2016, APS filed an application requesting that all of its contracts with 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 a right to sell to the host utility. Host utilities are required to purchase power from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 ~~to August 1, 2019.~~and briefing on this matter was completed in October 2019 regarding APS’s application. On ~~April 24,~~December 17, 2019, the ACC ~~approved this request.~~denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW and the rate paid to the qualifying facilities will be based on the long-term avoided cost. APS is in discussions with qualifying facility developers but has not entered into any new qualifying facility agreements that would be subject to the new requirements of the ACC's decision.

~~Four Corners~~Residential Electric Utility Customer Service Disconnections

~~SCE-Related Matters.~~ On ~~December 30, 2013,~~June 13, 2019, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general retail rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013.voluntarily suspended electric disconnections for residential customers who had not paid their bills. On ~~December 23, 2014,~~June 20, 2019, the ACC ~~approved rate adjustments resulting in a revenue increase of $57.1 million~~voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15 ("Summer Disconnection Moratorium"). During the Summer Disconnection Moratorium, APS could not charge late fees and interest on ~~an annual basis. This included the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting~~amounts that were past due from ~~the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement~~customers. Customer deposits must also ~~provided for deferral for future recovery of all unrecovered costs incurred in connection~~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 ~~closure of Units 1-3.~~emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. The ~~deferral balance related to the acquisition of SCE’s interest in Units 4~~emergency rule changes will be effective for 180 days and 5 and the closure of Units 1-3 was $46 million as of March 31, 2019 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.may be renewed for one additional 180-day period.

~~As part~~In addition, in June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of ~~APS’s acquisition~~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 ~~SCE’s interest in Units 4~~June 2019 and ~~5, APS and SCE agreed, via~~credit any fees that were charged for a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERCreconnection. The ACC Staff issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016. On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relatingdraft amendments to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relatingcustomer service disconnections rules. Stakeholders submitted initial comments to the ~~settlement was a jurisdictional contract~~draft amendments on September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and ~~should have been filed with FERC. APS cannot predict whether or if~~January 2020 regarding the ~~enforcement division will take any action. APS filed an~~customer service disconnections rules.

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~~appeal~~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.

Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of ~~FERC's~~customers for nonpayment beginning March 13, 2020. APS currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 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 customer behaviors, the impacts of COVID-19 on the economy not extending into 2021 and the results of final rulemaking related to the Summer Disconnection Moratorium. See "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 ~~2016~~ and ~~October 5, 2017 orders~~July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC held a workshop on February 25-26, 2020 for further consideration and discussion of 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

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 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. APS is providing 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 is not expected to have a material impact on APS's financial statements. APS developed a new tool for comparing customers’ rate plan options. APS had an independent third party verify that the new rate comparison tool works correctly. In February 2020, APS launched the new online rate comparison tool, which is now available for its customers. The ACC is currently investigating this matter and has hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. APS received a civil investigative demand from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks information pertaining to the rate plan comparison tool offered to APS customers. APS is fully cooperating with the ~~United States Court of Appeals for the Ninth Circuit on December 4, 2017. Oral argument for~~Attorney General’s Office in this ~~proceeding is scheduled for May 15, 2019.~~matter. APS cannot predict the outcome of ~~the proceeding.~~these matters.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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 recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018. The ACC has not issued a decision on this matter. APS ~~anticipates a decision later~~included the costs for the SCR project in the retail rate base in its 2019 ~~however we~~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.~~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") 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") ~~approves~~approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the ~~Unit.~~unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it plans to retire Cholla Unit 4 by the end of 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 ($8569 million as of March 31, ~~2019)~~2020), 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 ~~2026.~~2025.

On March 20, 2019, APS announced that it ~~has begun~~began evaluating the feasibility and cost of converting a unit at ~~the~~ 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 ~~will report~~reported the ~~result~~results of its evaluation byon May ~~20, 2019. If converting~~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 ~~is more cost effective than alternatives, APS will seek ACC approval before moving forward with the~~at Cholla ~~conversion project. APS cannot predict the outcome of this matter.~~to burn biomass.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Navajo Plant

The co-owners of the Navajo ~~Generating Station (the "Navajo Plant")~~Plant and the Navajo Nation agreed that the Navajo Plant ~~will~~would remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that ~~will allow~~allows for decommissioning activities to begin after the plant ~~ceases~~ceased operations in ~~December~~November 2019.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities

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


	Amortization Through	March 31, 2019				December 31, 2018				Amortization Through	March 31, 2020				December 31, 2019
	Amortization Through	Current		Non-Current		Current		Non-Current		Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	723,307	$	—	$	733,351	(a)	$	—	$	652,691	$	—	$	660,223
Retired power plant costs	2033	28,182		160,167		28,182		167,164		2033	28,182		135,349		28,182		142,503
Income taxes — allowance for funds used during construction ("AFUDC") equity	2049	6,457		151,541		6,457		151,467		2050	6,815		155,369		6,800		154,974
Deferred fuel and purchased power — mark-to-market (Note 7)	2023	29,340		14,360		31,728		23,768		2024	51,954		32,576		36,887		33,185
Deferred fuel and purchased power (b) (c)	2020	7,583		—		37,164		—		2021	77,730		—		70,137		—
Deferred property taxes										2027	8,569		56,053		8,569		58,196
SCR deferral										N/A	—		58,258		—		52,644
Ocotillo deferral										N/A	—		51,767		—		38,144
Four Corners cost deferral	2024	8,077		38,209		8,077		40,228		2024	8,077		30,133		8,077		32,152
Deferred compensation										2036	—		37,550		—		36,464
Lost fixed cost recovery (b)										2021	28,885		—		26,067		—
Income taxes — investment tax credit basis adjustment	2047	1,079		25,475		1,079		25,522		2048	1,098		24,920		1,098		24,981
Lost fixed cost recovery (b)	2020	29,698		—		32,435		—
Palo Verde VIEs (Note 6)	2046	—		20,170		—		20,015		2046	—		20,790		—		20,635
Deferred compensation	2036	—		37,581		—		36,523
Deferred property taxes	2027	8,569		64,214		8,569		66,356
Coal reclamation										2026	1,068		17,800		1,546		17,688
Loss on reacquired debt	2038	1,637		13,259		1,637		13,668		2038	1,637		11,636		1,637		12,031
Mead-Phoenix transmission line contributions in aid of construction ("CIAC")										2050	332		9,629		332		9,712
TCA balancing account (b)										2021	6,048		1,027		6,324		2,885
Tax expense of Medicare subsidy	2024	1,235		6,122		1,235		6,176		2024	1,238		4,881		1,235		4,940
TCA balancing account (b)	2020	306		—		3,860		772
AG-1 deferral	2022	2,654		5,155		2,654		5,819		2022	2,787		2,019		2,787		2,716
Mead-Phoenix transmission line CIAC	2050	332		9,961		332		10,044
Coal reclamation	2026	1,546		17,392		1,546		15,607
SCR deferral	N/A	—		30,581		—		23,276
Tax expense adjuster mechanism (c)	2019	5,451		—		—		—
Tax expense adjuster mechanism (b)										2020	942		—		1,612		—
Other	Various	3,079		4,013		1,947		3,185		Various	109		—		1,917		—
Total regulatory assets (d)		$	135,225	$	1,321,507	$	166,902	$	1,342,941		$	225,471	$	1,302,448	$	203,207	$	1,304,073


(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") and result in lower future revenues.


(b)	See "Cost Recovery Mechanisms" discussion above.


(c)	Subject to a carrying charge.


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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


	Amortization Through	March 31, 2019				December 31, 2018				Amortization Through	March 31, 2020				December 31, 2019
	Amortization Through	Current		Non-Current		Current		Non-Current		Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act(a)	(a)	$	91,401	$	1,178,216	$	—	$	1,272,709	2046	$	113,142	$	976,018	$	59,918	$	1,054,053
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act(a)	2058	6,302		243,418		6,302		243,691		2058	6,315		237,508		6,302		237,357
Asset retirement obligations	2057	—		337,844		—		278,585		2057	—		311,517		—		418,423
Removal costs	(b)	50,701		156,578		39,866		177,533		(c)	44,586		135,450		47,356		136,072
Other postretirement benefits	(c)	37,864		116,478		37,864		125,903		(d)	37,575		130,270		37,575		139,634
Spent nuclear fuel										2027	6,638		49,234		6,676		51,019
Income taxes — change in rates										2050	2,802		51,152		2,797		68,265
Four Corners coal reclamation										2038	5,461		48,405		1,059		51,704
Income taxes — deferred investment tax credit	2047	2,164		51,027		2,164		51,120		2048	2,202		49,910		2,202		50,034
Income taxes — change in rates	2048	2,764		69,954		2,769		70,069
Spent nuclear fuel	2027	7,190		54,866		6,503		57,002
Renewable energy standard (a)	2020	47,943		—		44,966		20
Demand side management (a)	2020	1,581		24,146		14,604		4,123
Renewable energy standard (b)										2021	45,872		115		39,287		10,300
Demand side management (b)										2021	1,702		43,423		15,024		24,146
Sundance maintenance	2030	6,657		11,637		1,278		17,228		2031	184		13,515		5,698		11,319
Active union medical trust										N/A	—		7,986		—		2,041
Property tax deferral										N/A	—		7,968		—		7,046
Tax expense adjustor mechanism (b)										2020	6,615		—		7,018		—
Deferred gains on utility property	2022	3,923		5,975		4,423		6,581		2022	2,423		3,577		2,423		4,163
Four Corners coal reclamation	2038	1,858		17,690		1,858		17,871
Tax expense adjustor mechanism (a)	2020	14		—		3,237		—
FERC transmission true up										2022	3,304		1,621		1,045		2,004
Other	Various	42		4,253		42		3,541		Various	284		132		532		255
Total regulatory liabilities		$	260,404	$	2,272,082	$	165,876	$	2,325,976		$	279,105	$	2,067,801	$	234,912	$	2,267,835


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


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


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


~~(c)~~(d)	See Note 5.


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 for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement dates.

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 March 31,						Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019			2020			2019
Service cost — benefits earned during the period	$	12,543		$	14,213		$	4,714		$	5,105		$	14,257		$	12,543		$	5,717		$	4,714
Non-service costs (credits):
Interest cost on benefit obligation	34,352			31,007			7,526			7,101			29,761			34,352			6,512			7,526
Expected return on plan assets	(42,893		)	(45,667		)	(9,603		)	(10,520		)	(46,806		)	(42,893		)	(10,019		)	(9,603		)
Amortization of:
Prior service cost (credit)	—			—			(9,455		)	(9,461		)
Prior service credit													—			—			(9,394		)	(9,455		)
Net actuarial loss	11,239			7,782			—			—			9,011			11,239			—			—
Net periodic benefit cost (credit)	$	15,241		$	7,335		$	(6,818	)	$	(7,775	)	$	6,223		$	15,241		$	(7,184	)	$	(6,818	)
Portion of cost (credit) charged to expense	$	8,244		$	2,242		$	(4,817	)	$	(5,605	)	$	1,342		$	8,244		$	(5,456	)	$	(4,817	)

Contributions

We have not made voluntary contributions ~~of $90 million~~ to our pension plan year-to-date in ~~2019.~~2020. The minimum required contributions for the pension plan are ~~zero~~0 for the next three years. We expect to make voluntary contributions up to ~~a total of $350~~$100 million per year during the ~~2019-2021~~2020-2022 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.


6.	Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with ~~three~~3 separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under ~~one~~1 lease and 2033 under the other ~~two~~2 leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2020 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

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

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 of $5 million for each period, 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 March 31, ~~2019~~2020 and December 31, ~~2018~~2019 include the following amounts relating to the VIEs (dollars in thousands):


	March 31, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	104,808	$	105,775	$	100,938	$	101,906
Equity — Noncontrolling interests	130,663		125,790		127,414		122,540

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") 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 ~~$299~~$304 million beginning in ~~2019,~~2020, and up to $456 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.

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

As of March 31, ~~2019~~2020 and December 31, ~~2018,~~2019, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Quantity

Commodity

Unit of Measure

March 31, 2019

December 31, 2018

Unit of Measure

March 31, 2020

December 31, 2019

Power

GWh

1,146

250

GWh

477

193

Gas

Billion cubic feet

233

218

Billion cubic feet

263

257

Gains and Losses from Derivative Instruments

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Financial Statement Location		Three Months Ended March 31,							Financial Statement Location		Three Months Ended March 31,
Commodity Contracts		2019				2018				Financial Statement Location	2020				2019
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Financial Statement Location	Fuel and purchased power (b)		$	(436	)	$	(491	)		Fuel and purchased power (b)		$	(414	)	$	(436	)


(a)	During the three months ended March 31, ~~2019~~2020 and ~~2018,~~2019, we had no0 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 a net loss of $1approximately $0.3 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Financial Statement Location		Three Months Ended March 31,								Financial Statement Location		Three Months Ended March 31,
Commodity Contracts		2019				2018					Financial Statement Location	2020				2019
Net Loss Recognized in Income	Financial Statement Location	Operating revenues		$	—			$	(1,219	)
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)		8,170				(34,089		)		Fuel and purchased power (a)		$	(30,078	)		$	8,170
Total			$	8,170			$	(35,308	)


(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. 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. ~~Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.~~ These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, ~~2019~~2020 and December 31, ~~2018.~~2019. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~


As of March 31, 2019: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheets
As of March 31, 2020: (dollars in thousands)																Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheets
Current assets	$	3,658		$	(2,857	)	$	801		$	(38	)	$	763		$	2,778		$	(1,482	)	$	1,296		$	812		$	2,108
Investments and other assets	1,016			(881		)	135			—			135			50			(50		)	—			—			—
Total assets	4,674			(3,738		)	936			(38		)	898			2,828			(1,532		)	1,296			812			2,108

Current liabilities	(34,487		)	2,857			(31,630		)	(1,659		)	(33,289		)	(55,081		)	1,482			(53,599		)	(1,185		)	(54,784		)
Deferred credits and other	(15,725		)	881			(14,844		)	—			(14,844		)	(32,627		)	50			(32,577		)	—			(32,577		)
Total liabilities	(50,212		)	3,738			(46,474		)	(1,659		)	(48,133		)	(87,708		)	1,532			(86,176		)	(1,185		)	(87,361		)
Total	$	(45,538	)	$	—		$	(45,538	)	$	(1,697	)	$	(47,235	)	$	(84,880	)	$	—		$	(84,880	)	$	(373	)	$	(85,253	)


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


(b)	NoNaN 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 ~~$1,659~~$1,185 and cash margin provided to counterparties of ~~($38).~~$812.


As of December 31, 2018: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheets
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
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113		$	584		$	(474	)	$	110		$	405		$	515
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113			584			(474		)	110			405			515

Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)	(38,235		)	474			(37,761		)	(1,185		)	(38,946		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)	(33,186		)	—			(33,186		)	—			(33,186		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)	(71,421		)	474			(70,947		)	(1,185		)	(72,132		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)	$	(70,837	)	$	—		$	(70,837	)	$	(780	)	$	(71,617	)


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


(b)	NoNaN 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 ~~$1,310~~$1,185 and cash margin provided to counterparties of ~~$156.~~$405.

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 March 31, ~~2019,~~2020 we have one counterparty for which our exposure represents approximately 22% of Pinnacle ~~West has no counterparties with positive exposures of greater than 10% of~~West's risk management assets. This exposure relates to a master agreement with a counterparty that has a very high credit rating. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, ~~2019~~2020 (dollars in thousands):


	March 31, 2019		March 31, 2020
Aggregate fair value of derivative instruments in a net liability position	$	50,212	$	86,955
Cash collateral posted	—		—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	47,874		81,719


(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 ~~$102~~$97 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") in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment ~~of $57.4 million~~ 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. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. 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. The DOE is reviewing a possible 3 year extension of the settlement agreement. APS cannot predict the timing of the DOE's decision on the extension.

APS has submitted ~~four~~5 claims pursuant to the terms of the August 18, 2014 settlement agreement, for ~~four~~5 separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid ~~$74.2~~$84.3 million for these claims (APS’s share is ~~$21.6~~$24.5 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). On October 31, 2019, APS ~~submitted~~filed its ~~most recent~~next claim pursuant to the terms of the August 18, 2014 settlement agreement ~~to the DOE on October 31, 2018~~ in the amount of ~~$10.2~~$16 million ~~(APS's~~(APS’s share is ~~$3.0~~$4.7 million). On February 11, ~~2019 and April 10, 2019 (in response to APS's request for reconsideration),~~2020, the DOE approved ~~in total~~ a payment of ~~$10.2~~$15.4 million ~~(APS’s~~(APS's share is ~~$3.0~~$4.5 million). and on April 20, 2020, 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"), 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 ~~$14.1~~$13.8 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately ~~$13.6~~$13.3 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. TheThe maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident. Based on APS’s ownership interest in the ~~three~~3 Palo Verde units, APS’s maximum retrospective premium per incident for all ~~three~~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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

insurance for a sudden and unforeseen accidental outage of any of the ~~three~~3 units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Limited ("NEIL"). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately ~~$24.8~~$25.5 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 ~~$71.2~~$73.4 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

As of March 31, 2019, our fuel and purchased power commitments have increased approximately $180 million from the information provided in our 2018 Form 10-K. This change primarily relates to new purchased power commitments. The majority of the changes relate to 2024 and thereafter.

~~Other than the item described above,~~2020, there have been no material changes ~~as of March 31, 2019,~~ outside the normal course of business in contractual obligations from the information provided in our ~~2018~~2019 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" or "CERCLA") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ("PRPs"). PRPs may be strictly, 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 52^nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("RI/FS"). Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS in the fall ~~or winter~~ of ~~2019.~~2020. We estimate that our costs related to this investigation and study will be approximately $2$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.

On August 6, 2013, Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, ~~two~~2 RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS's exposure or risk related to these matters.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the ~~two~~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. ~~In addition, APS and certain other parties not named~~On August 16, 2019, Maricopa County, one of the three direct defendants in the ~~remaining RID~~ service provider lawsuit, ~~may be brought into the litigation via~~filed a third-party ~~complaints filed by the current direct~~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.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs"). These laws and regulations can change from time to time, imposing new obligations on APS 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 new pollution control requirements on Four ~~Corners and~~Corners. EPA required the ~~Navajo Plant. EPA will require these plants~~plant to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the ~~plants.~~plant. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 iswas approximately $400 million, ~~the majority of~~ which has ~~already~~ been incurred. In addition, APS and El Paso Electric Company ("El Paso") entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") purchased the interest from 4CA on July 3, 2018. See "Four Corners ~~Coal Supply Agreement~~ - 4CA Matter" below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

~~Navajo Plant.~~ APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs. See "Navajo Plant" in Note 4 for information regarding future plans for the Navajo Plant.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Cholla. APS believed that EPA’s original 2012 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 Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that was inconsistent 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 Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See "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.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral ~~expansions consisting of~~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" or "closure for cause" of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.

~~On December 16, 2016, President Obama signed~~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 ~~("WIIN")~~ Act ~~into law, which contains a number of provisions requiring~~in 2016, EPA ~~to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA~~possesses authority to ~~directly enforce the~~either authorize states to develop their own permit programs for CCR ~~rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing~~management or issue federal permits governing CCR disposal ~~unit permitting programs, subject to EPA approval. For facilities~~both in states ~~that do not develop state-specific permitting~~without their own permit programs ~~EPA is required~~and on tribal lands. Although ADEQ has taken steps to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

~~ADEQ has initiated a process to evaluate how to develop a state~~ CCR permitting program, it is not clear when that ~~would cover electric generating units ("EGUs"), including Cholla. While APS has been working with ADEQ on the development of this~~ program ~~we are unable to predict when Arizona~~ will be ~~able to finalize and secure~~put into effect. On December 19, 2019, EPA ~~approval for a state-specific CCR permitting program. With respect to~~proposed its own set of regulations governing the Navajo Nation, APS has sought clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuingissuance of CCR management ~~permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.~~permits.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. On ~~July 17, 2018, EPA finalized a revision to its RCRA Subtitle D regulations for CCR, the "Phase I, Part I" revision to its CCR regulations, deferring for~~

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~future action a number of other proposed changes contemplated in a~~ March 1, 2018, ~~proposal. For the final rule issued on July 17, 2018,~~as a result of a settlement with certain environmental groups, EPA established nationwide health-based standards for certain constituents of CCR subject to groundwater corrective action and delayed the closure deadlines for certain unlined CCR surface impoundments by 18 months (for example, those disposal units required to undergo forced closure). These changes to the federal regulations governing CCR disposal are unlikely to have a material impact on APS. As for those aspects of the March 2018 rulemaking proposal for which EPA has yet to take final action, it remains unclear which specific provisions of the federal CCR rules will ultimately be modified, how they will be modified, or when such modification will occur.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, EPA is required to complete a rulemaking proceeding in the near future concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. Simultaneously with the issuance of EPA's proposed modifications to the federal CCR rules in response to industry petitions, on March 1, 2018, EPA issued a proposed rule seeking comment as to whether or not boron should be included on this list. EPA is not required to take final action approving the inclusion of boron. Should EPA take final action adding boron to the list of ~~groundwater~~ constituents that ~~might~~ trigger corrective action ~~any resulting corrective~~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 ~~measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At~~on this ~~time APS cannot predict the eventual results of this rulemaking proceeding concerning boron.~~proposal.

OnBased on an August 21, 2018 ~~the~~ D.C. Circuit ~~Court issued its~~ decision, ~~on the merits in this litigation. The Court upheld the legality of EPA’s CCR regulations, though it vacated and remanded back to EPA a number of specific provisions,~~ which ~~are to be corrected in accordance with the Court’s order. Among the issues affecting APS’s management of CCR, the D.C. Circuit’s decision~~ vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, even where those unlined impoundments have not otherwise violated a regulatory location restriction or groundwater protection standard (i.e., otherwise triggering forced closure). At this time, it remains unclear how this D.C. Circuit Court decision will affect APS’s operations or any financial impacts, as EPA ~~has yet~~recently proposed corresponding changes to ~~take regulatory action on remand to revise its 2015~~federal CCR ~~regulations consistent with the Court’s order.~~

Based on this decision, on December 17, 2018, certain environmental groups filed an emergency motion with the D.C. Circuit to either stay or summarily vacate EPA's July 17, 2018 final rule extending the closure-initiation deadline for certainregulations. On November 4, 2019, EPA proposed that all unlined CCR surface impoundments, ~~until October 2020. In response,~~regardless of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity).

On November 4, 2019, EPA ~~filed a motion~~also proposed to ~~remand but not vacate~~change the manner by which facilities that ~~deadline extension regulation. On March 13, 2019,~~have committed to cease burning coal in the ~~Court issued its ruling on~~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 ~~pending motions concerning the October 2020 deadline~~federal CCR regulations. EPA’s proposal regarding alternative closure would require express EPA authorization for ~~closure initiation and granted remand without vacatur. This ruling allows the current October 2020 deadline~~such facilities to ~~remain in effect while EPA completes a rulemaking to revise or reaffirm this deadline in accordance with the August 2018 D.C. Circuit decision concerning the closure of unlined~~continue operating their CCR ~~surface impoundments. We cannot predict the outcome of EPA’s remand rulemaking concerning the October 2020 deadline for closure initiation.~~disposal units under alternative closure.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action. 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 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15 million. The Navajo Plant ~~currently disposes~~disposed of CCR only in a dry landfill storage area. ~~APS estimates that its share of incremental costs to~~To comply with the CCR rule for the Navajo Plant, isAPS's share of incremental costs was approximately $1 ~~million.~~million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule required the initiation of an assessment monitoring program by April 15, 2018.

As of October 2018, APS ~~recently~~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 operating and initiate closure by October of31, 2020. APS currently estimates that the additional incremental costs to complete this corrective action and closure work, along with the costs to develop replacement CCR disposal capacity, could be approximately $5 million for both Cholla and Four Corners. APS initiated an assessment of corrective measures on January 14, 2019 and ~~anticipates completing this~~expects such assessment ~~during the summer~~will continue through mid- to late-2020. As part of ~~2019. During~~ this assessment, APS ~~will~~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 such,~~remedies as part of this $5process. 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 ~~may change based upon APS’s performance of~~for Cholla remains ongoing at this time. As APS continues to implement the CCR rule’s corrective action assessment ~~process.~~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.~~Plan/Affordable Clean Energy Regulations. On June ~~2, 2014,~~19, 2019, EPA ~~issued two proposed rules~~took final action on its proposals to ~~regulate greenhouse gas ("GHG"~~repeal EPA's 2015 Clean Power Plan (“CPP”) ~~emissions from modified~~ and ~~reconstructed EGUs pursuant to Section 111(b) of~~replace those regulations with a new rule, the Affordable Clean ~~Air Act and existing fossil fuel-fired power plants pursuant to Clean Air Act Section 111(d). On~~Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, ~~EPA finalized carbon pollution standards for EGUs, the "Clean Power Plan". On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan~~ and ~~proposed replacement~~those regulations ~~on August 21, 2018. In addition,~~had been stayed pending judicial challenges to the Clean Power Plan are pending before the D.C. Circuit, though that litigation is currently in abeyance while EPA develops regulatory action to potentially repeal and replace that regulation.review.

~~EPA's pending proposal to regulate carbon emissions from EGUs replaces the Clean Power Plan with standards that~~The ACE regulations are based ~~entirely~~ upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the ~~Clean Power Plan,~~CPP, EPA's ~~proposed "Affordable Clean Energy Rule"~~ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. ~~In addition,~~EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to ~~address~~develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review ~~("NSR"~~(“NSR”) ~~implications~~reform regulations were proposed as part of ~~power plant upgrades potentially necessary to achieve compliance with~~EPA’s initial ACE proposal, the ~~proposed Affordable Clean Energy Rule standards,~~finalized ACE regulations did not include such reform measures. EPA ~~also proposed to revise~~announced that it will be taking final action on EPA's NSR ~~regulations to more readily authorize~~reform proposal for EGUs in the ~~implementation of EGU efficiency upgrades.~~near future.

We cannot at this time predict the outcome of EPA's regulatory actions ~~related to~~repealing and replacing the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to approve the EPA's recently proposed Affordable Clean Energy Rule. In addition, we cannot predict whetherCPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits in the D.C. Circuit ~~Court will continue to hold the litigation~~ challenging the ~~original Clean Power Plan~~legality of EPA’s action, both in ~~abeyance in light~~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 ~~EPA's repeal proposal, which is still pending.~~Arizona or EPA will implement these regulations as applied to

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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

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. ~~Oral argument~~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 ~~appeal occurred~~petition for rehearing on December 11, 2019. On March ~~7, 2019.~~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. We cannot ~~predict whether~~at this ~~appeal will be successful and, if it is successful,~~time predict the outcome of this request for further ~~district court proceedings.~~review.

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

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. EPA ~~indicated that, depending on the extent of public comments it receives concerning the permit proposal, it anticipates taking~~then issued a revised final ~~action on a new~~ NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the EAB, based upon a November 1, 2019 filing by ~~August 2019. At this time we~~several environmental groups.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We cannot predict the outcome of ~~EPA's reconsideration of the NPDES permit~~this review and whether ~~reconsideration~~the review will have a material impact on our financial position, results of operations or cash flows.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Four Corners - 4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest ~~within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise~~and ultimately purchased the option. The purchase did not occur during the originally contemplated timeframe. Concurrent with the settlement of the 2016 Coal Supply Agreement matter described above, NTEC and 4CA agreed to allow for the purchase by NTEC of the 7% interest consistent with the option. On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement providing for the sale to NTEC of 4CA's 7% interest in Four Corners. Completion of the sale was subject to the receipt of approval by FERC, which was received on July 2, 2018, and the sale transaction closed on July 3, 2018. 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 March 31, 2020, the note has a remaining balance of $40 million. NTEC continues to make payments in accordance with the terms of the note. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the note.

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

The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The ~~balance of the amount under this formula due December 31, 2018 for calendar year 2017 was approximately $20 million, which was paid to 4CA on December 14, 2018. The balance of the~~ amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) iswas approximately $10 million, which iswas due to 4CA aton December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations.

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 March 31, ~~2019,~~2020, standby letters of credit totaled ~~$0.2~~$1.7 million and will expire in ~~2019.~~2020. As of March 31, ~~2019,~~2020, surety bonds expiring through 2020 totaled ~~$17~~$14 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at March 31, ~~2019.~~2020. In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Corners. (See "Four Corners ~~Coal Supply Agreement~~ - 4CA Matter" above for information related to this guarantee.) Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West reduce as payments are made under the respective guaranteed agreements. The Equity Contribution Guarantees are currently anticipated to be terminated upon completion of construction of the respective projects, which is anticipated to occur prior to December 31, 2020, and the PTC Guarantees (approximately $40 million as of March 31, 2020) are currently expected to be terminated ten years following the commercial operation date of the applicable project.


9.	Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Other income:
Interest income	$	2,302		$	1,891		$	3,277		$	2,302
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Debt return on Four Corners SCR deferrals (Note 4)							3,140			4,844
Debt return on Ocotillo modernization project (Note 4)							6,144			—
Miscellaneous	23			2			8			23
Total other income	$	7,169		$	3,985		$	12,569		$	7,169
Other expense:
Non-operating costs	$	(2,704	)	$	(1,646	)	$	(2,658	)	$	(2,704	)
Investment losses — net	(238		)	(176		)
Investment gains — net							60			(238		)
Miscellaneous	(1,416		)	(1,407		)	(2,186		)	(1,416		)
Total other expense	$	(4,358	)	$	(3,229	)	$	(4,784	)	$	(4,358	)

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides detail of APS’s other income and other expense for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Other income:
Interest income	$	1,550		$	1,678		$	2,341		$	1,550
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Debt return on Four Corners SCR deferrals (Note 4)							3,140			4,844
Debt return on Ocotillo modernization project (Note 4)							6,144			—
Miscellaneous	22			2			8			22
Total other income	$	6,416		$	3,772		$	11,633		$	6,416
Other expense:
Non-operating costs	$	(2,467	)	$	(1,539	)	$	(2,482	)	$	(2,467	)
Miscellaneous	(1,411		)	(1,406		)	(2,186		)	(1,411		)
Total other expense	$	(3,878	)	$	(2,945	)	$	(4,668	)	$	(3,878	)

~~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 for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (in thousands, except per share amounts):


	Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2020		2019
Net income attributable to common shareholders	$	17,918	$	3,221	$	29,993	$	17,918
Weighted average common shares outstanding — basic	112,337		112,017		112,594		112,337
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	398		476		268		398
Weighted average common shares outstanding — diluted	112,735		112,493		112,862		112,735
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	0.16	$	0.03	$	0.27	$	0.16
Net income attributable to common shareholders — diluted	$	0.16	$	0.03	$	0.27	$	0.16


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 — Unadjusted quoted prices in active markets for identical assets or ~~liabilities.~~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"), 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~~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 trust 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 78 in the 2019 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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.

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

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. ~~Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions.~~

Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization.~~

Investments Held in Nuclear Decommissioning Trust and Other Special Use Funds

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

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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at March 31, ~~2019~~2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at March 31, 2019			Level 1		Level 2			Level 3			Other				Total
Assets
Cash equivalents																$	26,130	$	—		$	—		$	—			$	26,130
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	3,598		$	1,076		$	(3,776	)	(a)	$	898		—		2,325			502			(719		)	(a)	2,108
Nuclear decommissioning trust:
Equity securities	7,547		—			—			2,630			(b)	10,177			11,452		—			—			2,090			(b)	13,542
U.S. commingled equity funds	—		—			—			451,229			(c)	451,229			—		—			—			416,463			(c)	416,463
U.S. Treasury debt	155,231		—			—			—				155,231			152,951		—			—			—				152,951
Corporate debt	—		108,509			—			—				108,509			—		112,667			—			—				112,667
Mortgage-backed debt securities	—		113,002			—			—				113,002
Mortgage-backed securities																—		115,790			—			—				115,790
Municipal bonds	—		70,375			—			—				70,375			—		98,605			—			—				98,605
Other fixed income	—		10,786			—			—				10,786			—		10,408			—			—				10,408
Subtotal nuclear decommissioning trust	162,778		302,672			—			453,859				919,309			164,403		337,470			—			418,553				920,426

Other special use funds:
Equity securities	11,471		—			—			1,563			(b)	13,034			6,752		—			—			1,331			(b)	8,083
U.S. Treasury debt	208,945		—			—			—				208,945			238,637		—			—			—				238,637
Municipal bonds	—		16,228			—			—				16,228			—		6,003			—			—				6,003
Subtotal other special use funds	220,416		16,228			—			1,563				238,207			245,389		6,003			—			1,331				252,723

Total Assets	$	383,194	$	322,498		$	1,076		$	451,646			$	1,158,414
Total assets																$	435,922	$	345,798		$	502		$	419,165			$	1,201,387
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(43,524	)	$	(6,688	)	$	2,079		(a)	$	(48,133	)	$	—	$	(79,583	)	$	(8,124	)	$	346		(a)	$	(87,361	)


(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.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, ~~2018~~2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at December 31, 2018			Level 1		Level 2			Level 3			Other				Total
Assets
Cash equivalents	$	1,200	$	—		$	—		$	—			$	1,200
Risk management activities — derivative instruments:
Commodity contracts	—		3,140			2			(2,029		)	(a)	1,113			$	—	$	551		$	33		$	(69	)	(a)	$	515
Nuclear decommissioning trust:
Equity securities	5,203		—			—			2,148			(b)	7,351			10,872		—			—			2,401			(b)	13,273
U.S. commingled equity funds	—		—			—			396,805			(c)	396,805			—		—			—			518,844			(c)	518,844
U.S. Treasury debt	148,173		—			—			—				148,173			160,607		—			—			—				160,607
Corporate debt	—		96,656			—			—				96,656			—		115,869			—			—				115,869
Mortgage-backed debt securities	—		113,115			—			—				113,115
Mortgage-backed securities																—		118,795			—			—				118,795
Municipal bonds	—		79,073			—			—				79,073			—		73,040			—			—				73,040
Other fixed income	—		9,961			—			—				9,961			—		10,347			—			—				10,347
Subtotal nuclear decommissioning trust	153,376		298,805			—			398,953				851,134			171,479		318,051			—			521,245				1,010,775

Other special use funds:
Equity securities	45,130		—			—			593			(b)	45,723			7,142		—			—			474			(b)	7,616
U.S. Treasury debt	173,310		—			—			—				173,310			232,848		—			—			—				232,848
Municipal bonds	—		17,068			—			—				17,068			—		4,631			—			��				4,631
Subtotal other special use funds	218,440		17,068			—			593				236,101			239,990		4,631			—			474				245,095

Total Assets	$	373,016	$	319,013		$	2		$	397,517			$	1,089,548
Total assets																$	411,469	$	323,233		$	33		$	521,650			$	1,256,385
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(52,696	)	$	(8,216	)	$	875		(a)	$	(60,037	)	$	—	$	(67,992	)	$	(3,429	)	$	(711	)	(a)	$	(72,132	)


(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.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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.~~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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

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

~~The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at March 31, 2019 and December 31, 2018:~~

March 31, 2019
Fair Value (thousands) Valuation Technique Significant Unobservable Input Weighted-Average
Commodity Contracts Assets Liabilities Range
Electricity:

Forward Contracts (a) $ 382
$ 5,206
Discounted cash flows Electricity forward price (per MWh) $19.77 - $67.40 $ 50.50
Natural Gas:

Forward Contracts (a) 694
1,482
Discounted cash flows Natural gas forward price (per MMBtu) $1.90 - $2.97 $ 2.46
Total $ 1,076
$ 6,688


~~(a)~~	~~Includes swaps and physical and financial contracts.~~

December 31, 2018
Fair Value (thousands) Valuation Technique Significant Unobservable Input Weighted-Average
Commodity Contracts Assets Liabilities Range
Electricity:

Forward Contracts (a) $ —
$ 2,456
Discounted cash flows Electricity forward price (per MWh) $17.88 - $37.03 $ 26.10
Natural Gas:

Forward Contracts (a) 2
5,760
Discounted cash flows Natural gas forward price (per MMBtu) $1.79 - $2.92 $ 2.48
Total $ 2
$ 8,216


~~(a)~~	~~Includes swaps and physical and financial contracts.~~

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2019 and 2018 (dollars in thousands):

Three Months Ended
March 31,
Commodity Contracts 2019 2018
Net derivative balance at beginning of period $ (8,214 ) $ (18,256 )
Total net gains (losses) realized/unrealized:

Deferred as a regulatory asset or liability (1,579 ) (2,322 )
Settlements 518
782

Transfers into Level 3 from Level 2 (2 ) (2,445 )
Transfers from Level 3 into Level 2 3,665
2,487

Net derivative balance at end of period $ (5,612 ) $ (19,754 )

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

~~Transfers~~ ~~between levels in the fair value hierarchy shown in the table above~~ reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

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 ~~$57~~$40 million as of March 31, ~~2019~~2020 and ~~$61~~$44 million as of December 31, ~~2018~~2019, 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~~Trust and Other Special Use Funds

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Mine Reclamation Escrow ~~Accounts,~~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 - To fund the future costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. 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

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including ~~other-than-temporary impairments)~~credit losses) in other regulatory liabilities.

Coal Mine Reclamation Escrow ~~Accounts~~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 ~~other-than-temporary impairments)~~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 ~~were transferred from APS other postretirement benefit trust assets into the active union employee medical trust in January 2018 (see Note 7 in the 2018 Form 10-K). These investments~~ may be used to pay active union employee medical costs incurred in the current ~~period~~ and in future periods. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including ~~other-than-temporary impairments)~~credit losses) in other regulatory ~~assets.~~ liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

COMBINED NOTES TO 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 trust~~Nuclear Decommissioning Trusts and other special use fund assets at March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):


	March 31, 2019														March 31, 2020
	Fair Value							Total Unrealized Gains				Total Unrealized Losses			Fair Value										Total Unrealized Gains			Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total						Nuclear Decommissioning Trusts					Other Special Use Funds				Total					Total Unrealized Gains			Total Unrealized Losses
Equity securities	$	458,776	$	11,471	$	470,247		Total Unrealized Gains	$	273,817		Total Unrealized Losses			$	(4	)	$	427,915		$	6,752		$	434,667		$	234,695			$	(1,201	)
Available for sale-fixed income securities	457,903		225,173		683,076		(a)	15,306				(2,250		)	490,421				244,640			735,061		(a)	41,455			(3,527		)
Other	2,630		1,563		4,193		(b)	—				—			2,090				1,331			3,421		(b)	—			—
Total	$	919,309	$	238,207	$	1,157,516		$	289,123			$	(2,254	)	$	920,426			$	252,723		$	1,173,149		$	276,150		$	(4,728	)


(a)	As of March 31, ~~2019,~~2020, the amortized cost basis of these available-for-sale investments is ~~$670~~$697 million.


(b)	Represents net pending securities sales and purchases.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~


	December 31, 2018														December 31, 2019
	Fair Value							Total Unrealized Gains				Total Unrealized Losses			Fair Value										Total Unrealized Gains			Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total						Nuclear Decommissioning Trusts					Other Special Use Funds				Total					Total Unrealized Gains			Total Unrealized Losses
Equity securities	$	402,008	$	45,130	$	447,138		Total Unrealized Gains	$	222,147		Total Unrealized Losses			$	(459	)	$	529,716		$	7,142		$	536,858		$	337,681			$	—
Available for sale-fixed income securities	446,978		190,378		637,356		(a)	8,634				(6,778		)	478,658				237,479			716,137		(a)	25,795			(669		)
Other	2,148		593		2,741		(b)	—				—			2,401				474			2,875		(b)	—			—
Total	$	851,134	$	236,101	$	1,087,235		$	230,781			$	(7,237	)	$	1,010,775			$	245,095		$	1,255,870		$	363,476		$	(669	)


(a)	As of December 31, ~~2018,~~2019, the amortized cost basis of these available-for-sale investments is ~~$635~~$691 million.


(b)	Represents net pending securities sales and purchases.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Three Months Ended March 31,								Three Months Ended March 31,
	Nuclear Decommissioning Trusts			Other Special Use Funds		Total			Nuclear Decommissioning Trusts			Other Special Use Funds		Total
2020
Realized gains									$	3,313		$	—	$	3,313
Realized losses									(2,227		)	—		(2,227		)
Proceeds from the sale of securities (a)									178,196			16,891		195,087
2019
Realized gains	$	1,103		$	—	$	1,103		$	1,103		$	—	$	1,103
Realized losses	(1,405		)	—		(1,405		)	(1,405		)	—		(1,405		)
Proceeds from the sale of securities (a)	122,593			56,455		179,048			122,593			56,455		179,048
2018
Realized gains	$	814		$	1	$	815
Realized losses	(2,047		)	—		(2,047		)
Proceeds from the sale of securities (a)	130,456			2,555		133,011


(a)	Proceeds are reinvested in the ~~nuclear decommissioning trusts or~~Nuclear Decommissioning Trusts and other special use ~~funds.~~funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

The fair value of APS's fixed income securities, summarized by contractual maturities, at March 31, ~~2019,~~2020, is as follows (dollars in thousands):



	Nuclear Decommissioning Trust		Coal Mine Reclamation Escrow Account		Active Union Employee Medical Account		Total
Less than one year	$	11,911	$	37,498	$	40,872	$	90,281
1 year – 5 years	137,509		18,487		143,565		299,561
5 years – 10 years	112,834		—		—		112,834
Greater than 10 years	228,167		4,218		—		232,385
Total	$	490,421	$	60,203	$	184,437	$	735,061

Nuclear Decommissioning Trusts (a) Coal Reclamation Escrow Accounts Active Union Medical Trust Total
Less than one year $ 26,100
$ 20,085
$ 40,099
$ 86,284
1 year – 5 years 120,511
15,960
138,627
275,098
5 years – 10 years 120,342
3,581
—
123,923
Greater than 10 years 190,950
6,821
—
197,771
Total $ 457,903
$ 46,447
$ 178,726
$ 683,076


~~(a)~~	~~Includes certain fixed income investments that are not due at a single maturity date. These investments have been allocated within the table based on the final payment date of the instrument.~~

13. New Accounting Standards

~~Standards Adopted in 2019~~

~~ASU 2016-02, Leases~~

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 16.

~~Standards Pending Adoption~~

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 ~~will require~~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 isand 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 ~~are currently evaluating~~adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this ~~new accounting standard~~guidance changed our process and ~~the impacts it may have on our financial statements.~~

methodology for

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred~~determining credit losses and resulted in additional disclosures, these changes did not have a ~~Cloud Computing Arrangement That Is a Service Contract~~

In August 2018, a new accounting standard was issued that clarifies how customers in a cloud computing service arrangement should account for implementation costs associated with the arrangement. To determine which implementation costs should be capitalized, the new guidance aligns the accounting with existing guidance pertaining to internal-use software. As a result of this new standard, certain cloud computing service arrangement implementation costs will now be subject to capitalization and amortized on a straight-line basis over the cloud computing service arrangement term. The new standard is effective for us on January 1, 2020, with early application permitted, and may be applied using either a retrospective or prospective transition approach. We are currently evaluating this new accounting standard and the impacts it may havematerial impact on our financial statements.

See Note 2 for related disclosures.

14. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Pension and Other Postretirement Benefits				Derivative Instruments				Total			Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2019												$	(56,522	)		$	(574	)		$	(57,096	)
OCI (loss) before reclassifications												—				292				292
Amounts reclassified from accumulated other comprehensive loss												1,205			(a)	20			(b)	1,225
Balance March 31, 2020												$	(55,317	)		$	(262	)		$	(55,579	)

Balance December 31, 2018	$	(45,997	)		$	(1,711	)		$	(47,708	)	$	(45,997	)		$	(1,711	)		$	(47,708	)
Amounts reclassified from accumulated other comprehensive loss	879			(a)	328			(b)	1,207			879			(a)	328			(b)	1,207
Balance March 31, 2019	$	(45,118	)		$	(1,383	)		$	(46,501	)	$	(45,118	)		$	(1,383	)		$	(46,501	)

Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	900			(a)	409			(b)	1,309
Reclassification of income tax effect related to tax reform	(7,954		)	(c)	(598		)	(c)	(8,552		)
Balance March 31, 2018	$	(49,494	)		$	(2,847	)		$	(52,341	)


(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 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.


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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Pension and Other Postretirement Benefits				Derivative Instruments				Total			Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2019												$	(34,948	)		$	(574	)		$	(35,522	)
OCI (loss) before reclassifications												—				292				292
Amounts reclassified from accumulated other comprehensive loss												1,013			(a)	20			(b)	1,033
Balance March 31, 2020												$	(33,935	)		$	(262	)		$	(34,197	)

Balance December 31, 2018	$	(25,396	)		$	(1,711	)		$	(27,107	)	$	(25,396	)		$	(1,711	)		$	(27,107	)
Amounts reclassified from accumulated other comprehensive loss	752			(a)	328			(b)	1,080			752			(a)	328			(b)	1,080
Balance March 31, 2019	$	(24,644	)		$	(1,383	)		$	(26,027	)	$	(24,644	)		$	(1,383	)		$	(26,027	)

Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	857			(a)	409			(b)	1,266
Reclassification of income tax effect related to tax reform	(4,440		)	(c)	(598		)	(c)	(5,038		)
Balance March 31, 2018	$	(28,004	)		$	(2,847	)		$	(30,851	)


(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 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.


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


15.	Income Taxes

The Tax ~~Cuts and Jobs~~ Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company's proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a ~~twelve month~~twelve-month period. As a result, the Company began amortization in March 2019. ~~On April 10, 2019,~~For the quarter ended March 31, 2020, the Company ~~filed a request with the ACC which addresses~~recorded $14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred ~~taxes.~~ tax liabilities subject to its jurisdiction over a 28.5-year period with amortization to retroactively begin as of January 1, 2018. For the quarter ended March 31, 2020, the Company recorded $6 million of income tax benefit related to amortization of these depreciation related liabilities. See Note 4 for more details.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

In August 2018, U.S. Treasury proposed regulations that ~~clarify~~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, ~~the~~these proposed regulations ~~are~~were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. ~~On December 20,~~In September 2019, U.S. Treasury issued final

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the ~~Joint Committee on Taxation ("JCT") released~~Company for property placed in service after September 27, 2017 and before January 1, 2018.

Along with the ~~general explanation of the Tax Act. The document - commonly referred to as the "Blue Book" - provides a comprehensive technical description of~~September 2019 final regulations, U.S. Treasury also issued new proposed regulations which clarify bonus depreciation transition rules under the Tax Act and includes the legislative intent of Congress with respect to the changes made by provisions of the Tax Act. The "Blue Book" provides clarification that the intent of the Tax Act was to exclude from the definition of bonus depreciation qualified property anyfor property placed in service by a regulated public ~~utility~~utilities after December 31, 2017. ~~In a footnote, the JCT indicated~~The proposed regulations provide that ~~a technical correction bill may be necessary~~certain regulated public utility property which was under construction prior to ~~reflect this intent.~~

Management recognizes tax positions which it believes are “more likely than not” to be sustained upon examination. In applying this “more likely than not” assessment, the Company is required to consider the technical merits of a position, including legislative intent. As a result, while no legislation has been passed which clarifies the ambiguities related to bonus depreciation for propertySeptember 28, 2017 and placed in service ~~on or after~~between January 1, 2018 ~~the Company currently believes the continued availability of~~and December 31, 2020 would continue to be eligible for bonus depreciation ~~is not “more likely than not” to be sustained upon examination. As a result,~~under the ~~Company has not recognized any current or deferred tax benefits related to~~rules and bonus depreciation ~~for property placed~~phase-downs in ~~service on or after January 1, 2018.~~effect prior to enactment of the Tax Act.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to ~~tax (see Note 6).~~tax. As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 6 for additional details related to the Palo Verde sale leaseback VIEs.

As of the balance sheet date, the tax year ended December 31, ~~2015~~2016 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, ~~we are~~the Company is no longer subject to state income tax examinations by tax authorities for years before ~~2014.~~2015.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~


16.	~~Leases~~Asset Retirement Obligations

~~We lease certain land, buildings, vehicles, equipment~~In the first quarter of 2020, APS recognized an asset retirement obligation ("ARO") for its share of corrective action and ~~other property through operating rental agreements with varying terms, provisions,~~water monitoring costs at Four Corners and ~~expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire~~the Navajo Plant (see additional details in ~~2019 through 2050. Substantially all~~Notes 4 and 8), which resulted in a decrease to the ARO of ~~our leasing activities relate~~$11 million for Four Corners and an increase to ~~APS.~~the ARO of $5 million for the Navajo Plant.

On January 1, 2019 we adopted new lease accounting guidance (see Note 13). We elected the transition method that allows us to apply the new lease guidance on the date of adoption, January 1, 2019, and will not retrospectively adjust prior periods. We also elected certain transition practical expedients that allow us to not reassess (a) whether any expired or existing contracts are or contain leases, (b) the lease classification for any expired or existing leases and (c) initial direct costs for any existing leases. These practical expedients apply to leases that commenced prior to January 1, 2019. Furthermore, we elected the practical expedient transition provisions relating to the treatment of existing land easements.

On January 1, 2019 the adoption of this new accounting standard resulted in the recognition on our Condensed Consolidated Balance Sheets of approximately $194 million of right-of-use lease assets and $119 million of lease liabilities relating to our operating lease arrangements. The right-of-use lease assets include $85 million of prepaid lease costs that have been reclassified from other deferred debits, and $10 million of deferred lease costs that have been reclassified from other current liabilities. In addition to these balance sheet impacts, the adoption of the guidance resulted in expanded lease disclosures, which are included below.

The following ~~table provides information related to~~schedule shows the change in our ~~lease costs~~asset retirement obligations for the three months ended March 31, ~~2019~~2020 (dollars in thousands):

Three Months Ended
March 31, 2019
Purchased Power Lease Contracts Land, Property & Equipment Leases Total
Operating lease cost $ —
$ 4,348
$ 4,348
Variable lease cost 17,290
—
17,290
Total lease cost $ 17,290
$ 4,348
$ 21,638



	2020
Asset retirement obligations at January 1, 2020	$	657,218
Changes attributable to:
Accretion expense	10,219
Settlements	(2,295		)
Estimated cash flow revisions	(5,821		)
Asset retirement obligations at March 31, 2020	$	659,321

~~Lease~~In accordance with regulatory accounting, APS accrues removal costs ~~are primarily included as a component~~for its regulated utility assets, even if there is no legal obligation for removal. See detail of ~~operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded~~regulatory liabilities 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). 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 leaseliabilities 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. Short-term lease cost is immaterial.

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~The following table provides information related to the maturity of our operating lease liabilities at March 31, 2019 (dollars in thousands):~~

March 31, 2019
Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total
2019 (remaining nine months of 2019) $ 54,499
$ 10,539
$ 65,038
2020 —
12,424
12,424
2021 —
9,585
9,585
2022 —
6,621
6,621
2023 —
5,496
5,496
Thereafter —
41,618
41,618
Total lease commitments 54,499
86,283
140,782
Less imputed interest 814
20,829
21,643
Total lease liabilities $ 53,685
$ 65,454
$ 119,139

~~The following table provides information related to estimated future minimum operating lease payments at December 31, 2018 (dollars in thousands):~~

December 31, 2018
Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total
2019 $ 54,499
$ 13,747
$ 68,246
2020 —
12,428
12,428
2021 —
9,478
9,478
2022 —
6,513
6,513
2023 —
5,359
5,359
Thereafter —
42,236
42,236
Total future lease commitments $ 54,499
$ 89,761
$ 144,260

~~The following tables provide other additional information related to operating lease liabilities:~~

March 31, 2019
Weighted average remaining lease term 8 years
Weighted average discount rate 3.86 %

Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands): $ 3,087

~~COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

At March 31, 2019, we have additional lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to purchased power lease contracts. These leases have commencement dates beginning in June 2020 with terms ending through October 2027.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. See Note 6 for a discussion of VIEs.

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" at the front of this report and "Risk Factors" in Part 1, Item 1A of the ~~2018~~2019 Form ~~10-K.~~10-K and Part II, Item 1A of this report.

OVERVIEW

Business Overview

Pinnacle West ~~owns all of the outstanding common stock of APS. APS~~ is ~~a vertically-integrated~~an investor-owned electric utility ~~that provides either retail or wholesale electric service to most of the state of~~holding company based in Phoenix, Arizona with ~~the major exceptions~~consolidated assets of about ~~one-half of the Phoenix metropolitan area, the Tucson metropolitan area~~$19 billion. For over 130 years, Pinnacle West and ~~Mohave County in northwestern~~our affiliates have provided energy and energy-related products to people and businesses throughout Arizona. ~~APS currently accounts for~~

Pinnacle West derives essentially all of our revenues and ~~earnings.~~

~~Areas~~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 ~~Business Focus~~

~~Operational Performance, Reliability~~Arizona’s 15 counties. APS is also the operator and ~~Recent Developments.~~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.

~~Nuclear.~~ APS operates and is a joint owner of Palo Verde. Palo Verde experienced strong performance during 2018, with its three units achieving a combined year-end capacity factor of 90.2% and an all-time best collective radiation exposure dose performance in the history of Palo Verde’s operation.

~~Coal and Related Environmental Matters and Transactions.~~ APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning GHG emissions. On August 3, 2015, EPA finalized a rule to limit carbon dioxide emissions from existing power plants (the "Clean Power Plan"), which the EPA later proposed repealing. EPA is considering a proposed replacement to the Clean Power Plan, which was published on August 21, 2018. This new proposal, the "Affordable Clean Energy Rule," is more narrow than its predecessor regulation, and is based entirely upon heat-rate improvements at steam-electric power plants. APS continually analyzes its long-range capital management plans to assess the potential effects of such proposals, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to continue participation in such plants.

~~Cholla~~

On September 11, 2014, APS announced that it would close its 260 megawatts ("MW") Unit 2 at Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit, which was later addressed in the 2017 Settlement Agreement. (See Note 4 for details related to the resulting cost recovery.) APS believes that the environmental benefits of this proposal are greater in the long-term than the benefits that would have resulted from adding emissions control equipment. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

On March 20, 2019, APS announced that it has begun 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 will report the result of its evaluation by May 20, 2019. If converting a unit is more cost effective than alternatives, APS will seek ACC approval before moving forward with the Cholla conversion project. APS cannot predict the outcome of this matter.

~~Four Corners~~

~~Ownership and Coal Supply Matters.~~ In 2013, BHP Billiton New Mexico Coal, Inc. ("BHP Billiton"), the parent company of BHP Navajo Coal Company ("BNCC"), the coal supplier and operator of the mine that served Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects. At that same time, the Four Corners’ co-owners executed the 2016 Coal Supply Agreement for the supply of coal to Four Corners from July 2016 through 2031. El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS agreed to assume the 7% shortfall obligation. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. 4CA purchased the El Paso interest on July 6, 2016. The purchase price was immaterial in amount, and 4CA assumed El Paso's reclamation and decommissioning obligations associated with the 7% interest.

NTEC had an option to purchase the 4CA 7% interest and ultimately purchased the interest on July 3, 2018. 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. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC's 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West's guarantee is secured by a portion of APS's payments to be owed to NTEC under the 2016 Coal Supply Agreement.COVID-19 Pandemic

The ~~2016 Coal Supply Agreement contained alternate pricing terms~~current COVID-19 pandemic has led to economic disruption and volatility in financial markets worldwide. The Company is operating under long-standing crisis 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 spread of this virus and ensuring continued, safe and reliable electric service for ~~the 7% interest~~APS customers.

We have identified business-critical positions 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 ofboth our operations and ~~maintenance costs~~support organizations and identified backup personnel who are intended to provide support if needed to maintain operations with a ~~specified rate~~reduced workforce. Essential planned work and capital investments are continuing during the pandemic but certain non-essential planned work has been postponed to later in 2020. The Company conducted a contract review to confirm adequacy of ~~return, offset by revenue generated by 4CA’s power sales. Such payments are~~needed summer resources and has measures in place to continue to monitor resource needs and supply chain adequacy. At this time, the Company does not believe it has any material supply chain risks due to ~~4CA at~~COVID-19 that would impact its ability to serve customers’ needs. Although it is still too early to predict, if the impacts of COVID-19 we experienced from March 13th through April 30th continue through the end of ~~each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA~~the second quarter, we would anticipate a ~~prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount due under this formula at December 31, 2018 for calendar year 2017 was approximately~~

~~$20 million, which was paid to 4CA on December 14, 2018. The balance of the amount under this formula for calendar year 2018 (up~~net 7% decrease in weather normalized retail electricity sales compared to the ~~date that NTEC purchased the 7% interest) is approximately $10 million, which is due to 4CA at December 31,~~second quarter 2019.

~~Lease Extension.~~ ~~APS, on behalf~~As a result of the ~~Four Corners participants, negotiated amendments~~COVID-19 pandemic, in mid-March 2020 the commercial paper markets failed to ~~an existing facility lease with~~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 ~~Navajo Nation, which extends~~first quarter of 2020. In mid-April 2020, we were again able to utilize the ~~Four Corners leasehold interest from 2016~~commercial paper market and we have used the commercial paper proceeds to ~~2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of~~pay down the amendments also required the approval of the United States Department of the Interior ("DOI"), as did a related federal rights-of-way grant. A federal environmental review was undertaken as part of the DOI review process, and culminated in the issuancerevolving credit facilities by ~~DOI of a record of decision on July 17, 2015 justifying the agency action extending the life of the plant and the adjacent mine.~~

On April 20, 2016, several environmental groups filed a lawsuit against 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 ESA and 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.

~~Wastewater Permit.~~ On July 16, 2018, several environmental groups filed a petition for review before the EPA EAB concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. EPA indicated that, depending on the extent of public comments it receives concerning the permit proposal, it anticipates taking final action on a new NPDES permit by August 2019. At this time, we cannot predict the outcome of EPA's reconsideration of the NPDES permit and whether reconsideration will have a material impact on our financial position, results of operations or cash flows.

~~Navajo Plant~~

~~The co-owners~~Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of ~~the Navajo Plant and the Navajo Nation agreed~~customers for nonpayment beginning March 13, 2020. In addition, APS has waived all late payment fees during this current moratorium. APS currently estimates that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019.

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 plantSummer Disconnection Moratorium (see Note 4 for ~~details~~discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 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 anticipating 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 to $30 million range. These estimated impact amounts depend on certain assumptions, including customer behaviors and the impacts of COVID-19 on the economy not extending into 2021. APS also established a customer support fund of $1.5 million to assist customers with a one-time credit of up to $100 on their bill with a priority given to customers on limited-income service plans and also is providing $1.25 million to assist local non-profits and community organizations working to mitigate the virus' impact. 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 Note 4 for discussion of EIS and TEAM Phase II).

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 has been collected through the DSM Adjustor Clause, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020 (see Note 4 for discussion of the DSM Adjustor Clause). Also, on May 5, 2020, APS voluntarily committed to the ACC to contribute $5.3 million of non-ratepayer funds to provide assistance to residential and business customers that have been impacted by the COVID-19 pandemic.

More detailed discussion of the recent impacts and future uncertainties related to the ~~resulting regulatory asset)~~COVID‑19 pandemic can be found throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations, the Combined Notes to Pinnacle West's and APS's financial statements that appear in Item 1of this report and "Risk Factors" in Part II, Item 1A of this report.

Strategic Overview

Our strategy is to deliver shareholder value by creating a sustainable energy future for Arizona with a clean, affordable, reliable and customer-focused plan.

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 customers.

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.

~~plus~~

APS's ability to successfully execute its clean energy commitment is dependent upon a ~~return~~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 ~~the net book value as well as other costs related to retirement~~improved and ~~closure, which are still being assessed and may be material.~~

~~Natural Gas.~~ APS has six natural gas power plants located throughout Arizona, including Ocotillo. Ocotillo was originally a 330 MW 4-unit gas plant located in the metropolitan Phoenix area. In early 2014, APS announced a project to modernize the plant, which involves retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines. In total, this increases the capacity of the site by 290 MW to 620 MW, with completion targeted by the middle of 2019. (See Note 4 for details of the rate recovery in our 2017 Rate Case Decision.)new technologies.

~~Transmission~~2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and ~~Delivery.~~energy storage before 2025. By building on those plans, APS ~~continues~~intends to ~~work closely~~attain an energy mix that is 65% clean by 2030, with ~~customers, stakeholders,~~45% of APS's generation portfolio coming from renewable energy. This target will serve as a checkpoint for our resource planning, investment strategy, and ~~regulators to identify and plan for transmission needs that support new customers, system reliability, access to markets and~~customer affordability efforts as APS moves toward 100% clean, carbon-free energy development. The capital expenditures table presented in the "Liquidity and Capital Resources" section below includes new APS transmission projects, along with other transmission costs for upgrades and replacements. APS is also working to establish and expand advanced grid technologies throughout its service territory to provide long-term benefits both to APS and its customers. APS is strategically deploying a variety of technologies that are intended to allow customers to better manage their energy usage, minimize system outage durations and frequency, enable customer choice for new customer sited technologies, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions.mix by 2050.

~~Energy Imbalance Market.~~2031 Goal: End APS's Use of Coal-Fired Generation. ~~In 2015, APS and the California Independent System Operator, the operator for the majority~~The commitment to end APS's use of ~~California's transmission grid, signed an agreement for~~coal-fired generation by 2031 will require APS to ~~begin participation~~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% since 2005. In addition, APS has committed to end the Energy Imbalance Market (“EIM”). APS's participation in the EIM began on October 1, 2016. The EIM allows for rebalancing supply and demand in 15-minute blocks with dispatching every five minutes before the energy is needed, insteaduse of ~~the traditional one hour blocks. APS continues to expect that~~coal at its participation in EIM will lower its fuel costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources.remaining Cholla units by 2025.

Renewables. ~~Renewable Energy.~~ 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, including energy efficiency resources that enable renewable additions and lead to a cleaner grid.

APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas. 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 renewable energy ~~sources in APS's renewable~~ portfolio that are in operation and under development as of March 31, ~~2019.~~2020. 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	238	—		243	—
Purchased Power Agreements:
Solar	310	—		310	—
Solar + Energy Storage	—	50		—	50
Wind	289	—		289	—
Geothermal	10	—		10	—
Biomass	14	—		14	—
Biogas	6	—		3	—
Total Purchased Power Agreements	629	50		626	50
Total Distributed Energy: Solar (a)	878	30	(b)	995	37	(b)
Total Renewable Portfolio	1,745	80		1,864	87

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


(b)	Applications received by APS that are not yet installed and online.

APS has developed and owns solar resources through the ACC-approved AZ Sun Program. APS invested approximately $675 million in the AZ Sun Program. APS issued two Requests for Proposal ("RFP") in September 2019. The first 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. A second RFP requests up to 250 MW of wind resources to be in service as soon as possible, but no later than 2022.

Palo Verde. Palo Verde, the nation’s largest carbon-free, clean energy resource, will continue to be a foundational part of APS's resource portfolio. The plant 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 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.

Affordable

We believe it is APS's responsibility to deliver electric services to customers in the most cost-effective manner. Since January 2018, the average residential bill decreased by 7.8% or $11.68.

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, APS identified $20 million in possible cost savings for 2020.

Participation in the EIM continues to be an effective tool for creating savings for our customers from the real-time, voluntary market. Over the past three years, the EIM has delivered approximately $140 million in gross benefits to APS customers. APS is in discussions with the EIM operator, 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 and proactive fire mitigation efforts, APS finished 2019 with its best score for frequency of customer power outages.

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 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.

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 customers 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 through an online chat.

APS expanded financial help for its most vulnerable customers 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.

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 is convening an advisory panel of customers to gain a deeper understanding of the customer experience through their individual perspectives. A group of customer service advisors, in conjunction with local human services agencies, will provide in-person customer support in communities APS serves.

Emerging Technologies

Energy ~~Storage.~~ 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 ~~can~~in certain circumstances, be used to defer certain traditional infrastructure investments. ~~Battery~~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 ~~battery~~energy storage projects to ~~evaluate the potential benefits for~~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 ~~battery~~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 agreement is scheduled to begin in 2021. In 2018, APS issued a request for proposal for approximately 106 MW of ~~battery~~energy storage to be located at up to five of its AZ Sun sites. Based upon our 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. In February 2019, we contracted for the 141 MW and ~~anticipate~~originally anticipated such facilities could be in service by mid-2020. 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. The results of the investigation will inform the timing of our utilization and implementation of batteries on our system. Due to the April 2019 event, APS is working with the counterparty for the AZ Sun sites to determine appropriate timing and path forward for such facilities. Additionally, in February 2019, APS signed two 20-year power purchase agreements for energy storage totaling 150 MW. Service under these power purchase agreements ~~are scheduled to begin in 2021, pending~~is also dependent on the results of the McMicken battery incident investigation and requires approval from the ACC to allow for recovery of these agreements through the PSA.

We currently plan to install at least an850 MW of energy storage by 2025, including the 150 MW of energy storage projects under power purchase agreements described above. The additional ~~660~~700 MW of APS-owned ~~solar plus battery~~energy storage ~~and stand-alone battery storage systems by~~is expected to be made up of the ~~summer of 2025,~~retrofits associated with ~~the first 260 MW being procured in 2019 (60 MW on additional~~our AZ Sun sites as described above, along with current and ~~100 MW of~~future RFPs for energy storage and solar plus ~~100~~energy storage projects. Given the April 2019 event, we continue to evaluate the appropriate timing and path forward to support the overall capacity goals for our system and associated energy storage requirements. Currently, APS is pursuing an RFP for battery-ready solar resources up to 150 MW with results expected in the first half of ~~battery storage).~~2020.

Electric Vehicles

APS plans to make electric vehicle charging more accessible for its customers and help Arizona businesses, schools and governments electrify their fleets. In 2019, APS implemented its Take Charge AZ Pilot Program. The program provides charging equipment, installation, and maintenance to business customers, government agencies, and multifamily housing communities. Rates are designed to encourage charging overnight and during daytime off-peak hours when solar energy is abundant.

Hydrogen Production

Palo Verde, in partnership with Idaho National Laboratory and two other utilities, has been chosen by the 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 project, planned for 2020 through 2022, will look at how hydrogen produced from Palo Verde energy may be used as energy storage for use in reverse-operable electrolysis or peaking gas turbines during times of the day when photovoltaic solar energy

~~Regulatory Matters~~sources are unavailable and energy reserves in the southwest United States are low. It could also be used to support a rapidly increasing hydrogen transportation fuel market.

Experience from the pilot project will offer insights into methods for flexible transitions between electricity and hydrogen generation missions 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.

~~Rate Matters.~~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 ~~needs timely recovery through rates of its capital and operating expenditures~~will continue to maintain its financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by FERC. See Note 4 for information on APS’s FERC rates.monitor this emerging technology.

Regulatory Overview

On ~~June 1, 2016,~~October 31, 2019, APS filed an application with the ACC for an annual increase in retail base ~~rates. On March 27, 2017, a majority~~rates of $69 million. This amount includes recovery of the ~~stakeholders~~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 ~~general retail~~prospective inclusion of rate ~~case, including~~refunds currently provided through the ~~ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed the 2017 Settlement Agreement and filed it with the ACC.~~TEAM. The proposed total revenue increase in APS's application is $184 million. The average annual customer bill impact ~~under the 2017 Settlement Agreement was calculated as~~of APS’s request is an increase of ~~3.28%~~5.6% (the average annual bill impact for a typical APS residential customer ~~was calculated~~is 5.4%).

The principal provisions of APS's application are:

a test year comprised of twelve months ended June 30, 2019, adjusted as ~~4.54%). (See~~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;

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

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


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


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


▪	a flat bill/subscription rate pilot program;

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

recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see 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 ofrelated to the ~~2017 Settlement Agreement.)~~resulting regulatory asset).

~~On January 3, 2018, an~~ APS customer filed a petition with the ACC that was determined by the Administrative Law Judge to be a complaint filed pursuant to Arizona Revised Statute §40-246 and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant requested that the increase become effective December 1, 2020. The hearing for this rate case was delayed by 75 days, at the request of ACC ~~hold a hearing on the amended Complaint~~Staff, and is currently scheduled to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. The ACC held a hearing on this matter beginning inbegin September 2018 and the hearing was concluded on October 1, 2018. Post-hearing briefing was concluded on December 14, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On April 22, 2019, the Administrative Law Judge issued a proposed amendment to the Recommended Opinion and Order which proposes that APS credit back to customers the $5 million DSMAC funds used by APS to educate ratepayers on the new rates and that APS ratepayers will be held harmless from expenditures made by APS for targeted outreach and education in any future rate case.30, 2020. APS cannot predict the outcome of ~~this matter.~~its request.

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 and file a report by May 3, 2019. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customersSee Note 4 for information regarding the new rates approved in the 2017 Rate Case Decision. On January 9, 2019, the ACC Commissioners voted to open a docket for this matter. On April 23, 2019, the ACC Staff indicated that they may need some additional time beyond May 3, 2019 to file the requested report. APS does not believe that the rate review will have a material impact on our current financial position, results of operations or cash flows. However, depending

regulatory matters.

~~upon the results of the rate review, the ACC may take further actions, including potentially reopening the 2017 Rate Case Decision. APS cannot predict the outcome of this matter.~~

APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its demand side management and renewable energy efforts and customer programs. These mechanisms, such as the RES and DSMAC, are described more fully in Note 4.

~~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 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 rate 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 recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018. The ACC has not issued a decision on this matter. APS anticipates a decision later in 2019, however we cannot predict the outcome of the decision. 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 in Note 4).

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

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

On August 13, 2018, APS filed TEAM Phase II, 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. The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019. The impact of TEAM Phase II is expected to be

~~earnings neutral as 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 addresses the amortization of depreciation related excess deferred taxes over a 28.5 year period (“TEAM Phase III”). Over the first 36 months, TEAM Phase III is expected to return $34.5 million to customers annually, and APS has proposed this refund begin July 1, 2019. The Company is currently in the process of seeking IRS guidance affirming the amortization method and period applicable to these depreciation related excess deferred taxes. The ACC has not yet approved TEAM Phase III.

~~Subpoena from Arizona Corporation Commissioner Robert Burns.~~ On August 25, 2016, Commissioner 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.

~~February 13, 2019, Commissioner Burns filed a notice of appeal. APS and Pinnacle West 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 received subsequent requests on these matters and continues to respond to such follow-on requests. Pinnacle West and APS cannot predict the outcome of these matters.

~~Energy Modernization Plan~~. On January 30, 2018, ACC Commissioner Tobin proposed the Energy Modernization Plan, which consists 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 IRP process. The Energy Modernization Plan includes replacing the current RES standard with a new standard called the CREST, which incorporates the proposals in the Energy Modernization Plan. On July 5, 2018, ACC Commissioner Tobin’s office issued a set of draft CREST rules for the ACC’s consideration, which proposes an electricity generating portfolio of at least 80% clean energy sources (including nuclear generation) by 2050, a target of 3,000 MW of deployed energy storage by 2030, and a plan to implement a new Energy Efficiency Standard when the current standard sunsets in 2020.

~~Integrated Resource Planning~~. ACC rules require utilities to develop fifteen-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 is required to file a Preliminary Resource Plan by April 1, 2019 and its final IRP by April 1, 2020. On February 25, 2019, APS filed a request to extend the deadline to file its Preliminary Integrated Resource Plan from April 1, 2019 to August 1, 2019. On April 24, 2019, the ACC approved this request.

~~FERC Matter.~~ As part of APS’s acquisition of SCE’s interest in Four Corners Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay

SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016. On July 29, 2016, APS filed for a rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. Oral argument for this proceeding is scheduled for May 15, 2019. APS cannot predict the outcome of the proceeding.

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.~~Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. BCE's ~~focus~~strategy is ~~on new growth opportunities~~to develop, own, operate and acquire energy infrastructure in a manner that ~~leverage~~leverages the Company’s core expertise in the electric energy industry. ~~BCE’s first initiative is~~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 transmission opportunities within the eleven 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. ~~TransCanyon continues to pursue transmission development opportunities in the western United States consistent with its strategy.~~

~~El Dorado.~~ ~~The operations of El Dorado~~On December 20, 2019, BCE acquired minority ownership positions in two wind farms under development by Tenaska, the 242 MW Clear Creek wind farm in Missouri and the 250 MW Nobles 2 wind farm in Minnesota. Both wind farms are ~~not~~ expected to ~~have any material impact on our financial results, or to require any material amounts~~achieve commercial operation in 2020 and deliver power under long-term power purchase agreements. BCE indirectly owns 9.9% of ~~capital, over~~ the ~~next three years.~~Clear Creek project and 5.1% of the Nobles 2 project.

El Dorado~~4CA.~~. ~~See "Four Corners - Ownership~~El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and ~~Coal Supply Matters" above for information regarding 4CA.~~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 ~~2016~~2017 through ~~2018,~~2019, 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 ~~1.9%~~2.2% for the ~~three months~~three-month period ended March 31, ~~2019~~2020 compared with the prior-year period. For the three years ~~2016~~2017 through ~~2018,~~2019, APS’s customer growth averaged ~~1.6%~~1.8% per year. We currently project annual customer growth to be 1.5 - 2.5% for ~~2019~~2020 and ~~to average in the range of 1.5 - 2.5%~~ for ~~2019~~2020 through ~~2021~~2022 based on our assessment of ~~improving economic conditions~~steady population growth in Arizona.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased ~~1.0%~~0.8% for the ~~three months~~three-month period ended March 31, ~~2019~~2020 compared with the prior-year period. ~~Improving~~Steady economic ~~conditions~~growth and customer growth were offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives. For the three years ~~2016~~2017 through ~~2018,~~2019, 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 increase in the range of 1.0 - 2.0% for ~~2019~~2020 and increase on average in the range of ~~1.5~~1.0 - ~~2.5%~~2.0% during ~~2019~~2020 through ~~2021,~~2022, including the effects of customer conservation, ~~and~~ energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather ~~variations. Slower~~variations and the impacts of several new large data centers opening operations in Metro Phoenix.

Although it is still too early to predict, if the impacts of COVID-19 we experienced from March 13th through April 30th continue through the end of the second quarter, we would anticipate a net 7% decrease in weather normalized retail electricity sales compared to the second quarter 2019. The impact of new large data centers could raise the range of expected annual sales growth rate over the 2020 to 2022 period, but demand from these customers remains uncertain at this time. These estimates could be further impacted by slower than expected growth of the Arizona economy or acceleration of the expected effects of customer conservation, energy efficiency, or distributed renewable generation initiatives, ~~could further impact these estimates.~~or customer and sales growth not resuming and the economy not normalizing in 2020 after COVID-19.

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, impacts of energy efficiency programs and growth in ~~DG,~~distributed generation, and responses to retail price changes. Based on past experience, a ~~reasonable range of~~1% variation in our kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of ~~up to~~ approximately ~~$15~~$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 ~~$20~~$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 ~~$10~~$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 and Capital Resources" below for information regarding the planned additions to our ~~facilities~~facilities.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and ~~income~~under construction, assessment ratios, and tax ~~impacts related~~rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.9% of the assessed value for 2019, 11.0% for 2018 and 11.2% for 2017. We expect property taxes to ~~bonus depreciation.~~ 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.

~~Property Taxes.~~Interest Expense. ~~Taxes other than income taxes consist primarily of property taxes, which are~~Interest expense is affected by the ~~value~~amount of ~~property in-service~~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, assessment ratios, and tax rates. The average property tax rate~~construction. We stop accruing AFUDC on a project when it is placed in Arizona for APS, which owns essentially all of our property, was 11.0% of the assessed value for 2018, 11.2% for 2017 and 11.2% for 2016. 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. 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 Note 15 for details of the impacts on the Company as of March 31, ~~2019.~~2020.) In APS's ~~recent general retail~~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.)

~~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.

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 ~~electric service to Native Load customers)~~sales supplied under traditional cost based rate regulation) and related activities and includes electricity generation, transmission and distribution.

Operating Results — Three-month period ended March 31, ~~2019~~2020 compared with three-month period ended March 31, ~~2018.~~2019.

Our consolidated net income attributable to common shareholders for the three months ended March 31, ~~2019~~2020 was ~~$18~~$30 million, compared with consolidated net income attributable to common shareholders of $3$18 million for the prior-year period. The results reflect an increase of approximately ~~$13~~$12 million for the regulated electricity segment primarily due to ~~the effects of weather, the change in residential rate design~~lower operations and ~~seasonal rates and lower fossil planned outages, partially offset by lower~~maintenance expense, higher pension and other postretirement non-service credits and ~~higher depreciation~~lower income tax expense due to amortization of excess deferred taxes as a result of the Tax Act, partially offset by lower revenue due to the refunds provided to customers resulting from the Tax Act and ~~amortization.~~

milder weather. COVID-19 did not have a material impact on our results of operations for the period ended March 31, 2020, but we will continue to monitor its impact on our results of operations.

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


	Three Months Ended March 31,									Three Months Ended March 31,
	2019			2018			Net Change			2020			2019			Net Change
	(dollars in millions)									(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	509		$	489		$	20		$	472		$	509		$	(37	)
Operations and maintenance	(245		)	(260		)	15			(221		)	(245		)	24
Depreciation and amortization	(149		)	(144		)	(5		)	(154		)	(149		)	(5		)
Taxes other than income taxes	(55		)	(53		)	(2		)	(57		)	(55		)	(2		)
Pension and other postretirement non-service credits - net	5			13			(8		)	14			5			9
All other income and expenses, net	14			15			(1		)	16			14			2
Interest charges, net of allowance for borrowed funds used during construction	(54		)	(52		)	(2		)	(55		)	(54		)	(1		)
Income taxes	(2		)	2			(4		)	20			(2		)	22
Less income related to noncontrolling interests (Note 6)	(5		)	(5		)	—			(5		)	(5		)	—
Regulated electricity segment income	18			5			13			30			18			12
All other	—			(2		)	2			—			—			—
Net Income Attributable to Common Shareholders	$	18		$	3		$	15		$	30		$	18		$	12

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were ~~$20~~$37 million ~~higher~~lower for the three months ended March 31, ~~2019~~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 $ 28
$ 7
$ 21
Change in residential rate design and seasonal rates (a) 13
—
13
Lower transmission revenues (Note 4) (8 ) —
(8 )
Refunds due to lower Federal corporate income tax rate (Note 4) (4 ) —
(4 )
Lower renewable energy regulatory surcharges and higher purchased power, partially offset by operations and maintenance costs (5 ) 1
(6 )
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals 17
18
(1 )
Higher retail revenue due to higher customer growth and changes in customer usage patterns, partially offset by the impacts of energy efficiency and distributed generation 4
2
2
Miscellaneous items, net 4
1
3
Total $ 49
$ 29
$ 20

(a) As part of the 2017 Settlement Agreement, rate design changes were implemented in the spring of 2018 that moved some revenue responsibility from summer to non-summer months. The change was made to better align revenue collections with costs of service.



	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Amortization of excess deferred taxes (Note 4)	$	(23	)	$	—		$	(23	)
Effects of weather	(17		)	(5		)	(12		)
Lower renewable energy regulatory surcharges, partially offset by operations and maintenance costs	(4		)	1			(5		)
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(35		)	(38		)	3
Higher retail revenue due to higher customer growth, offset by the impacts of energy efficiency, distributed generation and changes in customer usage patterns	2			2			—
Miscellaneous items, net	(2		)	(2		)	—
Total	$	(79	)	$	(42	)	$	(37	)

Operations and maintenance. Operations and maintenance expenses decreased ~~$15~~$24 million for the three months ended March 31, ~~2019~~2020 compared with the prior-year period primarily because of:

A decrease of $8$10 million in fossil generation costs primarily due to lower planned ~~outages;~~outages and lower operating costs due to the Navajo plant closure (see Note 4);

A decrease of $7$6 million primarily related to costs for renewable energy and similar regulatory programs, which isare partially offset byin operating revenues and purchased ~~power.~~power;

A decrease of $3 million in nuclear generation costs;

A decrease of $3 million related to employee benefit costs; and

A decrease of $2 million for other miscellaneous factors.

Depreciation and amortization.Depreciation and amortization expenses were $5 million higher for the three months ended March 31, ~~2019~~2020 compared ~~with~~to the prior-year period primarily ~~related~~due to increased plant in ~~service.~~service of $13 million, partially offset by the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of $8 million.

Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $8$9 million higher for the three months ended March 31, 2020 compared to the prior-year period primarily due to higher market returns in 2019.

Income taxes. Income taxes were $22 million lower for the three months ended March 31, ~~2019 compared to the prior-year period primarily due to lower market returns.~~

~~Income taxes.~~ ~~Income taxes were $4 million higher for the three months ended March 31, 2019~~2020 compared with the prior-year period primarily due to ~~higher pretax income, partially offset by the effects~~amortization of ~~refunds due to lower Federal corporate income tax rate (Note 4)~~excess deferred taxes (see Note 15).

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 March 31, ~~2019,~~2020, APS’s common equity ratio, as defined, was ~~54%~~53%. Its total shareholder equity was approximately ~~$5.7~~$5.9 billion, and total capitalization was approximately ~~$10.6~~$11.1 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately ~~$4.2~~$4.4 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.

On December 20, 2018, the Joint Committee on Taxation (“JCT”) released the general explanation of the Tax Act. The document - commonly referred to as the "Blue Book" - provides a comprehensive technical description of the Tax Act and includes the legislative intent of Congress with respect to the changes made by provisions of the Tax Act. The “Blue Book” provides clarification that the intent of the Tax Act was to exclude from the definition of bonus depreciation qualified property any property placed in service by a regulated public utility after December 31, 2017. As a result, the Company currently does not anticipate recognizing any cash tax benefits related to bonus depreciation for property placed in service on or after January 1, 2018 (See Note 15).

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in millions):

Pinnacle West Consolidated


	Three Months Ended March 31,						Net			Three Months Ended March 31,						Net
	2019			2018			Change			2020			2019			Change
Net cash flow provided by operating activities	$	173		$	167		$	6		$	184		$	173		$	11
Net cash flow used for investing activities	(254		)	(361		)	107			(341		)	(254		)	(87		)
Net cash flow provided by financing activities	81			196			(115		)	210			81			129
Net change in cash and cash equivalents	$	—		$	2		$	(2	)	$	53		$	—		$	53

Arizona Public Service Company


	Three Months Ended March 31,						Net			Three Months Ended March 31,						Net
	2019			2018			Change			2020			2019			Change
Net cash flow provided by operating activities	$	188		$	177		$	11		$	194		$	188		$	6
Net cash flow used for investing activities	(260		)	(355		)	95			(343		)	(260		)	(83		)
Net cash flow provided by financing activities	72			178			(106		)	192			72			120
Net change in cash and cash equivalents	$	—		$	—		$	—		$	43		$	—		$	43

Operating Cash Flows

Three-month period ended March 31, ~~2019~~2020 compared with three-month period ended March 31, ~~2018.~~2019. Pinnacle West’s consolidated net cash provided by operating activities was $184 million in 2020, compared to $173 million in 2019, ~~and $167 million in 2018,~~ an increase of $6$11 million in net cash provided by operating ~~activities.~~activities primarily due to lower pension contributions, operations and maintenance cost, fuel and purchased power costs and interest expense, partially offset by lower cash receipts from electric revenues.

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") 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 ~~110%~~117% funded as of January 1, ~~2019~~2020 and ~~117%~~112% as of January 1, ~~2018.~~2019. Under GAAP, the qualified pension plan was 97% funded as of January 1, 2020 and 90% funded as of January 1, ~~2019 and 95% funded as of January 1, 2018.~~2019. 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 $90 million~~ to our pension plan year-to-date in ~~2019.~~2020. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to ~~a total of $350~~$100 million per year during the ~~2019-2021~~2020-2022 period. We do not expect to make any contributions over the next three years 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 is still above 90% funded as of April 30, 2020.

Investing Cash Flows

Three-month period ended March 31, ~~2019~~2020 compared with three-month period ended March 31, ~~2018.~~2019. Pinnacle West’s consolidated net cash used for investing activities was $341 million in 2020, compared to $254 million in 2019, ~~compared to $361 million in 2018, a decrease~~an increase of ~~$107~~$87 million primarily related to ~~decreased~~increased capital expenditures. ~~The difference between APS and Pinnacle West's net cash used for investing activities primarily relates to Pinnacle West's investing cash activity related to 4CA.~~

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,
	2019		2020		2021		2020		2021		2022
APS
Generation:
Clean:
Nuclear Fuel	$	71	$	64	$	64
Nuclear Generation	70		68		67		$	129	$	123	$	123
Renewables (a)	16		18		3
New Resources (b)	90		182		291
Renewables and Energy Storage Systems ("ESS") (a)							121		490		671
Environmental	31		41		71		45		53		44
New Gas Generation	16		—		—
Other Generation	119		117		105		141		154		121
Distribution	500		455		546		556		444		446
Transmission	199		171		197		181		201		205
Other (c)	125		150		128
Other (b)							158		185		115
Total APS	$	1,237	$	1,266	$	1,472	$	1,331	$	1,650	$	1,725


(a)	~~Primarily~~ APS Solar Communities program,


~~(b)~~	~~Projected future generation resources, which may include~~ energy storage, renewable projects, and other clean energy projects


~~(c)~~(b)	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 ~~projected future new resources.~~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 ~~roof top solar systems, new clean resources,~~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

Three-month period ended March 31, ~~2019~~2020 compared with three-month period ended March 31, ~~2018.~~2019. Pinnacle West’s consolidated net cash provided by financing activities was $210 million in 2020, compared to $81 million in 2019, ~~compared to $196 million~~an increase of ~~net cash provided in 2018, a decrease of $115~~$129 million in net cash provided. The ~~decrease~~increase in net cash provided by financing activities includes a net ~~decrease~~increase in ~~short term~~short-term borrowings ~~of $107 million~~ and ~~higher~~lower long-term debt repayments of ~~$500~~$350 million, ~~which was~~ partially offset by $497 million in ~~higher~~lower issuances of long-term debt. ~~The difference between APS and Pinnacle West's net cash provided by financing activities primarily relates to short-term borrowings and repayments at Pinnacle West on behalf of 4CA.~~

Significant Financing Activities. On April ~~17, 2019,~~22, 2020, the Pinnacle West Board of Directors declared a dividend of ~~$0.7375~~$0.7825 per share of common stock, payable on June ~~3, 2019~~1, 2020 to shareholders of record on May ~~1, 2019.~~4, 2020.

~~On February 26, 2019, APS~~ entered into a $200 million term loan facility that matures August 26, 2020. APS used the proceeds to repay existing indebtedness. Borrowings under the facility bear interest at LIBOR plus 0.50% per annum.

~~On March 1, 2019, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.~~

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.~~programs, to finance indebtedness, and other general corporate purposes.

~~At March 31, 2019~~,On May 5, 2020, Pinnacle West ~~had~~refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day ~~$150~~$31 million ~~credit facility~~term loan agreement that matures ~~June 27, 2019.~~on May 4, 2021. Borrowings under the ~~facility~~agreement bear interest at LIBOR plus ~~0.70%~~1.40% per annum. At March 31, ~~2019,~~2020, Pinnacle West had ~~$49~~$33 million in outstanding borrowings under the ~~facility.~~prior agreement.

At March 31, ~~2019,~~2020, Pinnacle West had a ~~$200~~$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 senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, ~~2019,~~2020, Pinnacle West had no$100 million outstanding borrowings under its credit facility, no letters of credit outstanding and ~~$38~~no commercial paper borrowings.

On January 15, 2020, APS repaid at maturity the remaining $150 million of ~~commercial paper borrowings.~~

the $250 million aggregate principal amount of its 2.2% Senior Notes.

At March 31, ~~2019,~~2020, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At March 31, ~~2019,~~2020, APS had ~~$158 million of~~no commercial paper outstanding and no$430 million outstanding borrowings or letters of credit under its revolving credit facilities.

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 used the commercial paper proceeds to pay down the revolving credit facilities by approximately $220 million through May 1, 2020. We do not believe this will have a material impact on our financial position, results of operations or cash flows.

See "Financial Assurances" in Note 8 for a discussion of ~~APS’s~~ 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 ~~this covenant.~~these covenants. For both Pinnacle West and APS, ~~this covenant requires~~these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At March 31, ~~2019,~~2020, the ratio was approximately ~~51%~~53% for Pinnacle West and ~~46%~~48% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could "cross-default" other debt. See further discussion of "cross-default" provisions below.

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

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

On November 27, 2018, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit from $5.1 billion to $5.9 billion, and authorized APS’s short-term debt limit equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power).

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. If the ACC does not approve this application by December 31, 2020, this could impact APS’s ability to enter into new long-term debt obligations.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of ~~April 24, 2019~~May 1, 2020 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	A3	A-	A-
Senior unsecured	A3	BBB+	A-
Commercial paper	P-2	A-2	F2
Outlook	~~Stable~~Negative	Stable	~~Stable~~Negative

APS
Corporate credit rating	A2	A-	A-
Senior unsecured	A2	A-	A
Commercial paper	P-1	A-2	F2
Outlook	~~Stable~~Negative	Stable	~~Stable~~Negative

Off-Balance Sheets Arrangements

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

Contractual Obligations

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 ~~2018~~2019 Form 10-K. See "Critical Accounting Policies" in Item 7 of the ~~2018~~2019 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

On January 1, ~~2019~~2020 we adopted ~~new lease accounting guidance (ASU 2016-02,~~ASU 2016-13, and related ~~amendments) (see Note 16). We are currently evaluating~~amendments, pertaining to the ~~impacts~~measurement of ~~the pending adoption of the following new accounting standards effective for us~~credit losses on ~~January 1, 2020:~~

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

~~ASU 2018-15: Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~

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 trust, 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 trust, other special use funds (see Note 11 and Note 12), and benefit plan assets. The nuclear decommissioning trust, 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. 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 for the three months ended March 31, ~~2019~~2020 and ~~2018~~2019 (dollars in millions):


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Mark-to-market of net positions at beginning of period	$	(58	)	$	(91	)	$	(71	)	$	(58	)
Decrease (Increase) in regulatory asset/liability	12			(21		)
Decrease (Increase) in regulatory asset							(14		)	12
Recognized in OCI:
Mark-to-market losses realized during the period	—			—			—			—
Change in valuation techniques	—			—			—			—
Mark-to-market of net positions at end of period	$	(46	)	$	(112	)	$	(85	)	$	(46	)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at March 31, ~~2019~~2020 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" and "Fair Value Measurements," in Item 8 of our ~~2018~~2019 Form 10-K and Note 11 for more discussion of our valuation methods.


Source of Fair Value	2019			2020			2021			2022			2023		Total fair value			2020			2021			2022			2023			2024			Total Fair Value
Observable prices provided by other external sources	$	(23	)	$	(8	)	$	(6	)	$	(3	)	$	—	$	(40	)	$	(46	)	$	(13	)	$	(12	)	$	(6	)	$	—		$	(77	)
Prices based on unobservable inputs	(4		)	(2		)	—			—			—		(6		)	(5		)	—			—			—			(3		)	(8		)
Total by maturity	$	(27	)	$	(10	)	$	(6	)	$	(3	)	$	—	$	(46	)	$	(51	)	$	(13	)	$	(12	)	$	(6	)	$	(3	)	$	(85	)

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 at March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in millions):


	March 31, 2019					December 31, 2018					March 31, 2020					December 31, 2019
	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:
Regulatory asset (liability) (a)
Regulatory asset (a)
Electricity	$	5	$	(5	)	$	1	$	(1	)	$	1	$	(1	)	$	—	$	—
Natural gas	45		(45		)	44		(44		)	53		(53		)	55		(55		)
Total	$	50	$	(50	)	$	45	$	(45	)	$	54	$	(54	)	$	55	$	(55	)


(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 Financial Drivers" and "Market and Credit 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 controls and 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") (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 March 31, ~~2019.~~2020. 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 March 31, ~~2019.~~2020. 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 control over financial 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 March 31, ~~2019~~2020 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See "Business of Arizona Public Service Company — Environmental Matters" in Item 1 of the ~~2018~~2019 Form 10-K with regard to pending or threatened litigation and other disputes.

See Note 4 for ACC and FERC-related matters.

See Note 8 for information regarding environmental matters and Superfund-related matters.

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 ~~2018~~2019 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS. The risks described in the ~~2018~~2019 Form 10-K 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.

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.

In the near term, as a result of the COVID-19 pandemic, in mid-March 2020 we drew on our revolving credit facilities as a result of the commercial paper markets failing to function normally. Additionally, in March and April 2020 we experienced a net decrease in weather normalized retail electricity sales as compared to 2019. APS is also anticipating an increase in bad debt expense associated with the COVID-19 pandemic that will result in a negative impact to our 2020 operating results. 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.~~Labor Union Matter

Approximately 1,300 APS employees are union employees, represented by the International Brotherhood of Electrical Workers ("IBEW"). In March 2020, the Company concluded negotiations with the

IBEW and approved an extension of the contract that was set to expire on April 1, 2020 and that will now expire on April 1, 2023. Under the extension, union members received wage increases for 2020, 2021, and 2022.

Item 6. EXHIBITS

(a) Exhibits



Exhibit No.	Registrant(s)	Description

10.1	~~Pinnacle West APS~~	Term Loan Agreement dated as of February 26, 2019 among APS, as Borrower, SunTrust Bank, as Agent, SunTrust Bank, TD Bank, N.A., U.S. Bank National Association and The Bank of Nova Scotia, as Co-Syndication Agents and such institutions compromising the lenders party thereto

~~10.2~~	~~Pinnacle West~~	~~Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan~~

~~10.3~~	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.2	Pinnacle West	364-Day Term Loan, dated as of May 5, 2020, among Pinnacle West, as Borrower, PNC Bank, National Association, as Agent

31.1	Pinnacle West	Certificate of ~~Donald E. Brandt,~~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 ~~James R. Hatfield, Executive Vice President and~~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 ~~Donald E. Brandt,~~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 ~~James R. Hatfield, Executive Vice President and~~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.

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 ~~22, 2017~~19, 2020	3.1 to Pinnacle West/APS February ~~28, 2017~~25, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473	2/~~28/2017~~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.

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:	May ~~1, 2019~~8, 2020	By:	/s/ ~~James R. Hatfield~~Theodore N. Geisler
		~~James R. Hatfield~~	Theodore N. Geisler
		~~Executive~~	Senior Vice President and
			Chief Financial Officer
			(Principal Financial Officer and
			Officer Duly Authorized to sign this Report)


		ARIZONA PUBLIC SERVICE COMPANY
		(Registrant)


Dated:	May ~~1, 2019~~8, 2020	By:	/s/ ~~James R. Hatfield~~Theodore N. Geisler
		~~James R. Hatfield~~	Theodore N. Geisler
		~~Executive~~	Senior Vice President and
			Chief Financial Officer
			(Principal Financial Officer and
			Officer Duly Authorized to sign this Report)

9390



		Page

Forward-Looking Statements		2
Part I		4
Item 1.	Financial Statements	4
	Pinnacle West Capital Corporation	5
	Arizona Public Service Company	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6665
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	8884
Item 4.	Controls and Procedures	8885

Part II		8986
Item 1.	Legal Proceedings	8986
Item 1A.	Risk Factors	8986
Item 5.	Other Information	8986
Item 6.	Exhibits	9088
Signatures		9390



	March 31, 2019 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Electricity:
Forward Contracts (a)	$	382	$	5,206	Discounted cash flows	Electricity forward price (per MWh)	$19.77 - $67.40	$	50.50
Natural Gas:
Forward Contracts (a)	694		1,482		Discounted cash flows	Natural gas forward price (per MMBtu)	$1.90 - $2.97	$	2.46
Total	$	1,076	$	6,688



	Nuclear Decommissioning Trusts (a)		Coal Reclamation Escrow Accounts		Active Union Medical Trust		Total
Less than one year	$	26,100	$	20,085	$	40,099	$	86,284
1 year – 5 years	120,511		15,960		138,627		275,098
5 years – 10 years	120,342		3,581		—		123,923
Greater than 10 years	190,950		6,821		—		197,771
Total	$	457,903	$	46,447	$	178,726	$	683,076



	Three Months Ended March 31, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	—	$	4,348	$	4,348
Variable lease cost	17,290		—		17,290
Total lease cost	$	17,290	$	4,348	$	21,638



	March 31, 2019
Year	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
2019 (remaining nine months of 2019)	$	54,499	$	10,539	$	65,038
2020	—		12,424		12,424
2021	—		9,585		9,585
2022	—		6,621		6,621
2023	—		5,496		5,496
Thereafter	—		41,618		41,618
Total lease commitments	54,499		86,283		140,782
Less imputed interest	814		20,829		21,643
Total lease liabilities	$	53,685	$	65,454	$	119,139



	March 31, 2019
Weighted average remaining lease term	8 years
Weighted average discount rate	3.86		%

	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	3,087