10-Q

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 June 30, 2019

OR

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

For the transition period from              to          

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION	Yes	☒	No	☐
ARIZONA PUBLIC SERVICE COMPANY	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	☒	No	☐
ARIZONA PUBLIC SERVICE COMPANY	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	☒	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	☒
ARIZONA PUBLIC SERVICE COMPANY	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 August 1, 2019:	112,303,854
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of August 1, 2019:	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

		Page
Forward-Looking Statements		2
Part I		3
Item 1.	Financial Statements	3
	Pinnacle West Capital Corporation	4
	Arizona Public Service Company	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	72
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	97
Item 4.	Controls and Procedures	97
Part II		98
Item 1.	Legal Proceedings	98
Item 1A.	Risk Factors	98
Item 5.	Other Information	98
Item 6.	Exhibits	99
Signatures		101

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.

1

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" and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2018 ("2018 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:

• 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, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation;

• 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 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.

2

PART I — FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

	Page
Pinnacle West Condensed Consolidated Statements of Income for Three and Six Months Ended June 30, 2019 and 2018	4
Pinnacle West Condensed Consolidated Statements of Comprehensive Income for Three and Six Months Ended June 30, 2019 and 2018	5
Pinnacle West Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	6
Pinnacle West Condensed Consolidated Statements of Cash Flows for Six Months Ended June 30, 2019 and 2018	8
Pinnacle West Condensed Consolidated Statements of Changes in Equity for Three and Six Months Ended June 30, 2019 and 2018	9
APS Condensed Consolidated Statements of Income for Three and Six Months Ended June 30, 2019 and 2018	11
APS Condensed Consolidated Statements of Comprehensive Income for Three and Six Months Ended June 30, 2019 and 2018	12
APS Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	13
APS Condensed Consolidated Statements of Cash Flows for Six Months Ended June 30, 2019 and 2018	15
APS Condensed Consolidated Statements of Changes in Equity for Three and Six Months Ended June 30, 2019 and 2018	16
Combined Notes to Condensed Consolidated Financial Statements	18
Note 1. Consolidation and Nature of Operations	18
Note 2. Revenue	19
Note 3. Long-Term Debt and Liquidity Matters	20
Note 4. Regulatory Matters	22
Note 5. Retirement Plans and Other Postretirement Benefits	36
Note 6. Palo Verde Sale Leaseback Variable Interest Entities	37
Note 7. Derivative Accounting	38
Note 8. Commitments and Contingencies	43
Note 9. Other Income and Other Expense	51
Note 10. Earnings Per Share	52
Note 11. Fair Value Measurements	52
Note 12. Investment in Nuclear Decommissioning Trust and Other Special Use Funds	59
Note 13. New Accounting Standards	63
Note 14. Changes in Accumulated Other Comprehensive Loss	64
Note 15. Income Taxes	67
Note 16. Leases	68

3

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
OPERATING REVENUES (NOTE 2)	$	869,501		$	974,123		$	1,610,031		$	1,666,837
OPERATING EXPENSES
Fuel and purchased power	242,222			257,087			472,810			454,197
Operations and maintenance	227,543			268,397			473,177			534,079
Depreciation and amortization	147,374			145,436			296,081			290,261
Taxes other than income taxes	55,090			53,607			110,180			107,207
Other expenses	683			7,434			1,110			7,597
Total	672,912			731,961			1,353,358			1,393,341
OPERATING INCOME	196,589			242,162			256,673			273,496
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,572			13,073			18,760			27,152
Pension and other postretirement non-service credits - net	6,374			12,006			11,488			24,865
Other income (Note 9)	12,885			6,598			20,054			10,583
Other expense (Note 9)	(4,350		)	(3,771		)	(8,708		)	(7,000		)
Total	22,481			27,906			41,594			55,600
INTEREST EXPENSE
Interest charges	57,465			60,708			118,118			119,662
Allowance for borrowed funds used during construction	(4,494		)	(6,291		)	(11,159		)	(13,046		)
Total	52,971			54,417			106,959			106,616
INCOME BEFORE INCOME TAXES	166,099			215,651			191,308			222,480
INCOME TAXES	17,080			44,039			19,498			42,774
NET INCOME	149,019			171,612			171,810			179,706
Less: Net income attributable to noncontrolling interests (Note 6)	4,874			4,874			9,747			9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	144,145		$	166,738		$	162,063		$	169,959
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	112,337			112,115			112,381			112,067
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,651			112,471			112,734			112,482
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	1.28		$	1.49		$	1.44		$	1.52
Net income attributable to common shareholders — diluted	$	1.28		$	1.48		$	1.44		$	1.51

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

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
NET INCOME	$	149,019		$	171,612		$	171,810		$	179,706
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $0, $0, $0 and $96 for the respective periods	—			—			—			(96		)
Reclassification of net realized loss, net of tax benefit of $134, $150, $242 and $232 for the respective periods	404			456			732			865
Pension and other postretirement benefits activity, net of tax benefit of $506, $1,558, $218 and $1,115 for the respective periods	(1,539		)	(4,739		)	(660		)	(3,839		)
Total other comprehensive income (loss)	(1,135		)	(4,283		)	72			(3,070		)
COMPREHENSIVE INCOME	147,884			167,329			171,882			176,636
Less: Comprehensive income attributable to noncontrolling interests	4,874			4,874			9,747			9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	143,010		$	162,455		$	162,135		$	166,889

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

5

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2019			December 31, 2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,648		$	5,766
Customer and other receivables	263,836			267,887
Accrued unbilled revenues	193,657			137,170
Allowance for doubtful accounts	(3,095		)	(4,069		)
Materials and supplies (at average cost)	289,928			269,065
Fossil fuel (at average cost)	25,453			25,029
Assets from risk management activities (Note 7)	459			1,113
Deferred fuel and purchased power regulatory asset (Note 4)	30,559			37,164
Other regulatory assets (Note 4)	153,900			129,738
Other current assets	72,222			56,128
Total current assets	1,028,567			924,991
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	950,448			851,134
Other special use funds (Notes 11 and 12)	241,558			236,101
Other assets	97,322			103,247
Total investments and other assets	1,289,328			1,190,482
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	19,630,407			18,736,628
Accumulated depreciation and amortization	(6,470,935		)	(6,366,014		)
Net	13,159,472			12,370,614
Construction work in progress	568,890			1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	103,841			105,775
Intangible assets, net of accumulated amortization	261,584			262,902
Nuclear fuel, net of accumulated amortization	159,633			120,217
Total property, plant and equipment	14,253,420			14,029,570
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,431			1,342,941
Operating lease right-of-use assets (Note 16)	176,219			—
Assets for other postretirement benefits (Note 5)	56,336			46,906
Other	40,365			129,312
Total deferred debits	1,594,351			1,519,159
TOTAL ASSETS	$	18,165,666		$	17,664,202

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

6

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	327,969		$	277,336
Accrued taxes	158,921			154,819
Accrued interest	50,581			61,107
Common dividends payable	82,824			82,675
Short-term borrowings (Note 3)	432,373			76,400
Current maturities of long-term debt (Note 3)	250,000			500,000
Customer deposits	84,177			91,174
Liabilities from risk management activities (Note 7)	58,834			35,506
Liabilities for asset retirements	21,950			19,842
Operating lease liabilities (Note 16)	60,596			—
Regulatory liabilities (Note 4)	231,857			165,876
Other current liabilities	140,879			184,229
Total current liabilities	1,900,961			1,648,964
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)	4,886,879			4,638,232
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,838,145			1,807,421
Regulatory liabilities (Note 4)	2,287,892			2,325,976
Liabilities for asset retirements	723,005			706,703
Liabilities for pension benefits (Note 5)	356,928			443,170
Liabilities from risk management activities (Note 7)	21,592			24,531
Customer advances	174,411			137,153
Coal mine reclamation	197,443			212,785
Deferred investment tax credit	197,749			200,405
Unrecognized tax benefits	26,271			22,517
Operating lease liabilities (Note 16)	53,005			—
Other	144,142			147,640
Total deferred credits and other	6,020,583			6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,361,595 and 112,159,896 issued at respective dates	2,648,234			2,634,265
Treasury stock at cost; 58,219 and 58,135 shares at respective dates	(5,140		)	(4,825		)
Total common stock	2,643,094			2,629,440
Retained earnings	2,637,620			2,641,183
Accumulated other comprehensive loss	(47,636		)	(47,708		)
Total shareholders’ equity	5,233,078			5,222,915
Noncontrolling interests (Note 6)	124,165			125,790
Total equity	5,357,243			5,348,705
TOTAL LIABILITIES AND EQUITY	$	18,165,666		$	17,664,202

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

7

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	171,810		$	179,706
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	332,185			325,550
Deferred fuel and purchased power	(16,702		)	(50,112		)
Deferred fuel and purchased power amortization	23,307			50,851
Allowance for equity funds used during construction	(18,760		)	(27,152		)
Deferred income taxes	4,326			33,711
Deferred investment tax credit	(2,656		)	(2,778		)
Stock compensation	13,725			13,189
Changes in current assets and liabilities:
Customer and other receivables	3,543			(18,672		)
Accrued unbilled revenues	(56,487		)	(95,453		)
Materials, supplies and fossil fuel	(21,287		)	(22,970		)
Other current assets	(16,121		)	11,069
Accounts payable	65,874			36,614
Accrued taxes	4,102			8,140
Other current liabilities	(61,270		)	9,410
Change in other long-term assets	(82,850		)	23,927
Change in other long-term liabilities	3,195			(79,228		)
Net cash flow provided by operating activities	345,934			395,802
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(541,401		)	(679,949		)
Contributions in aid of construction	18,909			19,339
Allowance for borrowed funds used during construction	(11,159		)	(13,046		)
Proceeds from nuclear decommissioning trust sales and other special use funds	309,354			258,401
Investment in nuclear decommissioning trust and other special use funds	(310,494		)	(259,542		)
Other	7,153			(4,299		)
Net cash flow used for investing activities	(527,638		)	(679,096		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324			—
Short-term borrowing and payments — net	363,973			500,849
Short-term debt borrowings	49,000			45,000
Short-term debt repayments	(57,000		)	(25,000		)
Dividends paid on common stock	(161,979		)	(151,942		)
Repayment of long-term debt	(500,000		)	(82,000		)
Common stock equity issuance - net of purchases	(2,360		)	(2,294		)
Distributions to noncontrolling interests	(11,372		)	(11,372		)
Net cash flow provided by financing activities	177,586			273,241
NET DECREASE IN CASH AND CASH EQUIVALENTS	(4,118		)	(10,053		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,766			13,892
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,648		$	3,839

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

8

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)

	Three Months Ended June 30, 2019
	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
Balance, April 1, 2019	112,340,322	$	2,644,063	(63,271	)	$	(5,586	)	$	2,659,086		$	(46,501	)	$	130,663		$	5,381,725
Net income		—				—			144,145			—			4,874			149,019
Other comprehensive loss		—				—			—			(1,135		)	—			(1,135		)
Dividends on common stock ($1.48 per share)		—				—			(165,611		)	—			—			(165,611		)
Issuance of common stock	21,273	4,171				—			—			—			—			4,171
Reissuance of treasury stock for stock-based compensation and other		—		5,052		446			—			—			—			446
Capital activities by noncontrolling interests		—				—			—			—			(11,372		)	(11,372		)
Balance, June 30, 2019	112,361,595	$	2,648,234	(58,219	)	$	(5,140	)	$	2,637,620		$	(47,636	)	$	124,165		$	5,357,243

	Three Months Ended June 30, 2018
	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
Balance, April 1, 2018	111,961,963	$	2,620,261	(29,097	)	$	(2,431	)	$	2,454,268		$	(52,341	)	$	133,914		$	5,153,671
Net income		—				—			166,738			—			4,874			171,612
Other comprehensive loss		—				—			—			(4,283		)	—			(4,283		)
Dividends on common stock ($1.39 per share)		—				—			(155,604		)	—			—			(155,604		)
Issuance of common stock	28,259	4,411				—			—			—			—			4,411
Reissuance of treasury stock for stock-based compensation and other		—		11,464		1,000			—			—			(1		)	999
Capital activities by noncontrolling interests		—				—			—			—			(11,372		)	(11,372		)
Balance, June 30, 2018	111,990,222	$	2,624,672	(17,633	)	$	(1,431	)	$	2,465,402		$	(56,624	)	$	127,415		$	5,159,434

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

9

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)

	Six Months Ended June 30, 2019
	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
Balance, January 1, 2019	112,159,896	$	2,634,265	(58,135	)	$	(4,825	)	$	2,641,183		$	(47,708	)	$	125,790		$	5,348,705
Net income		—				—			162,063			—			9,747			171,810
Other comprehensive loss		—				—			—			72			—			72
Dividends on common stock ($1.48 per share)		—				—			(165,626		)	—			—			(165,626		)
Issuance of common stock	201,699	13,969				—			—			—			—			13,969
Purchase of treasury stock (a)		—		(75,791	)	(6,882		)	—			—			—			(6,882		)
Reissuance of treasury stock for stock-based compensation and other		—		75,707		6,567			—			—			—			6,567
Capital activities by noncontrolling interests		—				—			—			—			(11,372		)	(11,372		)
Balance, June 30, 2019	112,361,595	$	2,648,234	(58,219	)	$	(5,140	)	$	2,637,620		$	(47,636	)	$	124,165		$	5,357,243

	Six Months Ended June 30, 2018
	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
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		—				—			169,959			—			9,747			179,706
Other comprehensive loss		—				—			—			(3,070		)	—			(3,070		)
Dividends on common stock ($1.39 per share)		—				—			(155,620		)	—			—			(155,620		)
Issuance of common stock	174,052	9,867				—			—			—			—			9,867
Purchase of treasury stock (a)		—		(81,177	)	(6,277		)	—			—			—			(6,277		)
Reissuance of treasury stock for stock-based compensation and other		—		128,007		10,470			—			—			—			10,470
Capital activities by noncontrolling interests		—				—			—			—			(11,372		)	(11,372		)
Reclassification of income tax effects related to new tax reform (b)		—				—			8,552			(8,552		)	—			—
Balance, June 30, 2018	111,990,222	$	2,624,672	(17,633	)	$	(1,431	)	$	2,465,402		$	(56,624	)	$	127,415		$	5,159,434

(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.

10

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
OPERATING REVENUES	$	869,501		$	971,963		$	1,610,031		$	1,663,969
OPERATING EXPENSES
Fuel and purchased power	242,222			270,138			472,810			472,148
Operations and maintenance	224,143			251,999			464,518			506,600
Depreciation and amortization	147,354			144,533			296,039			288,645
Taxes other than income taxes	55,081			53,269			110,159			106,511
Other expenses	683			434			1,110			597
Total	669,483			720,373			1,344,636			1,374,501
OPERATING INCOME	200,018			251,590			265,395			289,468
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,572			13,073			18,760			27,152
Pension and other postretirement non-service credits - net	6,757			12,389			12,256			25,586
Other income (Note 9)	11,691			6,235			18,107			10,007
Other expense (Note 9)	(3,428		)	(3,372		)	(7,306		)	(6,318		)
Total	22,592			28,325			41,817			56,427
INTEREST EXPENSE
Interest charges	53,591			57,731			110,256			113,889
Allowance for borrowed funds used during construction	(4,494		)	(6,291		)	(11,159		)	(13,046		)
Total	49,097			51,440			99,097			100,843
INCOME BEFORE INCOME TAXES	173,513			228,475			208,115			245,052
INCOME TAXES	18,463			45,776			19,916			47,882
NET INCOME	155,050			182,699			188,199			197,170
Less: Net income attributable to noncontrolling interests (Note 6)	4,874			4,874			9,747			9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	150,176		$	177,825		$	178,452		$	187,423

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

11

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
NET INCOME	$	155,050		$	182,699		$	188,199		$	197,170
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $0, $0, $0 and $96 for the respective periods	—			—			—			(96		)
Reclassification of net realized loss, net of tax benefit of $134, $150, $242 and $232 for the respective periods	404			456			732			865
Pension and other postretirement benefits activity, net of tax benefit of $544, $1,566, $297 and $1,260 for the respective periods	(1,653		)	(4,764		)	(901		)	(3,907		)
Total other comprehensive income (loss)	(1,249		)	(4,308		)	(169		)	(3,138		)
COMPREHENSIVE INCOME	153,801			178,391			188,030			194,032
Less: Comprehensive income attributable to noncontrolling interests	4,874			4,874			9,747			9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	148,927		$	173,517		$	178,283		$	184,285

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

12

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2019			December 31, 2018
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	19,626,920		$	18,733,142
Accumulated depreciation and amortization	(6,467,684		)	(6,362,771		)
Net	13,159,236			12,370,371
Construction work in progress	568,890			1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	103,841			105,775
Intangible assets, net of accumulated amortization	261,429			262,746
Nuclear fuel, net of accumulated amortization	159,633			120,217
Total property, plant and equipment	14,253,029			14,029,171
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	950,448			851,134
Other special use funds (Notes 11 and 12)	241,558			236,101
Other assets	46,089			40,817
Total investments and other assets	1,238,095			1,128,052
CURRENT ASSETS
Cash and cash equivalents	1,355			5,707
Customer and other receivables	253,501			257,654
Accrued unbilled revenues	193,657			137,170
Allowance for doubtful accounts	(3,095		)	(4,069		)
Materials and supplies (at average cost)	289,928			269,065
Fossil fuel (at average cost)	25,453			25,029
Assets from risk management activities (Note 7)	459			1,113
Deferred fuel and purchased power regulatory asset (Note 4)	30,559			37,164
Other regulatory assets (Note 4)	153,900			129,738
Other current assets	49,697			35,111
Total current assets	995,414			893,682
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,431			1,342,941
Operating lease right-of-use assets (Note 16)	174,320			—
Assets for other postretirement benefits (Note 5)	52,611			43,212
Other	39,523			128,265
Total deferred debits	1,587,885			1,514,418
TOTAL ASSETS	$	18,074,423		$	17,565,323

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

13

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands) 

	June 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,721,696			2,721,696
Retained earnings	2,801,110			2,788,256
Accumulated other comprehensive loss	(27,276		)	(27,107		)
Total shareholder equity	5,673,692			5,661,007
Noncontrolling interests (Note 6)	124,165			125,790
Total equity	5,797,857			5,786,797
Long-term debt less current maturities (Note 3)	4,437,768			4,189,436
Total capitalization	10,235,625			9,976,233
CURRENT LIABILITIES
Short-term borrowings (Note 3)	376,873			—
Current maturities of long-term debt (Note 3)	250,000			500,000
Accounts payable	319,435			266,277
Accrued taxes	175,922			176,357
Accrued interest	49,703			60,228
Common dividends payable	82,800			82,700
Customer deposits	84,177			91,174
Liabilities from risk management activities (Note 7)	58,834			35,506
Liabilities for asset retirements	21,950			19,842
Operating lease liabilities (Note 16)	60,395			—
Regulatory liabilities (Note 4)	231,857			165,876
Other current liabilities	138,423			178,137
Total current liabilities	1,850,369			1,576,097
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,831,660			1,812,664
Regulatory liabilities (Note 4)	2,287,892			2,325,976
Liabilities for asset retirements	723,005			706,703
Liabilities for pension benefits (Note 5)	340,154			425,404
Liabilities from risk management activities (Note 7)	21,592			24,531
Customer advances	174,411			137,153
Coal mine reclamation	197,443			212,785
Deferred investment tax credit	197,749			200,405
Unrecognized tax benefits	42,313			41,861
Operating lease liabilities (Note 16)	51,158			—
Other	121,052			125,511
Total deferred credits and other	5,988,429			6,012,993
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
TOTAL LIABILITIES AND EQUITY	$	18,074,423		$	17,565,323

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

14

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	188,199		$	197,170
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	332,143			323,934
Deferred fuel and purchased power	(16,702		)	(50,112		)
Deferred fuel and purchased power amortization	23,307			50,851
Allowance for equity funds used during construction	(18,760		)	(27,152		)
Deferred income taxes	(10,625		)	10,372
Deferred investment tax credit	(2,656		)	(2,778		)
Changes in current assets and liabilities:
Customer and other receivables	3,645			(9,254		)
Accrued unbilled revenues	(56,487		)	(95,453		)
Materials, supplies and fossil fuel	(21,287		)	(23,073		)
Other current assets	(14,613		)	7,552
Accounts payable	68,399			39,573
Accrued taxes	(435		)	26,412
Other current liabilities	(57,709		)	7,395
Change in other long-term assets	(84,946		)	34,947
Change in other long-term liabilities	3,253			(84,643		)
Net cash flow provided by operating activities	334,726			405,741
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(541,401		)	(670,841		)
Contributions in aid of construction	18,909			19,339
Allowance for borrowed funds used during construction	(11,159		)	(13,046		)
Proceeds from nuclear decommissioning trust sales and other special use funds	309,354			258,227
Investment in nuclear decommissioning trust and other special use funds	(310,494		)	(259,367		)
Other	(1,612		)	(1,221		)
Net cash flow used for investing activities	(536,403		)	(666,909		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324			—
Short-term borrowings and payments — net	376,873			499,949
Short-term debt borrowings under revolving credit facility	—			25,000
Short-term debt repayments under revolving credit facility	—			(25,000		)
Repayment of long-term debt	(500,000		)	(82,000		)
Dividends paid on common stock	(165,500		)	(155,500		)
Distributions to noncontrolling interests	(11,372		)	(11,372		)
Net cash flow provided by financing activities	197,325			251,077
NET DECREASE IN CASH AND CASH EQUIVALENTS	(4,352		)	(10,091		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,707			13,851
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,355		$	3,760

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

15

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)

	Three Months Ended June 30, 2019
	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount
Balance, April 1, 2019	71,264,947	$	178,162	$	2,721,696	$	2,816,532		$	(26,027	)	$	130,663		$	5,821,026
Net Income		—		—		150,176			—			4,874			155,050
Other comprehensive loss		—		—		—			(1,249		)	—			(1,249		)
Dividends on common stock		—		—		(165,598		)	—			—			(165,598		)
Net capital activities by noncontrolling interests		—		—		—			—			(11,372		)	(11,372		)
Balance, June 30, 2019	71,264,947	$	178,162	$	2,721,696	$	2,801,110		$	(27,276	)	$	124,165		$	5,797,857

	Three Months Ended June 30, 2018
	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount
Balance, April 1, 2018	71,264,947	$	178,162	$	2,571,696	$	2,548,591		$	(30,851	)	$	133,914		$	5,401,512
Net Income		—		—		177,825			—			4,874			182,699
Other comprehensive loss		—		—		—			(4,308		)	—			(4,308		)
Other		—		—		—			—			(1		)	(1		)
Dividends on common stock		—		—		(155,600		)	—			—			(155,600		)
Net capital activities by noncontrolling interests		—		—		—			—			(11,372		)	(11,372		)
Balance, June 30, 2018	71,264,947	$	178,162	$	2,571,696	$	2,570,816		$	(35,159	)	$	127,415		$	5,412,930

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

16

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)

	Six Months Ended June 30, 2019
	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount
Balance, January 1, 2019	71,264,947	$	178,162	$	2,721,696	$	2,788,256		$	(27,107	)	$	125,790		$	5,786,797
Net income		—		—		178,452			—			9,747			188,199
Other comprehensive loss		—		—		—			(169		)	—			(169		)
Dividends on common stock		—		—		(165,598		)	—			—			(165,598		)
Net capital activities by noncontrolling interests		—		—		—			—			(11,372		)	(11,372		)
Balance, June 30, 2019	71,264,947	$	178,162	$	2,721,696	$	2,801,110		$	(27,276	)	$	124,165		$	5,797,857

	Six Months Ended June 30, 2018
	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		—		—		187,423			—			9,747			197,170
Other comprehensive loss		—		—		—			(3,138		)	—			(3,138		)
Dividends on common stock		—		—		(155,599		)	—			—			(155,599		)
Reclassification of income tax effects related to new tax reform (a)		—		—		5,038			(5,038		)	—			—
Net capital activities by noncontrolling interests		—		—		—			—			(11,372		)	(11,372		)
Balance, June 30, 2018	71,264,947	$	178,162	$	2,571,696	$	2,570,816		$	(35,159	)	$	127,415		$	5,412,930

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

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

17

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, 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 Form 10-K.

18

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

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

	Six Months Ended June 30,
	2019		2018
Cash paid during the period for:
Income taxes, net of refunds	$	10,788	$	10,032
Interest, net of amounts capitalized	114,717		104,249
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	108,056	$	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562		—
Dividends accrued but not yet paid	82,824		77,821

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

	Six Months Ended   June 30,
	2019		2018
Cash paid during the period for:
Income taxes, net of refunds	$	35,573	$	24,689
Interest, net of amounts capitalized	107,169		98,478
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	108,056	$	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562		—
Dividends accrued but not yet paid	82,800		77,800

2.    Revenue

Sources of Revenue

We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Our retail electric services and tariff rates are regulated by the ACC. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC").

19

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Retail residential electric service	$	432,568	$	500,247	$	784,134	$	816,922
Retail non-residential electric service	395,929		435,500		728,597		778,689
Wholesale energy sales	21,991		15,392		58,443		27,481
Transmission services for others	15,157		15,489		30,406		30,334
Other sources	3,856		7,495		8,451		13,411
Total operating revenues	$	869,501	$	974,123	$	1,610,031	$	1,666,837

Revenue Activities

Our revenues are primarily derived from activities that are classified as revenues from contracts with customers. This includes sales of electricity to our regulated retail customers and wholesale and transmission activities. Our revenues from contracts with customers for the three and six months ended June 30, 2019 were $858 million and $1,578 million, and for the three and six months ended June 30, 2018 were $954 million and $1,640 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and six months ended June 30, 2019, our revenues that do not qualify as revenue from contracts with customers were $12 million and $32 million, and for the three and six months ended June 30, 2018 were $20 million and $27 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 June 30, 2019 or December 31, 2018.

3. Long-Term Debt and Liquidity Matters

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

Pinnacle West

On May 9, 2019, Pinnacle West entered into a $50 million term loan agreement that matures May 7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR') plus 0.55% per annum. At June 30, 2019, Pinnacle West had $46 million in outstanding borrowings under the agreement.

20

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 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 June 30, 2019, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $10 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, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.

At June 30, 2019, 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 June 30, 2019, APS had $377 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.

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

Debt Fair Value

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

	As of June 30, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	449,111	$	449,124	$	448,796	$	443,955
APS	4,687,768		5,119,091		4,689,436		4,789,608
Total	$	5,136,879	$	5,568,215	$	5,138,232	$	5,233,563

21

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. Regulatory Matters

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 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") 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 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;

• an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;

• rate design changes, including:

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

▪ 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.

22

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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 were consolidated, and APS requested and was granted intervention. 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. The Arizona Supreme Court denied review.

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 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. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC reconsidered the matter and adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

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 customers regarding the new rates approved in the 2017 Rate Case Decision. On April 23, 2019, the ACC Staff indicated that they would need some additional time beyond May 3, 2019 to file the requested report.

23

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

APS cannot predict the outcome or impact of the future rate case to be filed no later than October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they 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 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.

24

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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 2020 RES Implementation Plan.

On July 2, 2019, ACC Staff issued 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 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. Clean peak sales would include nuclear energy as a clean resource. 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 (“LFCR”) mechanism (see below for discussion on 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 May 7, 2019, APS filed a request for an extension to file its 2020 DSM Plan no later than December 31, 2019. On July 10, 2019, the ACC approved this request.

25

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 for 2019 and 2018 (dollars in thousands):

	Six Months Ended June 30,
	2019			2018
Beginning balance	$	37,164		$	75,637
Deferred fuel and purchased power costs — current period	16,702			50,112
Amounts charged to customers	(23,307		)	(50,851		)
Ending balance	$	30,559		$	74,898

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

On November 30, 2018, APS filed its PSA rate for the PSA year beginning February 1, 2019. That rate was $0.001658 per kWh and consisted of a forward component of $0.000536 per kWh and a historical component of $0.001122 per kWh. The 2019 PSA rate is a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019.

Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters.  In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS's rate case (the "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

26

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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.

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 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, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease from 2017 levels). On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the delay in implementation does not have an adverse effect on APS.

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-

27

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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 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 addressed 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 proposed this refund begin July 1, 2019.  APS 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.

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

28

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.45 cents per kWh on May 1, 2019, with a requested effective date of September 1, 2019.  This price also reflects the 10% annual reduction discussed above.  The ACC has not yet ruled on this request.

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

See "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

29

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. 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 and all answering briefs are due on August 21, 2019. APS and Pinnacle West cannot predict the outcome of this matter.

30

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters.

Renewable Energy Ballot Initiative

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 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 ("IRP") process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued 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 July 2, 2019, 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.  Clean peak sales would include nuclear energy as a clean resource. The ACC held stakeholder meetings and workshops on ACC Staff’s draft energy rules on July 30 and July 31, 2019 and additional stakeholder workshops will be held in August 2019. APS cannot predict the outcome of this matter.

31

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 IRP from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request. On August 1, 2019, APS filed its Preliminary IRP.

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. A hearing is set to begin on August 27, 2019 regarding APS’s application. APS cannot predict the outcome of this matter.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.  On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15.  During the moratorium on disconnections, APS cannot charge late fees and interest on amounts that are past due from customers.  Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts.  The emergency rule changes will be effective for 180 days and may be renewed once.  During that time, the ACC will begin a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rules changes.  The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. In July 2019, certain Arizona electric cooperatives filed a request for rehearing of the emergency rules for disconnections on several grounds, including that Attorney General certification is required for such rulemaking. APS currently estimates that the disconnection moratorium will result in an impact to its 2019 operating results of approximately $5 million to $10 million pre-tax depending on certain assumptions, including customer behaviors. APS is further assessing the impact to its financial statements beyond 2019, which will be affected by the results of final rulemaking related to disconnections.

Retail Electric Competition Rules

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

32

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

competition rules was held on July 30, 2019. 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.

Four Corners 

SCE-Related Matters. On December 30, 2013, 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. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million 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 from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provided for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $44 million as of June 30, 2019 and is being amortized in rates over a total of 10 years.

 As part of APS’s acquisition of SCE’s interest in 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 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 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. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. APS cannot predict the outcome of the remand proceeding.

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

33

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") 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 a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.

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 ($81 million as of June 30, 2019), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.

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

Navajo Plant

The co-owners of the Navajo Generating Station (the "Navajo Plant") and the Navajo Nation agreed 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

34

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

value of its remaining investment in the plant ($83 million as of June 30, 2019) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.    

Regulatory Assets and Liabilities 

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

	Amortization Through	June 30, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	712,907	$	—	$	733,351
Retired power plant costs	2033	28,182		153,122		28,182		167,164
Income taxes — allowance for funds used during construction ("AFUDC") equity	2049	6,457		152,388		6,457		151,467
Deferred fuel and purchased power — mark-to-market (Note 7)	2023	55,729		21,516		31,728		23,768
Deferred fuel and purchased power (b) (c)	2020	30,559		—		37,164		—
Four Corners cost deferral	2024	8,077		36,190		8,077		40,228
Income taxes — investment tax credit basis adjustment	2047	1,079		25,170		1,079		25,522
Lost fixed cost recovery (b)	2020	25,746		—		32,435		—
Palo Verde VIEs (Note 6)	2046	—		20,325		—		20,015
Deferred compensation	2036	—		37,572		—		36,523
Deferred property taxes	2027	8,569		62,072		8,569		66,356
Loss on reacquired debt	2038	1,637		12,850		1,637		13,668
Tax expense of Medicare subsidy	2024	1,235		5,772		1,235		6,176
TCA balancing account (b)	2021	5,381		3,895		3,860		772
AG-1 deferral	2022	2,787		4,110		2,654		5,819
Mead-Phoenix transmission line CIAC	2050	332		9,878		332		10,044
Coal reclamation	2026	1,546		16,250		1,546		15,607
SCR deferral	N/A	—		37,919		—		23,276
Tax expense adjuster mechanism (b)	2019	3,149		—		—		—
Ocotillo deferral	N/A	—		9,495		—		—
Other	Various	3,994		—		1,947		3,185
Total regulatory assets (d)		$	184,459	$	1,321,431	$	166,902	$	1,342,941

(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.

35

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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."

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

	Amortization Through	June 30, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)	(b)	$	68,651	$	1,178,216	$	—	$	1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)	2058	6,302		241,633		6,302		243,691
Asset retirement obligations	2057	—		359,912		—		278,585
Removal costs	(c)	50,701		153,847		39,866		177,533
Other postretirement benefits	(d)	37,821		105,214		37,864		125,903
Income taxes — deferred investment tax credit	2047	2,164		50,414		2,164		51,120
Income taxes — change in rates	2048	2,764		69,171		2,769		70,069
Spent nuclear fuel	2027	6,578		53,769		6,503		57,002
Renewable energy standard (b)	2021	40,639		4,950		44,966		20
Demand side management (b)	2021	7,191		24,146		14,604		4,123
Sundance maintenance	2030	1,641		15,495		1,278		17,228
Deferred gains on utility property	2022	3,423		5,372		4,423		6,581
Four Corners coal reclamation	2038	1,858		17,540		1,858		17,871
Tax expense adjustor mechanism (b)	2020	1,663		—		3,237		—
Other	Various	461		8,213		42		3,541
Total regulatory liabilities		$	231,857	$	2,287,892	$	165,876	$	2,325,976

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

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

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

(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.

36

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
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018			2019			2018
Service cost — benefits earned during the period	$	12,408		$	14,121		$	24,951		$	28,334		$	4,470		$	5,445		$	9,184		$	10,550
Non-service costs (credits):
Interest cost on benefit obligation	34,069			31,338			68,421			62,345			7,421			6,973			14,947			14,074
Expected return on plan assets	(43,049		)	(45,759		)	(85,942		)	(91,426		)	(9,603		)	(10,520		)	(19,206		)	(21,041		)
Amortization of:
Prior service credit	—			—			—			—			(9,455		)	(9,461		)	(18,910		)	(18,921		)
Net actuarial loss	10,053			8,259			21,292			16,041			—			—			—			—
Net periodic benefit cost (credit)	$	13,481		$	7,959		$	28,722		$	15,294		$	(7,167	)	$	(7,563	)	$	(13,985	)	$	(15,338	)
Portion of cost (credit) charged to expense	$	7,000		$	2,769		$	15,244		$	5,011		$	(5,063	)	$	(5,119	)	$	(9,880	)	$	(10,724	)

Contributions

We have made voluntary contributions of $120 million to our pension plan year-to-date in 2019. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $350 million during the 2019-2021 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 separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually 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 and six months ended June 30, 2019 of $5 million and $10 million, respectively, and for the three and six months ended June 30, 2018 of $5 million and $10 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

37

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands):

	June 30, 2019		December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	103,841	$	105,775
Equity — Noncontrolling interests	124,165		125,790

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 million beginning in 2019, 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.

38

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of June 30, 2019 and December 31, 2018, 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	June 30, 2019	December 31, 2018
Power	GWh	1,000	250
Gas	Billion cubic feet	218	218

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

 

	Financial Statement Location	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts		2019			2018			2019			2018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	$	(538	)	$	(606	)	$	(974	)	$	(1,097	)

(a) During the three and six months ended June 30, 2019 and 2018, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that a net loss of approximately $1 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.

39

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

 

	Financial Statement Location	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts		2019			2018			2019			2018
Net Loss Recognized in Income	Operating revenues	$	—		$	(341	)	$	—		$	(1,560	)
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(49,686		)	3,384			(41,516		)	(30,705		)
Total		$	(49,686	)	$	3,043		$	(41,516	)	$	(32,265	)

(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.

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 June 30, 2019 and December 31, 2018.  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.

40

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,558		$	(2,939	)	$	619		$	(160	)	$	459
Investments and other assets	76			—			76			—			76
Total assets	3,634			(2,939		)	695			(160		)	535
Current liabilities	(60,588		)	2,939			(57,649		)	(1,185		)	(58,834		)
Deferred credits and other	(21,592		)	—			(21,592		)	—			(21,592		)
Total liabilities	(82,180		)	2,939			(79,241		)	(1,185		)	(80,426		)
Total	$	(78,546	)	$	—		$	(78,546	)	$	(1,345	)	$	(79,891	)

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

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

(c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of ($160).

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
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113
Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)

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

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

(c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

41

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 June 30, 2019, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. 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 June 30, 2019 (dollars in thousands):

	June 30, 2019
Aggregate fair value of derivative instruments in a net liability position	$	82,064
Cash collateral posted	—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	80,804

(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 $95 million if our debt credit ratings were to fall below investment grade.

42

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.

APS has submitted four claims pursuant to the terms of the August 18, 2014 settlement agreement, for four separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $74.2 million for these claims (APS’s share is $21.6 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). APS submitted its most recent 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 million (APS's share is $3.0 million). On February 11, 2019 and April 10, 2019 (in response to APS's request for reconsideration), the DOE approved in total a payment of $10.2 million (APS’s share is $3.0 million). On June 7, 2019, 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 $13.9 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 $13.5 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.    

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage

43

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

insurance for a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $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 $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 June 30, 2019, our fuel and purchased power commitments have increased approximately $100 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, there have been no material changes, as of June 30, 2019, outside the normal course of business in contractual obligations from the information provided in our 2018 Form 10-K. See Note 3 for discussion regarding changes in our 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. We estimate that our costs related to this investigation and study will be approximately $2 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 RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the

44

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.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. In addition, APS and certain other parties not named in the remaining RID service provider lawsuit may be brought into the litigation via third-party complaints filed by the current direct 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 the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. 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 is 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 - 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 and details related to the resulting regulatory asset.

45

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.

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 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 the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required 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 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 EPA approval for a state-specific CCR permitting program. With respect to 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 issuing 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.

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

46

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

RCRA Subtitle D regulations for CCR, the "Phase I, Part I" revision to its CCR regulations, deferring for future action a number of other proposed changes contemplated in a March 1, 2018 proposal. For the final rule issued on July 17, 2018, 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 action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time APS cannot predict the eventual results of this rulemaking proceeding concerning boron.

On 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 to take regulatory action on remand to revise its 2015 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 certain unlined CCR surface impoundments until October 2020. In response, EPA filed a motion to remand but not vacate that deadline extension regulation. On March 13, 2019, the Court issued its ruling on the pending motions concerning the October 2020 deadline for closure initiation and granted remand without vacatur. This ruling allows the current October 2020 deadline 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 CCR surface impoundments. We cannot predict the outcome of EPA’s remand rulemaking concerning the October 2020 deadline for closure initiation.

47

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 of CCR in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS's share of incremental costs is approximately $1 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. 

APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, all such disposal units must cease operating and initiate closure by October of 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 assessment during the summer of 2019. During this assessment, APS will gather additional groundwater data, solicit input from the public, host public hearings, and select remedies. As such, this $5 million cost estimate may change based upon APS’s performance of the CCR rule’s corrective action assessment process. 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 any potential change to the cost estimate would have a material impact on our financial position, results of operations or cash flows.

Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA's 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and those regulations had been stayed pending judicial review.

The ACE are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions (e.g., the Navajo Nation) with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal, the finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs in the near future.

We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. This action will likely be subject to judicial review and the outcome of those proceedings cannot be predicted. In addition, to the extent that the ACE regulations go into effect as finalized, it is not clear how the state of Arizona or EPA Region IX (i.e., as to the Navajo Nation) will implement these regulations as applied to the Cholla and Four Corners facilities, respectively.

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

48

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Federal Agency Environmental Lawsuit Related to Four Corners

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

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit. We cannot predict the outcome of any further proceedings.

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. On April 30, 2019, EPA issued a proposed NPDES permit for Four Corners and took comment on this proposal through July 1, 2019. As part of this proposal, EPA is contemplating a December 31, 2023 compliance deadline governing Four Corners for the recently updated effluent guidelines for bottom-ash transport water. EPA currently projects that it will take final action on this permit proposal by September 30, 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.

49

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 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.

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) is approximately $10 million, which is due to 4CA at December 31, 2019.

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 June 30, 2019, standby letters of credit totaled $1.7 million and will expire in 2020. As of June 30, 2019, surety bonds expiring through 2020 totaled $17 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.

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2019. In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See "Four Corners - 4CA Matter" above for information related to this guarantee.) 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 to be immaterial.

50

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Other income:
Interest income	$	2,699		$	2,408		$	5,001		$	4,299
Debt return on Four Corners SCR (Note 4)	4,887			4,188			9,731			6,280
Debt return on Ocotillo modernization project (Note 4)	5,294			—			5,294			—
Miscellaneous	5			2			28			4
Total other income	$	12,885		$	6,598		$	20,054		$	10,583
Other expense:
Non-operating costs	$	(3,481	)	$	(3,278	)	$	(6,185	)	$	(4,924	)
Investment losses — net	(491		)	(174		)	(729		)	(350		)
Miscellaneous	(378		)	(319		)	(1,794		)	(1,726		)
Total other expense	$	(4,350	)	$	(3,771	)	$	(8,708	)	$	(7,000	)

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Other income:
Interest income	$	1,504		$	2,046		$	3,054		$	3,724
Debt return on Four Corners SCR (Note 4)	4,887			4,188			9,731			6,280
Debt return on Ocotillo modernization project (Note 4)	5,294			—			5,294			—
Miscellaneous	6			1			28			3
Total other income	$	11,691		$	6,235		$	18,107		$	10,007
Other expense:
Non-operating costs	$	(3,049	)	$	(3,057	)	$	(5,517	)	$	(4,596	)
Miscellaneous	(379		)	(315		)	(1,789		)	(1,722		)
Total other expense	$	(3,428	)	$	(3,372	)	$	(7,306	)	$	(6,318	)

51

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 and six months ended June 30, 2019 and 2018 (in thousands, except per share amounts):

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2019		2018		2019		2018
Net income attributable to common shareholders	$	144,145	$	166,738	$	162,063	$	169,959
Weighted average common shares outstanding — basic	112,337		112,115		112,381		112,067
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	314		356		353		415
Weighted average common shares outstanding — diluted	112,651		112,471		112,734		112,482
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	1.28	$	1.49	$	1.44	$	1.52
Net income attributable to common shareholders — diluted	$	1.28	$	1.48	$	1.44	$	1.51

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.

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

 Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category 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. 

52

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of 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 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 7 in the 2018 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

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

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.

53

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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 medical account. See Note 12 for additional discussion about our investment accounts.

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

Fixed Income Securities

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

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

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

54

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

55

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at June 30, 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 (Level 3)			Other				Balance at June 30, 2019
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	3,198		$	436		$	(3,099	)	(a)	$	535
Nuclear decommissioning trust:
Equity securities	5,319		—			—			6,665			(b)	11,984
U.S. commingled equity funds	—		—			—			469,375			(c)	469,375
U.S. Treasury debt	162,044		—			—			—				162,044
Corporate debt	—		115,674			—			—				115,674
Mortgage-backed securities	—		113,179			—			—				113,179
Municipal bonds	—		67,158			—			—				67,158
Other fixed income	—		11,034			—			—				11,034
Subtotal nuclear decommissioning trust	167,363		307,045			—			476,040				950,448
Other special use funds:
Equity securities	13,200		—			—			997			(b)	14,197
U.S. Treasury debt	214,712		—			—			—				214,712
Municipal bonds	—		12,649			—			—				12,649
Subtotal other special use funds	227,912		12,649			—			997				241,558
Total assets	$	395,275	$	322,892		$	436		$	473,938			$	1,192,541
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(68,992	)	$	(13,189	)	$	1,755		(a)	$	(80,426	)

(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.

56

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 2018 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 (Level 3)			Other				Balance at December 31, 2018
Assets
Cash equivalents	$	1,200	$	—		$	—		$	—			$	1,200
Risk management activities — derivative instruments:
Commodity contracts	—		3,140			2			(2,029		)	(a)	1,113
Nuclear decommissioning trust:
Equity securities	5,203		—			—			2,148			(b)	7,351
U.S. commingled equity funds	—		—			—			396,805			(c)	396,805
U.S. Treasury debt	148,173		—			—			—				148,173
Corporate debt	—		96,656			—			—				96,656
Mortgage-backed securities	—		113,115			—			—				113,115
Municipal bonds	—		79,073			—			—				79,073
Other fixed income	—		9,961			—			—				9,961
Subtotal nuclear decommissioning trust	153,376		298,805			—			398,953				851,134
Other special use funds:
Equity securities	45,130		—			—			593			(b)	45,723
U.S. Treasury debt	173,310		—			—			—				173,310
Municipal bonds	—		17,068			—			—				17,068
Subtotal other special use funds	218,440		17,068			—			593				236,101
Total assets	$	373,016	$	319,013		$	2		$	397,517			$	1,089,548
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(52,696	)	$	(8,216	)	$	875		(a)	$	(60,037	)

(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.

57

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.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).

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

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 June 30, 2019 and December 31, 2018:

	June 30, 2019 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	294	$	11,675	Discounted cash flows	Electricity forward price (per MWh)	$18.27 - $30.11	$	26.78
Natural Gas:
Forward Contracts (a)	142		1,514		Discounted cash flows	Natural gas forward price (per MMBtu)	$0.05 - $2.88	$	2.41
Total	$	436	$	13,189

(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.

58

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2019			2018			2019			2018
Net derivative balance at beginning of period	$	(5,612	)	$	(19,754	)	$	(8,214	)	$	(18,256	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(8,731		)	(989		)	(10,310		)	(3,311		)
Settlements	2,431			494			2,949			1,276
Transfers into Level 3 from Level 2	(3,096		)	(2,534		)	(3,098		)	(4,979		)
Transfers from Level 3 into Level 2	2,255			13,425			5,920			15,912
Net derivative balance at end of period	$	(12,753	)	$	(9,358	)	$	(12,753	)	$	(9,358	)
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 $53 million as of June 30, 2019 and $61 million as of December 31, 2018 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 Trust and Other Special Use Funds

We have investments in debt and equity securities held in nuclear decommissioning trust, coal reclamation escrow account, and an active union employee medical account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our 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 Trust - To fund the future costs APS expects to incur to decommission Palo Verde, APS established an external decommissioning trust 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 trust. Because of the ability of APS to recover decommissioning

59

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) in other regulatory liabilities.

Coal Reclamation Escrow Account - APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities. Activities relating to APS coal reclamation escrow account investments are included within the other special use funds in the table below.

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 and 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) in other regulatory assets. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

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 and other special use fund assets at June 30, 2019 and December 31, 2018 (dollars in thousands):  

	June 30, 2019
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trust		Other Special Use Funds		Total
Equity securities	$	474,694	$	13,200	$	487,894		$	291,295	$	—
Available for sale-fixed income securities	469,089		227,361		696,450		(a)	24,638		(696		)
Other	6,665		997		7,662		(b)	—		—
Total	$	950,448	$	241,558	$	1,192,006		$	315,933	$	(696	)

(a) As of June 30, 2019, the amortized cost basis of these available-for-sale investments is $672 million.

(b) Represents net pending securities sales and purchases.

60

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trust		Other Special Use Funds		Total
Equity securities	$	402,008	$	45,130	$	447,138		$	222,147	$	(459	)
Available for sale-fixed income securities	446,978		190,378		637,356		(a)	8,634		(6,778		)
Other	2,148		593		2,741		(b)	—		—
Total	$	851,134	$	236,101	$	1,087,235		$	230,781	$	(7,237	)

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

(b) Represents net pending securities sales and purchases.

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,
	Nuclear Decommissioning Trust			Other Special Use Funds		Total
2019
Realized gains	$	2,643		$	—	$	2,643
Realized losses	(1,700		)	—		(1,700		)
Proceeds from the sale of securities (a)	93,559			36,747		130,306
2018
Realized gains	$	1,484		$	—	$	1,484
Realized losses	(2,978		)	—		(2,978		)
Proceeds from the sale of securities (a)	122,790			2,426		125,216

(a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

61

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Six Months Ended June 30,
	Nuclear Decommissioning Trust			Other Special Use Funds		Total
2019
Realized gains	$	3,746		$	—	$	3,746
Realized losses	(3,105		)	—		(3,105		)
Proceeds from the sale of securities (a)	216,152			93,202		309,354
2018
Realized gains	$	2,298		$	1	$	2,299
Realized losses	(5,025		)	—		(5,025		)
Proceeds from the sale of securities (a)	253,246			4,981		258,227

(a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

     The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2019, is as follows (dollars in thousands):

	Nuclear Decommissioning Trust (a)		Coal Reclamation Escrow Account		Active Union Medical Trust		Total
Less than one year	$	37,373	$	22,253	$	40,219	$	99,845
1 year – 5 years	126,745		17,449		140,569		284,763
5 years – 10 years	113,989		1,807		—		115,796
Greater than 10 years	190,982		5,064		—		196,046
Total	$	469,089	$	46,573	$	180,788	$	696,450

(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.

62

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in 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. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

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 entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments are 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 this new accounting standard and the impacts it may have on our financial statements.

63

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Three Months Ended June 30
Balance March 31, 2019	$	(45,118	)		$	(1,383	)		$	(46,501	)
OCI (loss) before reclassifications	(2,422		)		—				(2,422		)
Amounts reclassified from accumulated other comprehensive loss	883			(a)	404			(b)	1,287
Balance June 30, 2019	$	(46,657	)		$	(979	)		$	(47,636	)
Balance March 31, 2018	$	(49,494	)		$	(2,847	)		$	(52,341	)
OCI (loss) before reclassifications	(5,928		)		—				(5,928		)
Amounts reclassified from accumulated other comprehensive loss	1,189			(a)	456			(b)	1,645
Balance June 30, 2018	$	(54,233	)		$	(2,391	)		$	(56,624	)

64

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Six Months Ended June 30
Balance December 31, 2018	$	(45,997	)		$	(1,711	)		$	(47,708	)
OCI (loss) before reclassifications	(2,422		)		—				(2,422		)
Amounts reclassified from accumulated other comprehensive loss	1,762			(a)	732			(b)	2,494
Balance June 30, 2019	$	(46,657	)		$	(979	)		$	(47,636	)
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)
OCI (loss) before reclassifications	(5,928		)		(96		)		(6,024		)
Amounts reclassified from accumulated other comprehensive loss	2,089			(a)	865			(b)	2,954
Reclassification of income tax effect related to tax reform	(7,954		)	(c)	(598		)	(c)	(8,552		)
Balance June 30, 2018	$	(54,233	)		$	(2,391	)		$	(56,624	)

(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.

65

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 and six months ended June 30, 2019 and 2018 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Three Months Ended June 30
Balance March 31, 2019	$	(24,644	)		$	(1,383	)		$	(26,027	)
OCI (loss) before reclassifications	(2,414		)		—				(2,414		)
Amounts reclassified from accumulated other comprehensive loss	761			(a)	404			(b)	1,165
Balance June 30, 2019	$	(26,297	)		$	(979	)		$	(27,276	)
Balance March 31, 2018	$	(28,004	)		$	(2,847	)		$	(30,851	)
OCI (loss) before reclassifications	(5,790		)		—				(5,790		)
Amounts reclassified from accumulated other comprehensive loss	1,026			(a)	456			(b)	1,482
Balance June 30, 2018	$	(32,768	)		$	(2,391	)		$	(35,159	)

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Six Months Ended June 30
Balance December 31, 2018	$	(25,396	)		$	(1,711	)		$	(27,107	)
OCI (loss) before reclassifications	(2,414		)		—				(2,414		)
Amounts reclassified from accumulated other comprehensive loss	1,513			(a)	732			(b)	2,245
Balance June 30, 2019	$	(26,297	)		$	(979	)		$	(27,276	)
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)
OCI (loss) before reclassifications	(5,790		)		(96		)		(5,886		)
Amounts reclassified from accumulated other comprehensive loss	1,883			(a)	865			(b)	2,748
Reclassification of income tax effect related to tax reform	(4,440		)	(c)	(598		)	(c)	(5,038		)
Balance June 30, 2018	$	(32,768	)		$	(2,391	)		$	(35,159	)

66

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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 period. As a result, the Company began amortization in March 2019. As of June 30, 2019, the Company has recorded $19.4 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On April 10, 2019, the Company filed a request with the ACC which addresses the amortization of depreciation related excess deferred taxes. See Note 4 for more details.

In August 2018, Treasury proposed regulations that clarify 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 proposed regulations are ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. 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. In a footnote, the JCT indicated that a technical correction bill may be necessary 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 property placed in service on or after January 1, 2018, the Company currently believes the continued availability of bonus depreciation is not “more likely than not” to be sustained upon examination. As a result, the Company has not recognized any current or deferred tax benefits related to bonus depreciation for property placed in service on or after January 1, 2018.

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

67

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

16.  Leases

We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2019 through 2050. Substantially all of our leasing activities relate to APS.

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

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.

68

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information related to our lease costs for the three and six months ended June 30, 2019 (dollars in thousands):

	Three Months Ended June 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	14,063	$	4,414	$	18,477
Variable lease cost	41,529		360		41,889
Short-term lease cost	—		1,812		1,812
Total lease cost	$	55,592	$	6,586	$	62,178

	Six Months Ended June 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	14,063	$	8,762	$	22,825
Variable lease cost	58,820		360		59,180
Short-term lease cost	—		2,665		2,665
Total lease cost	$	72,883	$	11,787	$	84,670

Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Condensed Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.

69

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information related to the maturity of our operating lease liabilities at June 30, 2019 (dollars in thousands):

	June 30, 2019
Year	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
2019 (remaining six months of 2019)	$	49,051	$	7,335	$	56,386
2020	—		12,868		12,868
2021	—		10,029		10,029
2022	—		6,988		6,988
2023	—		5,838		5,838
2024	—		3,691		3,691
Thereafter	—		38,506		38,506
Total lease commitments	49,051		85,255		134,306
Less imputed interest	294		20,411		20,705
Total lease liabilities	$	48,757	$	64,844	$	113,601

We recognize lease assets and liabilities upon lease commencement. At June 30, 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. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million over the term of the arrangements.

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

70

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	June 30, 2019
Weighted average remaining lease term	8 years
Weighted average discount rate (a)	3.84	%

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

	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	11,987

71

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 Form 10-K.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS.  APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS currently accounts for essentially all of our revenues and earnings.

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

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 June 19, 2019, EPA took final action on its proposals to repeal EPA's 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and those regulations had been stayed pending judicial review. The ACE regulations are more narrow than the CPP, and is based 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 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, 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.

72

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

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.

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 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 to the date that NTEC purchased the 7% interest) is approximately $10 million, which is due to 4CA at December 31, 2019.

Lease Extension.  APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041.  The Navajo Nation approved these amendments in March 2011.  The effectiveness of 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 issuance 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.  

73

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.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit. We cannot predict the outcome of any further proceedings.

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. On April 30, 2019, EPA issued a proposed NPDES permit for Four Corners and took comment on this proposal through July 1, 2019. As part of this proposal, EPA is contemplating a December 31, 2023 compliance deadline governing Four Corners for the recently updated effluent guidelines for bottom-ash transport water. EPA currently projects that it will take final action on this permit proposal by September 30, 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 of the Navajo Plant and the Navajo Nation agreed 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 plant (see Note 4 for details related to the resulting regulatory asset) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material.

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.  The modernization of the plant was completed on May 30, 2019 and it increased the capacity of the site by 290 MW to a total of 620 MW. (See Note 4 for details of the rate recovery in our 2017 Rate Case Decision.)

74

Transmission and Delivery.  APS continues to work closely with customers, stakeholders, and regulators to identify and plan for transmission needs that support new customers, system reliability, access to markets and clean 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.

Energy Imbalance Market. In 2015, APS and the California Independent System Operator, the operator for the majority of California's transmission grid, signed an agreement for APS to begin participation in 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, instead of the traditional one hour blocks.  APS continues to expect that 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.

Renewable Energy. 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 APS's renewable energy sources in APS's renewable portfolio that are in operation and under development as of June 30, 2019. 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)
Total APS Owned: Solar	240	—
Purchased Power Agreements:
Solar	310	—
Solar + Energy Storage	—	50
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	3	—
Total Purchased Power Agreements	626	50
Total Distributed Energy: Solar (a)	902	36	(b)
Total Renewable Portfolio	1,768	86

(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 plans to issue two Requests for Proposal ("RFP") by September 2019. The first RFP will seek competitive proposals for up to 150 megawatts of APS-owned solar resources to be in service by 2021. This solar generation will be designed with the flexibility to

75

add energy storage as a future option. A second RFP will pursue up to 250 megawatts of wind resources to be in service as soon as possible, but no later than 2022.

Energy Storage. APS deploys a number of advanced technologies on its system, including energy storage. Storage can provide capacity, improve power quality, be utilized for system regulation, integrate renewable generation, and can be used to defer certain traditional infrastructure investments. Battery 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 storage projects to evaluate the potential benefits for customers and further our understanding of how storage works with other advanced technologies and the grid. We are preparing for additional battery 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 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 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 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 is expected to begin in mid-2021, pending approval from the ACC to allow for recovery of these agreements through the PSA and the results of the McMicken investigation.  Including the battery storage projects described above, we currently plan to install at least 700 MW of additional APS-owned solar plus battery storage and stand-alone battery storage systems by the summer of 2025. We originally intended to procure the first 260 MW in 2019 (60 MW on additional AZ Sun sites and 100 MW of solar plus 100 MW of battery storage), however given the April 2019 event we are currently evaluating appropriate timing and path forward to support the overall capacity goals for our system.

Regulatory Matters

Rate Matters.  APS needs timely recovery through rates of its capital and operating expenditures 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.

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 the 2017 Settlement Agreement and filed it with the ACC. 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 4.54%). (See Note 4 for details of the 2017 Settlement Agreement.)

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.

76

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 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. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC reconsidered the matter and adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

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 customers regarding the new rates approved in the 2017 Rate Case Decision. On April 23, 2019, the ACC Staff indicated that they would need some additional time beyond May 3, 2019 to file the requested report.

On June 5, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following:

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

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

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

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

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

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

• APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see Note 4 on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

77

APS cannot predict the outcome or impact of the future rate case to be filed no later than October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they will have a material impact on its financial position, results of operations or cash flows. 

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 Demand Side Management Adjustor Charge, 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 cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table 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.

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 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

78

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 proposed this refund begin July 1, 2019. APS 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.

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. 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

79

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 and all answering briefs are due on August 21, 2019. 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 also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters.

Energy Modernization Plan. On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plans ("IRP") process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued 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 July 2, 2019, 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.  Clean peak sales would include nuclear energy as a clean resource. The ACC held stakeholder meetings and workshops on ACC Staff’s draft energy rules on July 30 and July 31, 2019 and additional stakeholder workshops will be held in August 2019. APS cannot predict the outcome of this matter.

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 IRP from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request. On August 1, 2019, APS filed its Preliminary IRP.

80

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. A hearing is set to begin on August 27, 2019 regarding APS’s application. APS cannot predict the outcome of this matter.

Residential Electric Utility Customer Service Disconnections. On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.  On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15.  During the moratorium on disconnections, APS cannot charge late fees and interest on amounts that are past due from customers.  Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts.  The emergency rule changes will be effective for 180 days and may be renewed once.  During that time, the ACC will begin a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rules changes.  The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection.  In July 2019, certain Arizona electric cooperatives filed a request for rehearing of the emergency rules for disconnections on several grounds, including that Attorney General certification is required for such rulemaking. APS currently estimates that the disconnection moratorium will result in an impact to its 2019 financial statements of approximately $5 million to $10 million depending on certain assumptions, including customer behaviors. APS is further assessing the impact to its financial statements beyond 2019, which will be affected by the results of final rulemaking related to disconnections.

Retail Electric Competition Rules. On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules and energy modernization plan proposals was held on July 30, 2019. 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.

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

81

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. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. APS cannot predict the outcome of the remand 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. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE's focus is on new growth opportunities that leverage the Company’s core expertise in the electric energy industry.  BCE’s first initiative is 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 are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

4CA. See "Four Corners - Ownership and Coal Supply Matters" above for information regarding 4CA.

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 through 2018, 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

82

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 1.8% for the six-month period ended June 30, 2019 compared with the prior-year period.  For the three years 2016 through 2018, APS’s customer growth averaged 1.6% per year. We currently project annual customer growth to be 1.5 - 2.5% for 2019 and to average in the range of 1.5 - 2.5% for 2019 through 2021 based on our assessment of improving economic conditions in Arizona.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.2% for the six-month period ended June 30, 2019 compared with the prior-year period. Improving economic conditions and customer growth were offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives.  For the three years 2016 through 2018, 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 and increase on average in the range of 1.5 - 2.5% during 2019 through 2021, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  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.

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, and responses to retail price changes.  Based on past experience, a reasonable range of 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 million.

Weather.  In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data.  Historically, extreme weather variations have resulted in annual variations in net income in excess of $25 million.  However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $15 million.

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

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

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

83

Property Taxes.  Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates.  The average property tax rate in Arizona for APS, which owns essentially all of our property, was 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. 

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

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

Income Taxes.  Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC.  In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Act was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (See Note 15 for details of the impacts on the Company as of June 30, 2019.) In APS's recent general retail rate case, the ACC approved a Tax Expense Adjustor Mechanism which will be used to pass through the income tax effects to retail customers of the Tax Act. (See Note 4 for details of the TEAM.)

RESULTS OF OPERATIONS

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

Operating Results — Three-month period ended June 30, 2019 compared with three-month period ended June 30, 2018.

Our consolidated net income attributable to common shareholders for the three months ended June 30, 2019 was $144 million, compared with consolidated net income attributable to common shareholders of $167 million for the prior-year period.  The results reflect a decrease of approximately $20 million for the regulated electricity segment primarily due to the effects of weather, partially offset by lower operations and maintenance expense.

84

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

	Three Months Ended June 30,
	2019			2018			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	626		$	701		$	(75	)
Operations and maintenance	(227		)	(263		)	36
Depreciation and amortization	(147		)	(145		)	(2		)
Taxes other than income taxes	(55		)	(53		)	(2		)
Pension and other postretirement non-service credits - net	6			12			(6		)
All other income and expenses, net	16			16			—
Interest charges, net of allowance for borrowed funds used during construction	(53		)	(54		)	1
Income taxes	(17		)	(45		)	28
Less income related to noncontrolling interests (Note 6)	(5		)	(5		)	—
Regulated electricity segment income	144			164			(20		)
All other	—			3			(3		)
Net Income Attributable to Common Shareholders	$	144		$	167		$	(23	)

85

Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $75 million lower for the three months ended June 30, 2019 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	$	(61	)	$	(15	)	$	(46	)
Refunds due to lower Federal corporate income tax rate (Note 4)	(28		)	—			(28		)
Lower renewable energy regulatory surcharges, partially offset by operations and maintenance costs	(10		)	—			(10		)
Higher transmission revenues (Note 4)	5			—			5
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	2			(1		)	3
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(12		)	(14		)	2
Miscellaneous items, net	1			2			(1		)
Total	$	(103	)	$	(28	)	$	(75	)

Operations and maintenance.  Operations and maintenance expenses decreased $36 million for the three months ended June 30, 2019 compared with the prior-year period primarily because of:

• A decrease of $10 million in fossil generation primarily due to lower planned outages and other operating costs;

• A decrease of $10 million related to costs for renewable energy and similar regulatory programs, which is partially offset by operating revenues and purchased power;

• A decrease of $9 million related to public outreach costs at the parent company primarily associated with the ballot initiative in 2018;

• A decrease of $7 million related to employee benefit costs;

• An increase of $4 million for costs related to information technology; and

• A decrease of $4 million for other miscellaneous factors.

Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $6 million lower for the three months ended June 30, 2019 compared to the prior-year period primarily due to lower market returns.

86

Income taxes.  Income taxes were $28 million lower for the three months ended June 30, 2019 compared with the prior-year period primarily due to amortization of excess deferred taxes (Note 4) and lower pretax income.

Operating Results — Six-month period ended June 30, 2019 compared with six-month period ended June 30, 2018.

Our consolidated net income attributable to common shareholders for the six months ended June 30, 2019 was $162 million, compared with consolidated net income attributable to common shareholders of $170 million for the prior-year period.  The results reflect a decrease of approximately $7 million for the regulated electricity segment primarily due to the effects of weather and lower pension and other postretirement non-service credits, partially offset by lower operations and maintenance expense.

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

	Six Months Ended June 30,
	2019			2018			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,135		$	1,190		$	(55	)
Operations and maintenance	(472		)	(524		)	52
Depreciation and amortization	(296		)	(289		)	(7		)
Taxes other than income taxes	(110		)	(106		)	(4		)
Pension and other postretirement non-service credits - net	11			25			(14		)
All other income and expenses, net	30			33			(3		)
Interest charges, net of allowance for borrowed funds used during construction	(107		)	(107		)	—
Income taxes	(19		)	(43		)	24
Less income related to noncontrolling interests (Note 6)	(10		)	(10		)	—
Regulated electricity segment income	162			169			(7		)
All other	—			1			(1		)
Net Income Attributable to Common Shareholders	$	162		$	170		$	(8	)

87

Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $55 million lower for the six months ended June 30, 2019 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)
Refunds due to lower Federal corporate income tax rate (Note 4)	$	(32	)	$	—		$	(32	)
Effects of weather	(33		)	(8		)	(25		)
Lower renewable energy regulatory surcharges and higher purchased power, partially offset by operations and maintenance costs	(15		)	1			(16		)
Lower transmission revenues (Note 4)	(3		)	—			(3		)
Change in residential rate design and seasonal rates (a)	13			—			13
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	6			1			5
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	4			4			—
Miscellaneous items, net	6			3			3
Total	$	(54	)	$	1		$	(55	)

(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.

Operations and maintenance.  Operations and maintenance expenses decreased $52 million for the six months ended June 30, 2019 compared with the prior-year period primarily because of:

• A decrease of $18 million in fossil generation primarily due to lower planned outages and other operating costs;

• A decrease of $17 million related to costs for renewable energy and similar regulatory programs, which is partially offset by operating revenues and purchased power;

• A decrease of $11 million related to public outreach costs at the parent company primarily associated with the ballot initiative in 2018;

• A decrease of $8 million in transmission, distribution and customer service costs;

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

88

• A decrease of $4 million for other miscellaneous factors.

Depreciation and amortization.  Depreciation and amortization expenses were $7 million higher for the six months ended June 30, 2019 compared with the prior-year period primarily related to increased plant in service.

Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $13 million lower for the six months ended June 30, 2019 compared to the prior-year period primarily due to lower market returns.

Income taxes.  Income taxes were $24 million lower for the six months ended June 30, 2019 compared with the prior-year period primarily due to amortization of excess deferred taxes (Note 4) and lower pretax income.

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 June 30, 2019, APS’s common equity ratio, as defined, was 54%.  Its total shareholder equity was approximately $5.7 billion, and total capitalization was approximately $10.5 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.2 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).

89

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the six months ended June 30, 2019 and 2018 (dollars in millions):

Pinnacle West Consolidated

	Six Months Ended June 30,						Net
	2019			2018			Change
Net cash flow provided by operating activities	$	346		$	396		$	(50	)
Net cash flow used for investing activities	(528		)	(679		)	151
Net cash flow provided by financing activities	178			273			(95		)
Net change in cash and cash equivalents	$	(4	)	$	(10	)	$	6

Arizona Public Service Company

	Six Months Ended June 30,						Net
	2019			2018			Change
Net cash flow provided by operating activities	$	335		$	406		$	(71	)
Net cash flow used for investing activities	(536		)	(667		)	131
Net cash flow provided by financing activities	197			251			(54		)
Net change in cash and cash equivalents	$	(4	)	$	(10	)	$	6

Operating Cash Flows

Six-month period ended June 30, 2019 compared with six-month period ended June 30, 2018.  Pinnacle West’s consolidated net cash provided by operating activities was $346 million in 2019, compared to $396 million in 2018, a decrease of $50 million in net cash provided by operating activities primarily due to higher payments for operations and maintenance, property taxes, pension contributions and interest, partially offset by lower fuel and purchased power costs and higher customer advances.

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 112% funded as of January 1, 2019 and 117% as of January 1, 2018.  Under GAAP, the qualified pension plan was 90% funded as of January 1, 2019 and 95% funded as of January 1, 2018. 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 made voluntary contributions of $120 million to our pension plan year-to-date in 2019. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $350 million during the 2019-2021 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.

90

Investing Cash Flows

Six-month period ended June 30, 2019 compared with six-month period ended June 30, 2018.  Pinnacle West’s consolidated net cash used for investing activities was $528 million in 2019, compared to $679 million in 2018, a decrease of $151 million primarily related to decreased 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,
	2019		2020		2021
APS
Generation:
Clean:
Nuclear Fuel	$	71	$	64	$	64
Nuclear Generation	70		68		67
Renewables (a)	20		21		3
New Resources (b)	3		93		371
Environmental	26		57		53
New Gas Generation	16		—		—
Other Generation	172		142		114
Distribution	535		455		443
Transmission	189		198		206
Other (c)	135		168		151
Total APS	$	1,237	$	1,266	$	1,472

(a) Primarily APS Solar Communities program

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

(c) Primarily information systems and facilities projects

 Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and projected future new resources. 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, 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.

91

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

Six-month period ended June 30, 2019 compared with six-month period ended June 30, 2018.  Pinnacle West’s consolidated net cash provided by financing activities was $178 million in 2019, compared to $273 million in 2018, a decrease of $95 million in net cash provided.  The decrease in net cash provided by financing activities includes a net decrease in short term borrowings of $165 million and higher long-term debt repayments of $418 million, which was partially offset by $497 million in higher 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 June 19, 2019, the Pinnacle West Board of Directors declared a dividend of $0.7375 per share of common stock, payable on September 3, 2019 to shareholders of record on August 1, 2019.

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, 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.

On May 9, 2019, Pinnacle West entered into a $50 million term loan agreement that matures May 7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility. Borrowings under the agreement bear interest at LIBOR plus 0.55% per annum. At June 30, 2019, Pinnacle West had $46 million in outstanding borrowings under the agreement.

At June 30, 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 June 30, 2019, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $10 million of commercial paper borrowings.

At June 30, 2019, 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 June 30, 2019, APS had $377 million of

92

commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.

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

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

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.  Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At June 30, 2019, the ratio was approximately 52% for Pinnacle West and 47% 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).

93

Credit Ratings

The ratings of securities of Pinnacle West and APS as of August 1, 2019 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	Stable	Negative
APS
Corporate credit rating	A2	A-	A-
Senior unsecured	A2	A-	A
Commercial paper	P-1	A-2	F2
Outlook	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

As of June 30, 2019, our fuel and purchased power commitments have increased approximately $100 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, there have been no material changes, as of June 30, 2019, outside the normal course of business in contractual obligations from the information provided in our 2018 Form 10-K. See Note 3 for discussion regarding changes in our long-term debt obligations.

94

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

OTHER ACCOUNTING MATTERS

On January 1, 2019 we adopted new lease accounting guidance, ASU 2016-02, and related amendments. See Note 16. On July 1, 2019 we early adopted, ASU 2018-15, relating to accounting for cloud computing implementation costs. We are currently evaluating the impacts of the pending adoption of ASU 2016-13, and related amendments, pertaining to the measurement of credit losses of financial instruments. This new credit loss standard is effective for us on January 1, 2020. 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.

95

The following table shows the net pretax changes in mark-to-market of our derivative positions for the six months ended June 30, 2019 and 2018 (dollars in millions):

	Six Months Ended June 30,
	2019			2018
Mark-to-market of net positions at beginning of period	$	(59	)	$	(91	)
Increase in regulatory asset/liability	(22		)	(1		)
Recognized in OCI:
Mark-to-market losses realized during the period	1			1
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(80	)	$	(91	)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at June 30, 2019 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 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
Observable prices provided by other external sources	$	(33	)	$	(19	)	$	(9	)	$	(5	)	$	—		$	(66	)
Prices based on unobservable inputs	(10		)	(3		)	—			—			(1		)	(14		)
Total by maturity	$	(43	)	$	(22	)	$	(9	)	$	(5	)	$	(1	)	$	(80	)

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 June 30, 2019 and December 31, 2018 (dollars in millions):

	June 30, 2019					December 31, 2018
	Gain (Loss)					Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) (a)
Electricity	$	4	$	(4	)	$	1	$	(1	)
Natural gas	41		(41		)	44		(44		)
Total	$	45	$	(45	)	$	45	$	(45	)

(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.

96

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 June 30, 2019.  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 June 30, 2019.  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 June 30, 2019 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

97

PART II — OTHER INFORMATION

Item 1.                   LEGAL PROCEEDINGS

See "Business of Arizona Public Service Company — Environmental Matters" in Item 1 of the 2018 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 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 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. 

Item 5.                OTHER INFORMATION

None.

98

Item 6.                 EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
10.1	Pinnacle West	364-Day Term Loan, dated as of May 9, 2019, among Pinnacle West, as Borrower,  PNC Bank, National Association, as Agent and Citibank, as Syndication Agent
31.1	Pinnacle West	Certificate of Donald E. Brandt, 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 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, 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 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	The cover page from this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in Inline XBRL

________________________________

*Furnished herewith as an Exhibit.

99

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	3.1 to Pinnacle West/APS February 28, 2017 Form 8-K Report, File Nos. 1-8962 and 1-4473	2/28/2017
3.2	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/7/2008
3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form  8-K Report, File No. 1-4473	9/29/1993
3.4	APS	Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012	3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473	5/22/2012
3.5	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008	3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473	2/20/2009

_______________________________

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

100

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:	August 8, 2019	By:	/s/ James R. Hatfield
			James R. Hatfield
			Executive Vice President and
			Chief Financial Officer
			(Principal Financial Officer and
			Officer Duly Authorized to sign this Report)
		ARIZONA PUBLIC SERVICE COMPANY
		(Registrant)
Dated:	August 8, 2019	By:	/s/ James R. Hatfield
			James R. Hatfield
			Executive Vice President and
			Chief Financial Officer
			(Principal Financial Officer and
			Officer Duly Authorized to sign this Report)

101

EX-10.1

U.S. $50,000,000

364-DAY TERM LOAN AGREEMENT

Dated as of May 9, 2019

among

PINNACLE WEST CAPITAL CORPORATION,

asBorrower,

THE LENDERS PARTY HERETO,

PNC BANK, NATIONAL ASSOCIATION,

asAgent,

CITIBANK, N.A.

asSyndicationAgent,

_______________________________________________________________________

PNC CAPITAL MARKETS LLC,

and

CITIBANK, N.A.

asJointLeadArrangersandasJointBookrunners

TABLE OF CONTENTS

ARTICLE I DEFINITIONS AND ACCOUNTING TERMS 1

Section 1.01 Certain Defined Terms    1

Section 1.02 Other Interpretive Provisions    15

Section 1.03 Accounting Terms    16

Section 1.04 Rounding    16

Section 1.05 Times of Day    16

ARTICLE II AMOUNTS AND TERMS OF THE LOANS 17

Section 2.01 The Loans    17

Section 2.02 Making the Loans    17

Section 2.03 Fees    18

Section 2.04 Repayment of Loans    18

Section 2.05 Interest on Loans    18

Section 2.06 Interest Rate Determination.    20

Section 2.07 Optional Conversion of Loans    21

Section 2.08 Prepayments of Loans    22

Section 2.09 Increased Costs.    22

Section 2.10 Illegality    24

Section 2.11 Payments and Computations    24

Section 2.12 Taxes    25

Section 2.13 Sharing of Payments, Etc.    29

Section 2.14 Evidence of Debt    30

Section 2.15 Use of Proceeds    31

Section 2.16 Affected Lenders    31

Section 2.17 Replacement of Lenders    31

ARTICLE III CONDITIONS PRECEDENT 32

Section 3.01 Conditions Precedent to Effectiveness    32

Section 3.02 Determinations Under Section 3.01    33

ARTICLE IV REPRESENTATIONS AND WARRANTIES 34

Section 4.01 Representations and Warranties of the Borrower    34

ARTICLE V COVENANTS OF THE BORROWER 38

Section 5.01 Affirmative Covenants    38

Section 5.02 Negative Covenants    42

Section 5.03 Financial Covenant    43

ARTICLE VI EVENTS OF DEFAULT 43

i

Section 6.01 Events of Default    43

ARTICLE VII THE AGENT 45

Section 7.01 Appointment and Authority    45

Section 7.02 Rights as a Lender    45

Section 7.03 Exculpatory Provisions    46

Section 7.04 Reliance by Agent    46

Section 7.05 Delegation of Duties    47

Section 7.06 Resignation of Agent    47

Section 7.07 Non-Reliance on Agent and Other Lenders    48

Section 7.08 No Other Duties, Etc.    48

Section 7.09 Certain ERISA Matters    48

ARTICLE VIII MISCELLANEOUS 50

Section 8.01 Amendments, Etc.    50

Section 8.02 Notices, Etc.    51

Section 8.03 No Waiver; Cumulative Remedies; Enforcement    53

Section 8.04 Costs and Expenses; Indemnity; Damage Waiver    53

Section 8.05 Right of Set-off    55

Section 8.06 Effectiveness; Binding Effect    56

Section 8.07 Successors and Assigns    56

Section 8.08 Confidentiality    59

Section 8.09 Governing Law    60

Section 8.10 Counterparts; Integration    60

Section 8.11 Jurisdiction, Etc.    60

Section 8.12 Payments Set Aside    61

Section 8.13 Patriot Act and Beneficial Ownership Regulation    61

Section 8.14 Waiver of Jury Trial    61

Section 8.15 No Advisory or Fiduciary Responsibility    61

Section 8.16 Survival of Representations and Warranties    62

Section 8.17 Severability    62

Section 8.18 Acknowledgement and Consent to Bail-In of EEA Financial Institutions    62

Schedules

Schedule 1.01         Commitments and Ratable Shares

Schedule 4.01(j)     Subsidiaries

Schedule 4.01(k)     Existing Indebtedness

Schedule 8.02         Certain Addresses for Notices

Exhibits

Exhibit A         Form of Note

Exhibit B         Form of Notice of Initial Borrowing

ii

Exhibit C         Form of Assignment and Assumption

Exhibit D        Form of Interest Election Request

iii

364-DAY TERM LOAN AGREEMENT
Dated as of May 9, 2019

PINNACLE WEST CAPITAL CORPORATION, an Arizona corporation (the “Borrower”), the banks, financial institutions and other institutional lenders (the “Initial Lenders”) listed on the signature pages hereof, the other Lenders (as hereinafter defined), CITIBANK, N.A. as Syndication Agent, and PNC BANK, NATIONAL ASSOCIATION, as Agent for the Lenders, agree as follows:

The Borrower has requested that the Lenders provide a $50,000,000 term loan facility for the purposes set forth herein, and the Lenders are willing to do so on the terms and conditions set forth herein.

In consideration of the mutual covenants and agreements herein contained, the parties hereto covenant and agree as follows:

Article IDEFINITIONS AND ACCOUNTING TERMS

Section 1.01Certain Defined Terms. As used in this Agreement, the following terms shall have the following meanings:

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Agent.

“Affected Lender” means any Lender, as reasonably determined by the Agent or, if the Agent is the Affected Lender, by the Required Lenders, that (a) has failed to (i) fund all or any portion of its Loans unless such Lender notifies the Agent and the Borrower in writing that such failure is the result of such Lender’s determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable default, shall be specifically identified in writing) has not been satisfied or (ii) pay to the Agent or any other Lender any other amount required to be paid by it under this Agreement, (b) has notified the Borrower, the Agent or any Lender in writing of its intention not to fund a Loan or any of its other funding obligations under this Agreement, (c) has failed, within three Business Days after written request by the Agent, or, if the Agent is the Affected Lender, by the Required Lenders, to confirm that it will comply with the terms of this Agreement relating to its obligations to fund a Loan, (d) shall (or whose parent company shall) generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or shall have had any proceeding instituted by or against such Lender (or its parent company) seeking to adjudicate it as bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or custodian for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not

instituted by it), either such proceeding shall remain undismissed or unstayed for a period of 30 days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or custodian for, it or for any substantial part of its property) shall occur, or shall take (or whose parent company shall take) any corporate action to authorize any of the actions set forth above in this subsection (d) or (e) has become the subject of a Bail-In Action, provided that a Lender shall not be deemed to be an Affected Lender solely by virtue of the ownership or acquisition of any equity interest in any Lender or any Person that directly or indirectly controls such Lender by a Governmental Authority or an instrumentality thereof.

“Affiliate” means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person. For purposes of this definition, the term “control” (including the terms “controlling”, “controlled by” and “under common control with”) of a Person means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of Voting Stock, by contract or otherwise.

“Agent” means PNC Bank, National Association (including its branches and Affiliates as may be required to administer its duties) in its capacity as administrative agent under any of the Loan Documents, or any successor administrative agent.

“Agent’s Account” means the account of the Agent designated as such by the Agent to the Lenders and the Borrower from time to time.

“Agent’s Office” means the Agent’s address specified in Section 8.02(a) and, as appropriate, the Agent’s Account, or such other address or account as the Agent may from time to time notify the Borrower and the Lenders.

“Agreement” means this 364-Day Term Loan Agreement, dated as of May 9, 2019, among the Borrower, the Lenders named herein and from time to time party hereto, the Syndication Agent and the Agent, together with all schedules and exhibits hereto.

“Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Borrower or its Subsidiaries from time to time concerning or relating to bribery, corruption or money laundering.

“Applicable Lending Office” means, with respect to each Lender, such Lender’s Domestic Lending Office in the case of a Base Rate Loan and such Lender’s Eurodollar Lending Office in the case of a Eurodollar Rate Loan.

“Applicable Rate” means (i) if a Base Rate Loan, 0.000% per annum and (ii) if a Eurodollar Rate Loan, 0.550% per annum.

2

“Approved Fund” means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of any entity that administers or manages a Lender.

“APS” means Arizona Public Service Company, an Arizona corporation.

“Arrangers” means each of PNC Capital Markets LLC and Citibank, N.A., together with their successors and assigns.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an Eligible Assignee, and accepted by the Agent, in substantially the form of Exhibit C hereto.

“Authorized Officer” means the chairman of the board, chief executive officer, chief operating officer, chief financial officer, chief accounting officer, president, any vice president, treasurer, controller or any assistant treasurer of the Borrower.

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

“Base Rate” means for any day a fluctuating rate per annum equal to the highest of:

(a)    the Prime Rate;

(b)    the Federal Funds Rate plus 0.50%; and

(c)    an amount equal to (i) the Eurodollar Rate for a one month Interest Period on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus (ii) 1%; provided that, if the Base Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“Base Rate Loan” means a Loan that bears interest as provided in Section 2.05(a)(i).

“Beneficial Ownership Certification” means a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation in form and substance acceptable to the Agent in its discretion (as amended or modified by the Agent from time to time in its sole discretion).

“Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.

“Benefit Plan” means any of (a) an “employee benefit plan” (as defined in ERISA) that is subject to Title I of ERISA, (b) a “plan” as defined in Section 4975 of the Internal Revenue Code or (c) any Person whose assets include (for purposes of ERISA Section 3(42) or otherwise for

3

purposes of Title I of ERISA or Section 4975 of the Internal Revenue Code) the assets of any such “employee benefit plan” or “plan”.

“Borrower” has the meaning given to such term in the introductory paragraph hereof.

“Borrower Information” has the meaning specified in Section 8.08.

“Borrowing” means Loans of the same Type that are made, Converted or continued on the same date and, in the case of Eurodollar Rate Loans, as to which a single Interest Period is in effect.

“Business Day” means a day of the year on which banks are not required or authorized by Law to close in New York, New York or Phoenix, Arizona and, if the applicable Business Day relates to any Loan in which interest is calculated by reference to the Eurodollar Rate, on which dealings are carried on in the London interbank market.

“Capital Lease Obligations” means, subject to Section 1.03, as to any Person, the obligations of such Person to pay rent or other amounts under a lease of (or other agreement conveying the right to use) real and/or personal property, which obligations are required to be classified and accounted for as a capital lease or a finance lease on the balance sheet of such Person under GAAP and, for the purposes of this Agreement, the amount of such obligations shall be the capitalized amount thereof, determined in accordance with GAAP.

“Change in Law” means the occurrence, after the date of this Agreement, of any of the following: (a) the adoption of any Law, (b) any change in any Law or in the administration, interpretation or application thereof by any Governmental Authority or (c) the making or issuance of any request, rules, guideline, requirement or directive (whether or not having the force of law) by any Governmental Authority; provided, however, that notwithstanding anything herein to the contrary, (i) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines, requirements and directives thereunder, issued in connection therewith or in implementation thereof, and (ii) all requests, rules, guidelines, requirements and directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed a “Change in Law” regardless of the date enacted, adopted, issued or implemented.

“Commitment” means, as to any Lender, its obligation to make a Loan to the Borrower pursuant to Section 2.01, in an aggregate principal amount not to exceed the amount set forth opposite such Lender’s name on Schedule 1.01 under the column “Commitment”. “Commitments” means the total of the Lenders’ Commitments hereunder. The Commitments shall in no event exceed $50,000,000.

“Consolidated” refers to the consolidation of accounts in accordance with GAAP.

“Consolidated Indebtedness” means, at any date, the Indebtedness of the Borrower and its Consolidated Subsidiaries determined on a Consolidated basis as of such date; provided, however, that so long as the creditors of the VIE Lessor Trusts have no recourse to the assets of APS,

4

“Consolidated Indebtedness” shall not include any Indebtedness or other obligations of the VIE Lessor Trusts.

“Consolidated Net Worth” means, at any date, the sum as of such date of (a) the par value (or value stated on the books of the Borrower) of all classes of capital stock of the Borrower and its Subsidiaries, excluding the Borrower’s capital stock owned by the Borrower and/or its Subsidiaries, plus (or minus in the case of a surplus deficit) (b) the amount of the Consolidated surplus, whether capital or earned, of the Borrower, determined in accordance with GAAP as of the end of the most recent calendar month (excluding the effect on the Borrower’s accumulated other comprehensive income/loss of the ongoing application of Accounting Standards Codification Topic 815).

“Consolidated Subsidiary” means, at any date, any Subsidiary or other entity the accounts of which would be Consolidated with those of the Borrower on its Consolidated financial statements if such financial statements were prepared as of such date; provided that in no event will Consolidated Subsidiaries include the VIE Lessor Trusts.

“Controlled Affiliate” has the meaning specified in Section 4.01(n).

“Convert”, “Conversion”, “Converted” and “Converting” each refers to a conversion of Loans of one Type into Loans of the other Type pursuant to Section 2.06, Section 2.07 or Section 2.10.

“Debtor Relief Laws” means the Bankruptcy Code of the United States of America, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief Laws of the United States of America or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.

“Default” means any Event of Default or any event that would constitute an Event of Default but for the requirement that notice be given or time elapse or both.

“Dollars” or “$” means dollars of the United States of America.

“Domestic Lending Office” means, with respect to any Lender, the office of such Lender described as such in such Lender’s Administrative Questionnaire, or such other office or offices as a Lender may from time to time notify the Borrower and the Agent.

“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent;

5

“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Effective Date” has the meaning specified in Section 3.01.

“Eligible Assignee” means any Person that meets the requirements to be an assignee under Section 8.07(b)(iii) and Section 8.07(b)(v), (subject to such consents, if any, as may be required under Section 8.07(b)(iii)).

“Environmental Action” means any action, suit, demand, demand letter, claim, notice of non-compliance or violation, notice of liability or potential liability, investigation, proceeding, consent order or consent agreement relating in any way to any Environmental Law, Environmental Permit or Hazardous Materials or arising from alleged injury or threat of injury to health, safety or the environment and relating to any Environmental Law, including, without limitation, (a) by any Governmental Authority for enforcement, cleanup, removal, response, remedial or other actions or damages and (b) by any Governmental Authority or any third party for damages, contribution, indemnification, cost recovery, compensation or injunctive relief.

“Environmental Law” means any federal, state, local or foreign statute, law, ordinance, rule, regulation, code, order, judgment, decree or judicial or agency interpretation, policy or guidance relating to pollution or protection of the environment, natural resources or, to the extent relating to exposure to Hazardous Materials, human health or safety, including, without limitation, those relating to the use, handling, transportation, treatment, storage, disposal, release or discharge of Hazardous Materials.

“Environmental Permit” means any permit, approval, identification number, license or other authorization required under any Environmental Law.

“ERISA” means the Employee Retirement Income Security Act of 1974.

“ERISA Affiliate” means any trade or business (whether or not incorporated) under common control with the Borrower within the meaning of Section 414(b) or (c) of the Internal Revenue Code (and Sections 414(m) and (o) of the Internal Revenue Code for purposes of provisions relating to Section 412 of the Internal Revenue Code).

“ERISA Event” means (a) a Reportable Event with respect to a Pension Plan; (b) a withdrawal by the Borrower or any ERISA Affiliate from a Pension Plan subject to Section 4063 of ERISA during a plan year in which it was a substantial employer (as defined in Section 4001(a)(2) of ERISA) or a cessation of operations that is treated as such a withdrawal under Section 4062(e) of ERISA; (c) a complete or partial withdrawal by the Borrower or any ERISA Affiliate from a Multiemployer Plan or notification that a Multiemployer Plan is in reorganization; (d) the filing of a notice of intent to terminate, the treatment of a Plan amendment as a termination under Section

6

4041 or 4041A of ERISA, or the commencement of proceedings by the PBGC to terminate a Pension Plan or Multiemployer Plan; (e) an event or condition which constitutes grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Pension Plan or Multiemployer Plan; or (f) the imposition of any liability under Title IV of ERISA, other than for PBGC premiums due but not delinquent under Section 4007 of ERISA, upon the Borrower or any ERISA Affiliate.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Eurodollar Lending Office” means, with respect to any Lender, the office of such Lender described as such in such Lender’s Administrative Questionnaire, or such other office or offices as a Lender may from time to time notify the Borrower and the Agent.

“Eurodollar Rate” means for any Interest Period as to any Eurodollar Rate Loan, (i) the rate per annum determined by the Agent to be the offered rate which appears on the page of the Reuters Screen which displays the London interbank offered rate administered by ICE Benchmark Administration Limited (such page currently being the LIBOR01 page) (the “LIBO Rate”) for deposits (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period in Dollars, determined as of approximately 11:00 a.m. (London, England time), two Business Days prior to the commencement of such Interest Period, or (ii) in the event the rate referenced in the preceding clause (i) does not appear on such page or service or if such page or service shall cease to be available, the rate determined by the Agent to be the offered rate on such other page or other service which displays the LIBO Rate for deposits (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period in Dollars, determined as of approximately 11:00 a.m. (London, England time) two Business Days prior to the commencement of such Interest Period; provided that if LIBO Rates are quoted under either of the preceding clauses (i) or (ii), but there is no such quotation for the Interest Period elected, the LIBO Rate shall be equal to the Interpolated Rate; and provided, further, that if any such rate determined pursuant to this definition is below zero, the Eurodollar Rate will be deemed to be zero.

“Eurodollar Rate Loan” means a Loan that bears interest at a rate based on the Eurodollar Rate (other than a Base Rate Loan bearing interest at a rate based on the Eurodollar Rate).

“Events of Default” has the meaning specified in Section 6.01.

“Excluded Taxes” means, with respect to the Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of the Borrower hereunder, (a) Taxes imposed on or measured by its overall net income (however denominated), and franchise Taxes imposed on it (in lieu of net income Taxes), by the United States of America or the jurisdiction (or any political subdivision thereof) under the Laws of which such recipient is organized or does business or in which its principal office is located or, in the case of any Lender, in which its Applicable Lending Office is located, (b) any branch profits Taxes imposed by the United States of America or any similar Tax imposed by any other jurisdiction in which the Borrower is located, (c) any backup withholding Tax that is required by the Internal Revenue Code to be withheld from amounts payable to a Lender that has failed to comply with clause (A) of Section 2.12(e)(ii), (d) in the case

7

of a Foreign Lender (other than as agreed to between any assignee and the Borrower pursuant to a request by the Borrower under Section 2.17), any United States of America withholding Tax that (i) is required to be imposed on amounts payable to such Foreign Lender pursuant to the Laws in force at the time such Foreign Lender becomes a party hereto (or designates a new Applicable Lending Office) or (ii) is attributable to such Foreign Lender’s failure or inability (other than as a result of a Change in Law) to comply with clause (B) of Section 2.12(e)(ii), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new Applicable Lending Office (or assignment), to receive additional amounts from the Borrower with respect to such withholding Tax pursuant to Section 2.12(a)(i) or (ii); and (e) any United States withholding Tax imposed by FATCA.

“Executive Order” has the meaning specified in Section 4.01 (p).

“Existing Credit Agreement” means that certain 364-Day Credit Agreement, dated as of June 28, 2018 by and among the Borrower, the lenders party thereto and MUFG Bank, Ltd., as agent.

“FATCA” means Sections 1471 through 1474 of the Internal Revenue Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreement entered into pursuant to Section 1471(b)(1) of the Internal Revenue Code.

“Federal Funds Rate” means, for any day, the rate per annum equal to the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System on such day, as published by the Federal Reserve Bank of New York on the Business Day next succeeding such day; provided that (a) if such day is not a Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day, and (b) if no such rate is so published on such next succeeding Business Day, the Federal Funds Rate for such day shall be the average rate (rounded upward, if necessary, to a whole multiple of 1/100 of 1%) charged to the Agent on such day on such transactions as determined by the Agent; provided further, that if the Federal Funds Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“Fee Letter” means that certain Fee Letter dated as of May 9, 2019, between the Agent and the Borrower, as amended, modified, restated or supplemented from time to time.

“Foreign Lender” means any Lender that is organized under the Laws of a jurisdiction other than that in which the Borrower is resident for tax purposes. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“Four Corners Acquisition” means the acquisition by APS from Southern California Edison Company (“SCE”) of SCE’s interests in Units 4 and 5 of the Four Corners Power Plant near Farmington, New Mexico, pursuant to the Purchase and Sale Agreement, dated as of November 8, 2010, by and between SCE and APS.

8

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” has the meaning specified in Section 1.03.

“Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank) and any group or body charged with setting financial accounting or regulatory capital rules or standards (including, without limitation, the Financial Accounting Standards Board, the Bank for International Settlements or the Basel Committee on Banking Supervision or any successor or similar authority to any of the foregoing).

“Government Official” shall mean (a) an executive, official, employee or agent of a governmental department, agency or instrumentality, (b) a director, officer, employee or agent of a wholly or partially government owned or controlled company or business, (c) a political party or official thereof, or candidate for political office or (d) an executive, official, employee or agent of a public international organization (e.g., the International Monetary Fund or the World Bank).

“Guarantee” means as to any Person, any obligation, contingent or otherwise, of such Person directly or indirectly guaranteeing any Indebtedness of any other Person or in any manner providing for the payment of any Indebtedness of any other Person or otherwise protecting the holder of such Indebtedness against loss (whether by virtue of partnership arrangements, agreements to keep well, to purchase assets, goods, securities or services, or to take-or-pay or otherwise), provided that the term “Guarantee” shall not include endorsements for collection or deposit in the ordinary course of business. The term “Guarantee” used as a verb has a corresponding meaning.

“Hazardous Materials” means (a) petroleum and petroleum products, byproducts or breakdown products, radioactive materials, asbestos-containing materials, polychlorinated biphenyls and radon gas and (b) any other chemicals, materials or substances designated, classified or regulated as hazardous or toxic or as a pollutant or contaminant under any Environmental Law.

“Hedge Agreement” means any interest rate swap, cap or collar agreement, interest rate future or option contract, currency swap agreement, currency future or option contract, commodity future or option contract, commodity forward contract or other similar agreement.

“Indebtedness” means as to any Person at any date (without duplication): (a) indebtedness created, issued, incurred or assumed by such Person for borrowed money or evidenced by bonds, debentures, notes or similar instruments; (b) all obligations of such Person to pay the deferred purchase price of property or services, excluding, however, trade accounts payable (other than for borrowed money) arising in, and accrued expenses incurred in, the ordinary course of business of such Person so long as such trade accounts payable are paid within 180 days of the date incurred (unless subject to a good faith dispute); (c) all Indebtedness secured by a Lien on any asset of such

9

Person, to the extent such Indebtedness has been assumed by, or is a recourse obligation of, such Person; (d) all Guarantees by such Person; (e) all Capital Lease Obligationsof such Person; and (f) the amount of all reimbursement obligations of such Person (whether contingent or otherwise) in respect of letters of credit, bankers’ acceptances, surety or other bonds and similar instruments in support of Indebtedness; provided that Indebtedness, in accordance with Section 1.03, shall exclude any obligation or liability arising from the application or interpretation of ASC Topic 840 or 842 or any related, similar or successor pronouncement, guideline, publication or rule, or which is otherwise excluded in accordance with Section 1.03.

“Indemnified Taxes” means Taxes other than Excluded Taxes.

“Ineligible Institution” means (a) a natural person, (b) an Affected Lender or any of its Subsidiaries, (c) the Borrower, any of its Subsidiaries or any of its Affiliates, (d) a company, investment vehicle or trust for, or owned and operated for the primary benefit of, a natural person or relative(s) thereof, or (e) any Person who, upon becoming a Lender hereunder, would constitute an Affected Lender or a Subsidiary thereof.

“Initial Borrowing” means the Loans made by the Initial Lenders on the Effective Date pursuant to Section 2.01 hereof.

“Initial Lenders” has the meaning given to such term in the introductory paragraph hereof.

“Interest Election Request” means a written request by the Borrower to Convert or continue a Borrowing in accordance with the definition of “Interest Period” contained in this Section 1.01 and/or Section 2.07, as applicable, in each case in substantially the form of Exhibit D hereto.

“Interest Period” means, for each Eurodollar Rate Loan comprising part of the same Borrowing, the period commencing on (i) the date such Eurodollar Rate Loan is disbursed, (ii) the date of the Conversion of any Base Rate Loan into such Eurodollar Rate Loan or (iii) the effective date of the most recent continuation of such Eurodollar Rate Loan, as the case may be, and ending on the last day of the period selected by the Borrower pursuant to the provisions below and, thereafter, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by the Borrower pursuant to the provisions below. The duration of each such Interest Period shall be one week or one, two, three or six months, as the Borrower may, upon notice (in the form of an Interest Election Request duly completed and executed by the Borrower) received by the Agent not later than 12:00 noon on the third Business Day prior to the first day of such Interest Period, select; provided, however, that:

(a)    the Borrower may not select any Interest Period that ends after the Maturity Date;

(b)    Interest Periods commencing on the same date for Eurodollar Rate Loans comprising part of the same Borrowing shall be of the same duration;

(c)    whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur

10

on the next succeeding Business Day, provided, however, that, if such extension would cause the last day of such Interest Period (other than a one week Interest Period) to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day; and

(d)    other than with respect to a one week Interest Period, whenever the first day of any Interest Period occurs on a day of an initial calendar month for which there is no numerically corresponding day in the calendar month that succeeds such initial calendar month by the number of months equal to the number of months in such Interest Period, such Interest Period shall end on the last Business Day of such succeeding calendar month.

“Internal Revenue Code” means the Internal Revenue Code of 1986, as amended from time to time, and the regulations promulgated and rulings issued thereunder.

“Interpolated Rate” means, in relation to the LIBO Rate, the rate which results from interpolating on a linear basis between:

(a)    the applicable LIBO Rate for the longest period (for which that LIBO Rate is available) which is less than the Interest Period of that Loan; and

(b)    the applicable LIBO Rate for the shortest period (for which that LIBO Rate is available) which exceeds the Interest Period of that Loan,

each as of approximately 11:00 a.m. (London, England time) two Business Days prior to the commencement of such Interest Period of that Loan.

“Laws” means, collectively, all international, foreign, Federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, licenses, authorizations and permits of, and agreements with, any Governmental Authority.

“Lenders” means the Initial Lenders and each Person that shall become a party hereto pursuant to Section 8.07.

“LIBO Rate” has the meaning specified in the definition of “Eurodollar Rate.”

“Lien” means any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or otherwise), charge or other security interest or preferential arrangement that has the practical effect of creating a security interest, including, without limitation, the lien or retained security title of a conditional vendor and any easement, right of way or other encumbrance on title to real property, and any capital lease having substantially the same economic effect as any of the foregoing.

“Loans” has the meaning specified in Section 2.01.

11

“Loan Documents” mean this Agreement, each Note and the Fee Letter.

“Material Adverse Effect” means a material adverse effect on (a) the financial condition, operations, business or property of the Borrower and its Subsidiaries taken as a whole, (b) the rights and remedies of the Agent or any Lender under this Agreement or any Note or (c) the ability of the Borrower to perform its obligations under this Agreement or any Note.

“Material Subsidiary” means APS and, at any time, each other Subsidiary of the Borrower which as of such time meets the definition of a “significant subsidiary” included as of the date hereof in Regulation S-X of the Securities and Exchange Commission or whose assets at such time exceed 10% of the assets of the Borrower and the Subsidiaries (on a Consolidated basis).

“Maturity Date” means May 7, 2020.

“Multiemployer Plan” means any employee benefit plan of the type described in Section 4001(a)(3) of ERISA, to which the Borrower or any ERISA Affiliate makes or is obligated to make contributions, or during the preceding five plan years, has made or been obligated to make contributions.

“Note” means a promissory note of the Borrower payable to the order of any Lender, delivered pursuant to a request made under Section 2.14, in substantially the form of Exhibit A hereto.

“Notice of Initial Borrowing” has the meaning specified in Section 2.02(a).

“Obligations” means all loans to, and debts, liabilities, obligations, covenants and duties of, the Borrower arising under any Loan Document or otherwise with respect to any Loan, whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising and including interest and fees that accrue under any Loan Document after the commencement by or against the Borrower of any proceeding under any Debtor Relief Laws naming such Person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding.

“OFAC” means Office of Foreign Assets Control of the United States Department of the Treasury.

“Other Taxes” means all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or under any other Loan Document or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement or any other Loan Document.

“Participant” has the meaning specified in Section 8.07(d).

“Participant Register” has the meaning specified in Section 8.07(d).

“PATRIOT Act” means the USA PATRIOT Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)), as amended.

12

“PBGC” means the Pension Benefit Guaranty Corporation.

“Pension Plan” means any “employee pension benefit plan” (as such term is defined in Section 3(2) of ERISA), other than a Multiemployer Plan, that is subject to Title IV of ERISA and is sponsored or maintained by the Borrower or any ERISA Affiliate or to which the Borrower or any ERISA Affiliate contributes or has an obligation to contribute, or in the case of a multiple employer or other plan described in Section 4064(a) of ERISA, has made contributions at any time during the immediately preceding five plan years.

“Percentage” means, with respect to any Lender at any time, a fraction the numerator of which is the outstanding principal amount of such Lender’s Loans at such time and the denominator of which is the aggregate outstanding principal amount of all Loans at such time; provided, that (i) the initial Percentage of each Lender shall be the percentage set forth opposite such Lender’s name on Schedule 1.01 under the column “Ratable Share” and (ii) if the outstanding principal amount of all Loans has been repaid in full, the Percentage of each Lender shall be such Lender’s Percentage as in effect immediately prior to such repayment.

“Person” means an individual, partnership, corporation (including a business trust), joint stock company, trust, unincorporated association, joint venture, limited liability company or other entity, or a government or any political subdivision or agency thereof.

“Plan” means any “employee benefit plan” (as such term is defined in Section 3(3) of ERISA) established by the Borrower or, with respect to any such plan that is subject to Section 412 of the Internal Revenue Code or Title IV of ERISA, any ERISA Affiliate.

“Prime Rate” shall mean the interest rate per annum announced from time to time by the Agent at its Principal Office as its then prime rate, which rate may not be the lowest or most favorable rate then being charged commercial borrowers or others by the Agent. Any change in the Prime Rate shall take effect at the opening of business on the day such change is announced.

“Principal Office” shall mean the main banking office of the Agent in Pittsburgh, Pennsylvania.

“Prohibited Person” means any Person (a) listed in the Annex to the Executive Order or identified pursuant to Section 1 of the Executive Order; (b) that is owned or controlled by, or acting for or on behalf of, any Person listed in the Annex to the Executive Order or identified pursuant to the provisions of Section 1 of the Executive Order; (c) with whom a Lender is prohibited from dealing or otherwise engaging in any transaction by any terrorism or anti-laundering law, including the Executive Order; (d) who commits, threatens, conspires to commit, or support “terrorism” as defined in the Executive Order; (e) who is named as a “Specially designated national or blocked person” on the most current list published by the OFAC at its official website, at http://www.treas.gov/offices/enforcement/ofac/sdn/t11sdn.pdf or any replacement website or other replacement official publication of such list; or (f) who is owned or controlled by a Person listed above in clause (c) or (e).

13

“PTE” means a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.

“PVNGS” means the Palo Verde Nuclear Generating Station.

“Ratable Share” of any amount means, with respect to any Lender at any time but subject to Section 2.16, the product of such amount times such Lender’s Percentage.

“Register” has the meaning specified in Section 8.07(c).

“Related Parties” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees and advisors of such Person and of such Person’s Affiliates.

“Reportable Event” means any of the events set forth in Section 4043(c) of ERISA, other than events for which the 30-day notice period has been waived under the final regulations issued under Section 4043, as in effect as of the date of this Agreement (the “Section 4043 Regulations”). Any changes made to the Section 4043 Regulations that become effective after the Effective Date shall have no impact on the definition of Reportable Event as used herein unless otherwise amended by the Borrower and the Required Lenders.

“Required Lenders” means, as of any date of determination, but subject to Section 2.16, Lenders holding in the aggregate more than 50% of the aggregate outstanding principal amount of all Loans (or, if all Loans have been repaid in full, more than 50% of the aggregate amount of all outstanding Obligations); providedthat at all times when two or more Lenders are party to this Agreement, the term “Required Lenders” shall in no event mean less than two Lenders.

“Sanctions” means economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by OFAC and any similar economic or financial sanctions or trade embargoes of the type described in Sections 4.01(n) through (q) and imposed, administered or enforced from time to time by the U.S. government, including the U.S. Department of State, or any other applicable Governmental Authority.

“SEC Reports” means the Borrower’s (i) Form 10-K Report for the year ended December 31, 2018, (ii) Form 10-Q Report for the quarter ended March 31, 2019, and (iii) Form 8-K Reports filed on February 26, 2019 (amending the Form 8-K filed on December 20, 2018), February 26, 2019 and February 28, 2019.

“Subsidiary” of any Person means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (a) the issued and outstanding Voting Stock, (b) the interest in the capital or profits of such limited liability company, partnership or joint venture or (c) the beneficial interest in such trust or estate, is at the time directly or indirectly owned or controlled by such Person, by such Person and one or more of its other Subsidiaries or by one or more of such Person’s other Subsidiaries; provided that in no event will Subsidiaries include the VIE Lessor Trusts.

14

“Syndication Agent” means Citibank, N.A., together with its successors and assigns.

“Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Type”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Eurodollar Rate or the Base Rate.

“VIE Lessor Trusts” means the three (3) separate variable-interest entity lessor trusts that purchased from, and leased back to, APS certain interests in the PVNGS Unit 2 and related common facilities, as described in Note 6 of Combined Notes to Condensed Consolidated Financial Statements in Borrower’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2019.

“Voting Stock” means capital stock issued by a corporation, or equivalent interests in any other Person, the holders of which are ordinarily, in the absence of contingencies, entitled to vote for the election of directors (or persons performing similar functions) of such Person, even if the right so to vote has been suspended by the happening of such a contingency.

“Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

Section 1.02Other Interpretive Provisions. With reference to this Agreement and each other Loan Document, unless otherwise specified herein or in such other Loan Document:

(a)The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation.” The word “will” shall be construed to have the same meaning and effect as the word “shall.” Unless the context requires otherwise, (i) any definition of or reference to any agreement, instrument or other document shall be construed as referring to such agreement, instrument or other document as from time to time amended, restated, supplemented or otherwise modified (subject to any restrictions on such amendments, restatements, supplements or modifications set forth herein or in any other Loan Document), (ii) any reference herein to any Person shall be construed to include such Person’s permitted successors and permitted assigns, (iii) the words “herein,” “hereof” and “hereunder,” and words of similar import when used in any Loan Document, shall be construed to refer to such Loan Document in its entirety and not to any particular provision thereof, (iv) all references in a Loan Document to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, the Loan Document in which such references appear, (v) any reference to any law shall include all statutory and regulatory provisions consolidating, amending, replacing or interpreting such law and any reference to any law or regulation shall, unless

15

otherwise specified, refer to such law or regulation as amended, modified or supplemented from time to time, and (vi) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

(b)In the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including;” the words “to” and “until” each mean “to but excluding;” and the word “through” means “to and including.”

(c)Section headings herein and in the other Loan Documents are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other Loan Document.

Section 1.03Accounting Terms. Unless otherwise specified herein, and subject to the provision below, all accounting terms used herein shall be interpreted, all accounting determinations hereunder shall be made, and all financial statements required to be delivered hereunder shall be prepared, in accordance with generally accepted accounting principles as in effect from time to time, applied on a basis consistent (except for changes concurred in by the Borrower’s independent public accountants) with the most recent audited Consolidated financial statements of the Borrower delivered to the Agent (“GAAP”). If at any time any change in GAAP or in the interpretation thereof would affect the computation of any financial ratio or requirement set forth in any Loan Document, and either the Borrower or the Required Lenders shall so request, the Agent, the Lenders and the Borrower shall negotiate in good faith to amend such ratio or requirement to preserve the original intent thereof in light of such change in GAAP or in the interpretation thereof (subject to the approval of the Required Lenders); providedthat, unless and until so amended, such ratio or requirement shall continue to be computed in accordance with GAAP prior to such change therein. Notwithstanding the foregoing, (a) for purposes of all financial or covenant calculations made under this Agreement and for purposes of defining and calculating Capital Lease Obligations, Indebtedness and Consolidated Indebtedness hereunder for such purposes, all leases or other agreements of any Person deemed to be a lease or other obligation under GAAP (as in effect from time to time) (whether such lease or other agreement is existing as of the date hereof or hereafter entered into) that would not be characterized as (i) a Capital Lease Obligation, (ii) Indebtedness or (iii) Consolidated Indebtedness, in each case, under this Agreement based on GAAP as in effect as of December 31, 2015, will not be deemed to be (i) a Capital Lease Obligation, (ii) Indebtedness or (iii) Consolidated Indebtedness, respectively, as a result of any change in GAAP, or the interpretation or application thereof required or approved by such Person’s independent certified public accountants, occurring or coming into or taking effect after December 31, 2015, including ASC Topic 840 or 842 or any related, similar or successor pronouncement, guidance, publication or rule and (b) all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made (i) without giving effect to any election under Accounting Standards Codification 825-10-25 (or any other Accounting Standards Codification or Financial Accounting Standard having a similar result or effect) to value any Indebtedness or other liabilities of any Person at “fair value”, as defined therein and (ii) without giving effect to any treatment of Indebtedness in respect of convertible debt instruments under Accounting Standards Codification 470-20 (or any other Accounting Standards Codification or Financial Accounting Standard having

16

a similar result or effect) to value any such Indebtedness in a reduced or bifurcated manner as described therein, and such Indebtedness shall at all times be valued at the full stated principal amount thereof.

Section 1.04Rounding. Any financial ratios required to be maintained by the Borrower pursuant to this Agreement shall be calculated by dividing the appropriate component by the other component, carrying the result to one place more than the number of places by which such ratio is expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).

Section 1.05Times of Day. Unless otherwise specified, all references herein to times of day shall be references to Eastern time (daylight or standard, as applicable).

ARTICLE IIAMOUNTS AND TERMS OF THE LOANS

Section 2.01The Loans.

Subject to the terms and conditions hereof (including, without limitation, Section 3.01), each Lender, by its acceptance hereof, severally agrees to make a one-time loan (individually, a “Loan” and, collectively, the “Loans”) to the Borrower on the Effective Date in Dollars in an aggregate principal amount equal to such Lender’s Commitment.  As provided in Section 2.05, the Borrower may elect that each Borrowing of Loans be either Base Rate Loans or Eurodollar Rate Loans. Amounts borrowed by the Borrower hereunder and prepaid or otherwise repaid may not be reborrowed. Unless an earlier maturity is provided for hereunder, all Loans shall mature and be due and payable on the Maturity Date. The Commitments shall immediately and automatically terminate upon the earlier of (i) 5:00 p.m. on the Effective Date and (ii) the making of the Loans pursuant to this Section 2.01.

Section 2.02Making the Loans.

(a)The Initial Borrowing shall be made on notice, given not later than (x) 12:00 noon on the third Business Day prior to the Effective Date in the case of an Initial Borrowing consisting of Eurodollar Rate Loans or (y) 12:00 noon on the Business Day prior to the Effective Date in the case of an Initial Borrowing consisting of Base Rate Loans, by the Borrower to the Agent, which shall give to each Lender prompt notice thereof by facsimile. Such notice of the Initial Borrowing (the “Notice of Initial Borrowing”) shall be in writing or by facsimile in substantially the form of Exhibit B hereto, specifying therein the requested (i) date of the Initial Borrowing (which shall be the Effective Date and a Business Day), (ii) Type of Loans comprising the Initial Borrowing, (iii) aggregate amount of the Initial Borrowing, and (iv) in the case of an Initial Borrowing consisting of Eurodollar Rate Loans, initial Interest Period for each such Loan. Each Lender shall, before 2:00 p.m. on the date of the Initial Borrowing, make available for the account of its Applicable Lending Office to the Agent at the Agent’s Account, in same day funds, such Lender’s Ratable Share of the Initial Borrowing. After the Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Agent will make such funds available to the Borrower at the

17

Agent’s address referred to in Section 8.02 or as requested by the Borrower in the Notice of Initial Borrowing.

(b)Anything in subsection (a) above to the contrary notwithstanding, (i) the Borrower may not select Eurodollar Rate Loans for any Borrowing if the aggregate amount of such Borrowing is less than $5,000,000 or less than an integral multiple of $500,000 in excess thereof or if the obligation of the Lenders to make Eurodollar Rate Loans shall then be suspended pursuant to Section 2.06 or 2.10, and (ii) at no time shall there be more than three (3) different Interest Periods outstanding for Eurodollar Rate Loans.

(c)The Notice of Initial Borrowing shall be irrevocable and binding on the Borrower. If the Notice of Initial Borrowing specifies that the Initial Borrowing is to be comprised of Eurodollar Rate Loans, the Borrower shall indemnify each Lender against any loss, cost or expense reasonably incurred by such Lender as a result of any failure (i) to fulfill on or before the date specified in the Notice of Initial Borrowing the applicable conditions set forth in Article III or (ii) to otherwise borrow the Eurodollar Rate Loans requested by the Borrower in the Notice of Initial Borrowing on such date (and shall set forth such indemnification obligation in the Notice of Initial Borrowing), including, without limitation, any loss (excluding loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to fund the Loan to be made by such Lender as part of the Initial Borrowing when such Loan, as a result of any such failure, is not made on such date.

(d)Unless the Agent shall have received notice from a Lender prior to the time of the Initial Borrowing that such Lender will not make available to the Agent such Lender’s Ratable Share of the Initial Borrowing, the Agent may assume that such Lender has made such portion available to the Agent on the date of the Initial Borrowing in accordance with subsection (a) of this Section 2.02 and the Agent may, in reliance upon such assumption, make available to the Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such Ratable Share available to the Agent, such Lender and the Borrower severally agree to repay to the Agent within one Business Day after demand for such Lender and within three Business Days after demand for the Borrower such corresponding amount together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Agent, at (i) in the case of the Borrower, the interest rate applicable at the time to Loans comprising the Initial Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If the Borrower and such Lender shall pay such interest to the Agent for the same or an overlapping period, the Agent shall promptly remit to the Borrower the amount of such interest paid by the Borrower for such period. If such Lender shall repay to the Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Loan as part of the Initial Borrowing for purposes of this Agreement.

(e)The failure of any Lender to make the Loan to be made by it as part of the Initial Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Loan on the date of the Initial Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Loan to be made by such other Lender on the date of the Initial Borrowing.

18

Section 2.03Fees. The Borrower shall pay to the Agent and PNC Capital Markets LLC such fees as are agreed between the Borrower and the Agent pursuant to the Fee Letter.

Section 2.04Repayment of Loans. The Borrower hereby unconditionally agrees to pay to the Agent on the Maturity Date, for the account of the Lenders, the then unpaid principal amount of the Loans, together with all accrued and unpaid interest thereon, and all other outstanding Obligations.

Section 2.05Interest on Loans.

(a)Scheduled Interest. The Borrower shall pay interest on the unpaid principal amount of each Loan owing to each Lender from the date of such Loan until such principal amount shall be paid in full, at the following rates per annum:

(i)Base Rate Loans. During such periods as such Loan is a Base Rate Loan, a rate per annum equal at all times to the sum of (x) the Base Rate in effect from time to time plus (y) the Applicable Rate for Base Rate Loans in effect from time to time, payable in arrears quarterly on the last Business Day of each March, June, September and December during such periods and on the date such Base Rate Loan shall be Converted or paid in full.

(ii)Eurodollar Rate Loans. During such periods as such Loan is a Eurodollar Rate Loan, a rate per annum equal at all times during each Interest Period for such Loan to the sum of (x) the Eurodollar Rate for such Interest Period for such Loan plus (y) the Applicable Rate for Eurodollar Rate Loans in effect from time to time, payable in arrears on the last day of such Interest Period and, if such Interest Period has a duration of more than three months, on each day that occurs during such Interest Period every three months from the first day of such Interest Period and on the date such Eurodollar Rate Loan shall be Converted or paid in full.

(b)Default Interest. Upon the occurrence and during the continuance of an Event of Default under Section 6.01(a), the Agent may, and upon the request of the Required Lenders shall, require the Borrower to pay interest (“Default Interest”) on (i) the unpaid principal amount of each Loan owing to each Lender, payable in arrears on the dates referred to in clause (a)(i) or (a)(ii) above, at a rate per annum equal at all times to 2% per annum above the rate per annum required to be paid on such Loan pursuant to clause (a)(i) or (a)(ii) above and (ii) to the fullest extent permitted by Law, the amount of any interest, fee or other amount payable hereunder that is not paid when due, from the date such amount shall be due until such amount shall be paid in full, payable in arrears on the date such amount shall be paid in full and on demand, at a rate per annum equal at all times to 2% per annum above the rate per annum required to be paid on Base Rate Loans pursuant to clause (a)(i) above, provided, however, that following acceleration of the Loans pursuant to Section 6.01, Default Interest shall accrue and be payable hereunder whether or not previously required by the Agent.

(c)Interest Rate Limitation. Nothing contained in this Agreement or in any other Loan Document shall be deemed to establish or require the payment of interest to any Lender at a rate in excess of the maximum rate permitted by applicable Law. If the amount of interest payable for the

19

account of any Lender on any interest payment date would exceed the maximum amount permitted by applicable Law to be charged by such Lender, the amount of interest payable for its account on such interest payment date shall be automatically reduced to such maximum permissible amount. In the event of any such reduction affecting any Lender, if from time to time thereafter the amount of interest payable for the account of such Lender on any interest payment date would be less than the maximum amount permitted by applicable Law to be charged by such Lender, then the amount of interest payable for its account on such subsequent interest payment date shall be automatically increased to such maximum permissible amount, provided that at no time shall the aggregate amount by which interest paid for the account of any Lender has been increased pursuant to this sentence exceed the aggregate amount by which interest paid for its account has theretofore been reduced pursuant to the previous sentence.

Section 2.06Interest Rate Determination.

(a)The Agent shall give prompt notice to the Borrower and the Lenders of the applicable interest rate determined by the Agent for purposes of Section 2.05(a).

(b)(i)    If the Required Lenders determine that for any reason in connection with any request for a Eurodollar Rate Loan or a Conversion to or continuation thereof that (a) Dollar deposits are not being offered to banks in the London interbank eurodollar market for the applicable amount and Interest Period of such Eurodollar Rate Loan, (b) adequate and reasonable means do not exist for determining the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Rate Loan, or (c) the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Rate Loan does not adequately and fairly reflect the cost to such Lenders of funding such Loan, the Agent will promptly so notify the Borrower and each Lender, whereupon each Eurodollar Rate Loan will automatically on the last day of the then existing Interest Period therefor Convert into a Base Rate Loan. Thereafter, the obligation of the Lenders to make or maintain Eurodollar Rate Loans shall be suspended until the Agent (upon the instruction of the Required Lenders) revokes such notice. Upon receipt of such notice, the Borrower may revoke any pending request for a Borrowing of, Conversion to or continuation of Eurodollar Rate Loans or, failing that, will be deemed to have Converted such request into a request for a Base Rate Loan in the amount specified therein.

(ii)Notwithstanding anything to the contrary herein, if at any time the Agent or the Required Lenders determine (which determination shall be conclusive absent manifest error) that either (a) (i) the circumstances set forth in Section 2.06(b)(i) have arisen and such circumstances are unlikely to be temporary or (ii) the circumstances set forth in Section 2.06(b)(i) have not arisen but the supervisor for the administrator of the Eurodollar Rate or a Governmental Authority having jurisdiction over the Agent has made a public statement identifying a specific date after which the Eurodollar Rate shall no longer be used for determining interest rates for loans (either such date, a “Eurodollar Termination Date”), or (b) a rate other than the Eurodollar Rate has become a widely recognized benchmark rate for newly originated loans in Dollars in the U.S. market, then the Agent and the Borrower shall endeavor to establish an alternate rate of interest to the Eurodollar Rate that gives due

20

consideration to the then prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time such that, to the extent practicable, the all-in interest rate based on the alternate rate of interest will be substantially equivalent to the all-in Eurodollar Rate-based interest rate in effect prior to its replacement, and shall enter into an amendment to this Agreement to reflect such alternate rate of interest and such other related changes to this Agreement as may be applicable.

(iii)Notwithstanding anything to the contrary in Section 8.01, any amendment to this Agreement pursuant to Section 2.06(b)(ii) shall become effective without any further action or consent of any other party to this Agreement so long as the Agent shall not have received, within five (5) Business Days of the date notice of such alternate rate of interest, together with a copy of such amendment, is provided to the Lenders, a written notice from the Required Lenders stating that such Required Lenders object to such amendment. Selection of the alternate rate of interest, adjustments to the applicable margins, and amendments to this Agreement (i) will be determined with due consideration to the then-current market practices for determining and implementing a rate of interest for newly originated loans in the United States and loans Converted from a Eurodollar Rate-based rate to an alternate rate of interest, and (ii) may also reflect adjustments to account for (x) the effects of the transition from the Eurodollar Rate to the alternate rate of interest and (y) yield- or risk-based differences between the Eurodollar Rate and the alternate rate of interest. Providedthat, if such alternate rate of interest shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

(iv)Until an amendment reflecting a new alternate rate of interest in accordance with this Section 2.06 is effective, each advance, Conversion and continuation of a Loan under the Eurodollar Rate will continue to bear interest with reference to the Eurodollar Rate; providedhowever, that if the Agent determines (which determination shall be final and conclusive, absent manifest error) that a Eurodollar Termination Date has occurred, then following the Eurodollar Termination Date, all Loans as to which the Eurodollar Rate would otherwise apply shall automatically be Converted to Base Rate Loans until such time as an amendment reflecting an alternate rate of interest and related matters as described above is implemented.

(c)If the Borrower shall fail to select the duration of any Interest Period for any Eurodollar Rate Loans in accordance with the provisions contained in the definition of “Interest Period” in Section 1.01, the Agent will forthwith so notify the Borrower and the Lenders and such Loans will automatically, on the last day of the then existing Interest Period therefor, Convert into Base Rate Loans.

(d)On the date on which the aggregate unpaid principal amount of Eurodollar Rate Loans comprising any Borrowing shall be reduced, by payment or prepayment or otherwise, to less than $5,000,000, such Loans shall automatically Convert into Base Rate Loans.

21

(e)Upon the occurrence and during the continuance of any Event of Default,

(i)with respect to Eurodollar Rate Loans, each such Loan will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Loan (or if such Loan is then a Base Rate Loan, will continue as a Base Rate Loan); and

(ii)the obligation of the Lenders to Convert Loans into Eurodollar Rate Loans shall be suspended until the Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist.

Section 2.07Optional Conversion of Loans. The Borrower may on any Business Day, upon notice given to the Agent (in the form of an Interest Election Request duly completed and executed by the Borrower) not later than 12:00 noon on the third Business Day prior to the date of the proposed Conversion and subject to the provisions of Sections 2.06 and 2.10, Convert all or any portion of the Loans of one Type comprising the same Borrowing into Loans of the other Type; provided, however, that (a) any Conversion of Eurodollar Rate Loans into Base Rate Loans shall be made only on the last day of an Interest Period for such Eurodollar Rate Loans, (b) any Conversion of Base Rate Loans into Eurodollar Rate Loans shall be in an amount not less than the minimum amount specified in Section 2.02(b) and (c) no Conversion of any Loans shall result in more separate Borrowings than permitted under Section 2.02(b). Each such notice of a Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Loans to be Converted and (iii) if such Conversion is into Eurodollar Rate Loans, the duration of the initial Interest Period for each such Loan. Each Interest Election Request shall be irrevocable and binding on the Borrower.

Section 2.08Prepayments of Loans.

(a)Optional. At any time and from time to time, the Borrower shall have the right to prepay the Loans, in whole or in part, without premium or penalty (except as provided in clause (z) below), upon notice at least two Business Days’ prior to the date of such prepayment, in the case of Eurodollar Rate Loans, and not later than 11:00 a.m. on the date of such prepayment, in the case of Base Rate Loans, to the Agent specifying the proposed date of such prepayment and the aggregate principal amount and Type of the Loans to be prepaid (and, in the case of Eurodollar Rate Loans, the Interest Period of the Borrowing pursuant to which made); provided, however, that (x) each partial prepayment shall be in a minimum aggregate principal amount of $1,000,000 and, if in excess thereof, in an integral multiple of $500,000, (y) accrued interest to the date of prepayment on the principal amount prepaid shall be payable by the Borrower on the date of such prepayment, and (z) in the event of any such prepayment of a Eurodollar Rate Loan, the Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.04(e). Each prepayment of Loans shall be applied ratably to the outstanding principal amount of each Lender’s Loan in accordance with such Lender’s Ratable Share.

(b)Mandatory. The Borrower shall prepay the aggregate principal amount of the Loans, together with accrued interest to the date of prepayment on the principal amount prepaid, without requirement of demand therefor, or shall pay or prepay any other Indebtedness then outstanding at any time, when and to the extent required to comply with applicable Laws of any Governmental Authority or applicable resolutions of the Board of Directors of the Borrower.

22

Section 2.09Increased Costs.

(a)Increased Costs Generally. If any Change in Law shall:

(i)impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender (except any reserve requirement contemplated by Section 2.09(e));

(ii)impose on any Lender or the London interbank market any other condition, cost or expense affecting this Agreement or Eurodollar Rate Loans made by such Lender; or

(iii)subject the Agent or any Lender to any Taxes (other than (A) Indemnified Taxes, (B) Excluded Taxes and (C) Other Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

and the result of any of the foregoing shall be to increase the cost to the Agent or such Lender of making, maintaining or Converting any Loan (or of maintaining its obligation to make any such Loan), or to reduce the amount of any sum received or receivable by the Agent or such Lender hereunder (whether of principal, interest or any other amount) then, upon request of the Agent or such Lender, the Borrower will pay to the Agent or such Lender such additional amount or amounts as will compensate the Agent or such Lender for such additional costs incurred or reduction suffered.

(b)Capital Requirements. If any Lender determines that any Change in Law affecting such Lender or any Applicable Lending Office of such Lender or such Lender’s holding company, if any, regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Loans made by such Lender, to a level below that which such Lender or such Lender’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy and liquidity), then from time to time the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.

(c)Certificates for Reimbursement. A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in subsection (a) or (b) of this Section and delivered to the Borrower shall be conclusive and binding upon all parties absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 30 days after receipt thereof.

(d)Delay in Requests. Failure or delay on the part of any Lender to demand compensation pursuant to the foregoing provisions of this Section shall not constitute a waiver of such Lender’s right to demand such compensation, provided that the Borrower shall not be required to compensate a Lender pursuant to the foregoing provisions of this Section for any increased costs

23

incurred or reductions suffered more than three months prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s intention to claim compensation therefor (except that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the three-month period referred to above shall be extended to include the period of retroactive effect thereof).

(e)Reserves on Eurodollar Rate Loans. The Borrower shall pay to each Lender, as long as such Lender shall be required to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency funds or deposits (currently known as “Eurocurrency liabilities”), additional interest on the unpaid principal amount of each Eurodollar Rate Loan equal to the actual costs of such reserves allocated to such Loan by such Lender (as determined by such Lender in good faith, which determination shall be conclusive absent manifest error), which shall be due and payable on each date on which interest is payable on such Loan, provided the Borrower shall have received at least 30 days’ prior notice (with a copy to the Agent) of such additional interest from such Lender. If a Lender fails to give notice 30 days prior to the relevant interest payment date, such additional interest shall be due and payable 30 days from receipt of such notice.

Section 2.10Illegality. If any Lender shall have determined in good faith that the introduction of or any change in any applicable Law or in the interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof, or compliance with any guideline or request from any such Governmental Authority (whether or not having the force of law), makes it unlawful for any Lender or its Applicable Lending Office to make, maintain or fund Eurodollar Rate Loans, or to determine or charge interest rates based upon the Eurodollar Rate, or any Governmental Authority has imposed material restrictions on the authority of such Lender to purchase or sell, or to take deposits of, Dollars in the London interbank market, then, on notice thereof by such Lender to the Borrower through the Agent, any obligation of such Lender to make or continue Eurodollar Rate Loans or to Convert Base Rate Loans to Eurodollar Rate Loans shall be suspended until such Lender notifies the Agent and the Borrower that the circumstances giving rise to such determination no longer exist. Upon receipt of such notice, the Borrower shall, upon demand from such Lender (with a copy to the Agent), prepay or, if applicable, Convert all Eurodollar Rate Loans of such Lender to Base Rate Loans, either on the last day of the Interest Period therefor, if such Lender may lawfully continue to maintain such Eurodollar Rate Loans to such day, or immediately, if such Lender may not lawfully continue to maintain such Eurodollar Rate Loans. Upon any such prepayment or Conversion, the Borrower shall also pay accrued interest on the amount so prepaid or Converted.

Section 2.11Payments and Computations.

(a)All payments to be made by the Borrower shall be made without condition or deduction for any counterclaim, defense, recoupment or setoff. The Borrower shall make each payment hereunder not later than 1:00 p.m. on the day when due in Dollars to the Agent at the Agent’s Account in same day funds. The Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal, interest or fees ratably (other than amounts payable pursuant to Section 2.09, 2.10, 2.12, 2.17 or 8.04(e)) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other amount payable to

24

any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Assumption and recording of the information contained therein in the Register pursuant to Section 8.07(c), from and after the effective date specified in such Assignment and Assumption, the Agent shall make all payments hereunder and under the Notes in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Assumption shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.

(b)All computations of interest based on the Base Rate (when the Base Rate is based on the Prime Rate) shall be made by the Agent on the basis of a year of 365 or 366 days, as the case may be, and all other computations of interest and fees hereunder (including computations of interest based on the Eurodollar Rate and the Federal Funds Rate and of fees) shall be made by the Agent on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest or fees are payable. Each determination by the Agent of an interest rate hereunder shall be conclusive and binding for all purposes, absent manifest error.

(c)Whenever any payment hereunder or under the Notes shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or fees, as the case may be; provided, however, that, if such extension would cause payment of interest on or principal of Eurodollar Rate Loans to be made in the next following calendar month, such payment shall be made on the next preceding Business Day.

(d)Unless the Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Lenders hereunder that the Borrower will not make such payment in full, the Agent may assume that the Borrower has made such payment in full to the Agent on such date and the Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due to such Lender. If and to the extent the Borrower shall not have so made such payment in full to the Agent, each Lender shall repay to the Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Agent, at the Federal Funds Rate.

Section 2.12Taxes.

(a)Payments Free of Taxes; Obligation to Withhold; Payments on Account of Taxes.

(i)Any and all payments by or on account of any obligation of the Borrower hereunder or under any other Loan Document shall to the extent permitted by applicable Laws be made free and clear of and without reduction or withholding for any Taxes. If, however, applicable Laws require the Borrower or the Agent to withhold or deduct any Tax, such Tax shall be withheld or deducted in accordance with such Laws as determined by the Borrower or the Agent, as the case may be, upon the basis of the information and documentation to be delivered pursuant to subsection (e) below.

25

(ii)If the Borrower or the Agent shall be required by the Internal Revenue Code to withhold ordeduct any Taxes, including both United States of America Federal backup withholding and withholding Taxes, from any payment, then (A) the Agent shall withhold or make such deductions as are determined by the Agent to be required based upon the information and documentation it has received pursuant to subsection (e) below, (B) the Agent shall timely pay the full amount withheld or deducted to the relevant Governmental Authority in accordance with the Internal Revenue Code, and (C) to the extent that the withholding or deduction is made on account of Indemnified Taxes or Other Taxes, the sum payable by the Borrower shall be increased as necessary so that after any required withholding or the making of all required deductions (including deductions applicable to additional sums payable under this Section) the Agent or each Lender, as the case may be, receives an amount equal to the sum it would have received had no such withholding or deduction been made.

(b)Payment of Other Taxes by the Borrower. Without limiting the provisions of subsection (a) above, the Borrower shall timely pay any Other Taxes to the relevant Governmental Authority in accordance with applicable Laws.

(c)Tax Indemnifications.

(i)Without limiting the provisions of subsection (a) or (b) above, the Borrower shall, and does hereby, indemnify the Agent and each Lender, and shall make payment in respect thereof within 30 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) withheld or deducted by the Borrower or the Agent or paid by the Agent or such Lender, as the case may be, and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. The Borrower shall also, and does hereby, indemnify the Agent, and shall make payment in respect thereof within 10 days after demand therefor, for any amount which a Lender for any reason fails to pay indefeasibly to the Agent as required by clause (ii) of this subsection. A certificate as to the amount of any such payment or liability delivered to the Borrower by a Lender (with a copy to the Agent), or by the Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(ii)Each Lender shall, within 30 days after demand therefor, severally indemnify (A) the Agent for (x) any Indemnified Taxes and Other Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Agent for such Indemnified Taxes and Other Taxes and without limiting the obligation of the Borrower to do so), (y) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 8.07(d) relating to the maintenance of a Participant Register and (z) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted

26

by the relevant Governmental Authority, and (B) the Borrower and the Agent against any and all Taxes and any and all related losses, claims, liabilities, penalties, interest and expenses (including the fees, charges and disbursements of any counsel for the Borrower orthe Agent) incurred by or asserted against the Borrower or the Agent by any Governmental Authority as a result of the failure by such Lender to deliver, or as a result of the inaccuracy, inadequacy or deficiency of, any documentation required to be delivered by such Lender to the Borrower or the Agent pursuant to subsection (e). A certificate as to the amount of such payment or liability delivered to any Lender by the Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Agent to set off and apply any and all amounts at any time owing to such Lender under this Agreement or any other Loan Document or otherwise payable by the Agent to the Lender from any other source against any amount due to the Agent under this clause (ii). The agreements in this clause (ii) shall survive the resignation and/or replacement of the Agent, any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all other Obligations.

(d)Evidence of Payments. Upon request by the Borrower or the Agent, as the case may be, after any payment of Taxes by the Borrower or by the Agent to a Governmental Authority as provided in this Section 2.12, the Borrower shall deliver to the Agent or the Agent shall deliver to the Borrower, as the case may be, the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by Laws to report such payment or other evidence of such payment reasonably satisfactory to the Borrower or the Agent, as the case may be.

(e)Status of Lenders; Tax Documentation.

(i)Each Lender shall deliver to the Borrower and to the Agent, at the time or times prescribed by applicable Laws or when reasonably requested by the Borrower or the Agent, such properly completed and executed documentation prescribed by applicable Laws or by the taxing authorities of any jurisdiction and such other reasonably requested information as will permit the Borrower or the Agent, as the case may be, to determine (A) whether or not payments made hereunder or under any other Loan Document are subject to Taxes, (B) if applicable, the required rate of withholding or deduction, and (C) such Lender’s entitlement to any available exemption from, or reduction of, applicable Taxes in respect of all payments to be made to such Lender by the Borrower pursuant to this Agreement or otherwise to establish such Lender’s status for withholding tax purposes in the applicable jurisdiction.

(ii)Without limiting the generality of the foregoing, if the Borrower is resident for tax purposes in the United States of America,

(A)any Lender that is a “United States person” within the meaning of Section 7701(a)(30) of the Internal Revenue Code shall deliver to the Borrower and the Agent executed originals of Internal Revenue Service Form W-9 or such other documentation or information prescribed by applicable Laws or reasonably requested by the Borrower or the Agent as will enable the Borrower or the Agent,

27

as the case may be, to determine whether or not such Lender is subject to backup withholding or information reporting requirements; and

(B)each Foreign Lender that is entitled under the Internal Revenue Code or any applicable treaty to an exemption from or reduction of withholding tax with respect to payments hereunder or under any other Loan Document shall deliver to the Borrower and the Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the request of the Borrower or the Agent, but only if such Foreign Lender is legally entitled to do so), whichever of the following is applicable:

(1)executed originals of Internal Revenue Service Form W-8BEN or Form W-8BEN-E claiming eligibility for benefits of an income tax treaty to which the United States of America is a party,

(2)executed originals of Internal Revenue Service Form W-8ECI,

(3)executed originals of Internal Revenue Service Form W-8IMY and all required supporting documentation,

(4)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under section 881(c) of the Internal Revenue Code, (x) a certificate to the effect that such Foreign Lender is not (A) a “bank” within the meaning of section 881(c)(3)(A) of the Internal Revenue Code, (B) a “10 percent shareholder” of the Borrower within the meaning of section 881(c)(3)(B) of the Internal Revenue Code, or (C) a “controlled foreign corporation” described in section 881(c)(3)(C) of the Internal Revenue Code and (y) executed originals of Internal Revenue Service Form W-8BEN or Form W-8BEN-E, or

(5)executed originals of any other form prescribed by applicable Laws as a basis for claiming exemption from or a reduction in United States of America Federal withholding tax together with such supplementary documentation as may be prescribed by applicable Laws to permit the Borrower or the Agent to determine the withholding or deduction required to be made.

(iii)Each Lender shall promptly (A) notify the Borrower and the Agent of any change in circumstances which would modify or render invalid any claimed exemption or reduction, and (B) take such steps as shall not be materially disadvantageous to it, in the reasonable judgment of such Lender, and as may be reasonably necessary (including the re-designation of its Applicable Lending Office) to avoid any requirement of applicable Laws of any jurisdiction that the Borrower or the Agent make any withholding or deduction for taxes from amounts payable to such Lender.

28

(iv)If a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Internal Revenue Code, as applicable), such Lender shall deliver to each of the Borrower and the Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Internal Revenue Code) and such additional documentation reasonably requested by the Borrower or the Agent as may be necessary for the Borrower and the Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (iv), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

(f)Treatment of Certain Refunds. Unless required by applicable Laws, at no time shall the Agent have any obligation to file for or otherwise pursue on behalf of a Lender, or have any obligation to pay to any Lender, any refund of Taxes withheld or deducted from funds paid for the account of such Lender. If the Agent or any Lender determines, in its sole discretion, that it has received a refund of any Taxes or Other Taxes as to which it has been indemnified by the Borrower or with respect to which the Borrower has paid additional amounts pursuant to this Section, it shall pay to the Borrower an amount equal to such refund (but only to the extent of indemnity payments made, or additional amounts paid, by the Borrower under this Section with respect to the Taxes or Other Taxes giving rise to such refund), net of all reasonable out-of-pocket expenses incurred by the Agent or such Lender, as the case may be, and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund), provided that the Borrower, upon the request of the Agent or such Lender, agrees to repay the amount paid over to the Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Agent or such Lender in the event the Agent or such Lender is required to repay such refund to such Governmental Authority. This subsection shall not be construed to require the Agent or any Lender to make available its tax returns (or any other information relating to its taxes that it deems confidential) to the Borrower or any other Person.

(g)Payments. Failure or delay on the part of the Agent or any Lender to demand compensation pursuant to the foregoing provisions of this Section 2.12 shall not constitute a waiver of the Agent’s or such Lender’s right to demand such compensation, provided that the Borrower shall not be required to compensate the Agent or a Lender pursuant to the foregoing provisions of this Section 2.12 for any Indemnified Taxes or Other Taxes imposed or asserted by the relevant Governmental Authority more than three months prior to the date that the Agent or such Lender, as the case may be, claims compensation with respect thereto (except that, if a Change in Law giving rise to such Indemnified Taxes or Other Taxes is retroactive, then the three-month period referred to above shall be extended to include the period of retroactive effect thereof).

(h)The Agent and each Lender agrees to cooperate with any reasonable request made by the Borrower in respect of a claim of a refund in respect of Indemnified Taxes as to which it has been indemnified by the Borrower or with respect to which the Borrower has paid additional amounts

29

pursuant to this Section 2.12 if (i) the Borrower has agreed in writing to pay all of the Agent’s or such Lender’s reasonable out-of-pocket costs and expenses relating to such claim, (ii) the Agent or such Lender determines, in its good faith judgment, that it would not be disadvantaged, unduly burdened or prejudiced as a result of such claim and (iii) the Borrower furnishes, upon request of the Agent or such Lender, an opinion of tax counsel (such opinion, which can be reasoned, and such counsel to be reasonably acceptable to such Lender or the Agent) that the Borrower is likely to receive a refund or credit.

Section 2.13Sharing of Payments, Etc. If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Loans owing to it (other than pursuant to Section 2.09, 2.10, 2.12, 2.17 or 8.04(e) or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans to any assignee or participant, other than to the Borrower or any Subsidiary thereof if permitted hereby (as to which the provisions of this Section 2.13 shall apply) in excess of its Ratable Share of payments on account of the Loans obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders (for cash at face value) such participations in the Loans owing to them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender’s Ratable Share (according to the proportion of (i) the amount of such Lender’s required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.13 may, to the fullest extent permitted by Law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation.

Section 2.14Evidence of Debt.

(a)Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan owing to such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder in respect of Loans. The Borrower agrees that upon notice by any Lender to the Borrower (with a copy of such notice to the Agent) to the effect that a Note is required or appropriate in order for such Lender to evidence (whether for purposes of pledge, enforcement or otherwise) the Loans owing to, or to be made by, such Lender, the Borrower shall promptly execute and deliver to such Lender a Note payable to the order of such Lender in a principal amount equal to the Loans owing to, or to be made by, such Lender.

(b)The Register maintained by the Agent pursuant to Section 8.07(c) shall include a control account, and a subsidiary account for each Lender, in which accounts (taken together) shall be recorded (i) the date and amount of each Borrowing made hereunder, the Type of Loans comprising such Borrowing and, if appropriate, the Interest Period applicable thereto, (ii) the terms

30

of each Assignment and Assumption delivered to and accepted by it, (iii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iv) the amount of any sum received by the Agent from the Borrower hereunder and each Lender’s share thereof.

(c)Entries made in good faith by the Agent in the Register pursuant to subsection (b) above, and by each Lender in its account or accounts pursuant to subsection (a) above, shall be primafacie evidence of the amount of principal and interest due and payable or to become due and payable from the Borrower to, in the case of the Register, each Lender and, in the case of such account or accounts, such Lender, under this Agreement, absent manifest error; provided, however, that the failure of the Agent or such Lender to make an entry, or any finding that an entry is incorrect, in the Register or such account or accounts shall not limit or otherwise affect the obligations of the Borrower under this Agreement.

Section 2.15Use of Proceeds. The proceeds of the Loans shall be available (and the Borrower agrees that it shall use such proceeds) solely to refinance Indebtedness of the Borrower under the Existing Credit Agreement and in accordance with Section 4.01(p).

Section 2.16Affected Lenders. Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes an Affected Lender, then the following provisions shall apply for so long as such Lender is an Affected Lender:

(a)the outstanding principal amount of the Loans of such Affected Lender shall not be included in determining whether the Required Lenders have taken or may take any action hereunder (including any consent to any amendment or waiver pursuant to Section 8.01), other than any waiver, amendment or modification requiring the consent of all Lenders or of each Lender affected;

(b)to the extent the Agent receives any payments or other amounts for the account of an Affected Lender under this Agreement, such Affected Lender shall be deemed to have requested that the Agent use such payment or other amount to fulfill such Affected Lender’s previously unsatisfied obligations to fund a Loan under Section 2.01 or any other unfunded payment obligation of such Affected Lender under this Agreement; and

(c)subject to Section 8.18, for the avoidance of doubt, the Borrower, the Agent and each other Lender shall retain and reserve its other rights and remedies respecting each Affected Lender.

In the event that (a) the Agent and the Borrower each agrees that an Affected Lender has adequately remedied all matters that caused such Lender to be an Affected Lender or (b) an Affected Lender is replaced by another Lender pursuant to Section 2.17, then, in either case, this Section 2.16 will no longer apply to such Lender.

Section 2.17Replacement of Lenders. If any Lender requests compensation under Section 2.09, or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.12, or if any Lender is an Affected Lender, then the Borrower may, at its sole expense and effort, upon notice to such Lender and the Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject

31

to the restrictions contained in, and consents required by, Section 8.07), all of its interests, rights and obligations under this Agreement and the related Loan Documents to one or more assignees that shall assume such obligations (which any such assignee may be another Lender (other than an Affected Lender), if such Lender accepts such assignment), provided that:

(a)the Borrower shall have paid to the Agent the assignment fee specified in Section 8.07(b);

(b)such Lender shall have received payment of an amount equal to the outstanding principal amount of its Loans, accrued interest thereon, accrued fees and all other amounts payable to it hereunder and under the other Loan Documents (including any amounts under Section 8.04(e)) from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts);

(c)in the case of any such assignment resulting from a claim for compensation under Section 2.09 or payments required to be made pursuant to Section 2.12, such assignment will result in a reduction in such compensation or payments thereafter; and

(d)such assignment does not conflict with applicable Laws.

A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.

ARTICLE IIICONDITIONS PRECEDENT

Section 3.01Conditions Precedent to Effectiveness. This Agreement shall become effective on and as of the first date (the “Effective Date”) on which the following conditions precedent have been satisfied:

(a)The Lenders shall have been given such access to the management, records, books of account, contracts and properties of the Borrower and its Subsidiaries as they shall have requested.

(b)The Borrower shall have paid all accrued and agreed fees and expenses of the Agent, the Arrangers and the Lenders, including but not limited to all fees then due and payable pursuant to the Fee Letter, and the reasonable accrued fees and expenses of one law firm acting as counsel to the Agent that have been invoiced at least one Business Day prior to the Effective Date.

(c)On the Effective Date, the following statements shall be true and the Agent shall have received a certificate signed by a duly authorized officer of the Borrower, dated the Effective Date, stating that:

(i)The representations and warranties contained in Section 4.01 are true and correct on and as of the Effective Date, both before and after giving effect to the Initial

32

Borrowing and the application of the proceeds thereof, as though made on and as of such date (excluding that the Initial Borrowing is not listed on Schedule 4.01(k) hereto); and

(ii)No event has occurred and is continuing, or would result from the Initial Borrowing or the application of the proceeds thereof, that constitutes a Default.

(d)The Agent shall have received the Notice of Initial Borrowing pursuant to Section 2.02.

(e)The Agent shall have received on or before the Effective Date the following, each dated such day, in form and substance satisfactory to the Agent and the Lenders:

(i)Receipt by the Agent of executed counterparts of this Agreement properly executed by a duly authorized officer of the Borrower and by each Lender.

(ii)The Notes, payable to the order of the Lenders to the extent requested by any Lender pursuant to Section 2.14(a).

(iii)The articles of incorporation of the Borrower certified to be true and complete as of a recent date by the appropriate governmental authority of the state or other jurisdiction of its incorporation and certified by a secretary, assistant secretary or associate secretary of the Borrower to be true and correct as of the Effective Date.

(iv)The bylaws of the Borrower certified by a secretary, assistant secretary or associate secretary of the Borrower to be true and correct as of the Effective Date.

(v)Certified copies of the resolutions of the Board of Directors of the Borrower approving this Agreement and the Notes, and of all documents evidencing other necessary corporate action and governmental approvals, if any, with respect to this Agreement and the Notes.

(vi)A certificate of the secretary, assistant secretary or associate secretary of the Borrower certifying the names and true signatures of the officers of the Borrower authorized to sign this Agreement and the Notes and the other documents to be delivered hereunder.

(vii)A certificate as of a recent date from the Borrower’s state of incorporation evidencing that the Borrower is in good standing in such state.

(viii)A favorable opinion of counsel for the Borrower, in form and substance reasonably acceptable to the Lenders.

(ix)A written opinion of Sidley Austin LLP, special New York counsel for the Agent, in form and substance reasonably acceptable to the Agent.

(f)PATRIOT Act. At least five days prior to the Effective Date, the Borrower shall have provided to the Agent and the Lenders the documentation and other information reasonably

33

requested by the Agent, and reasonably available to the Borrower, in order to comply with requirements of the PATRIOT Act.

(g)In the event that the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation, the Borrower shall deliver, at least five days prior to the Effective Date, a Beneficial Ownership Certification in relation to the Borrower.

(h)Concurrently with or before the Effective Date, the Agent shall receive evidence satisfactory to it that (i) all principal, interest and other amounts outstanding under the Borrower’s Existing Credit Agreement shall be repaid and satisfied in full and (ii) all commitments to extend credit under the Existing Credit Agreement shall be terminated.

Section 3.02Determinations Under Section 3.01. For purposes of determining compliance with the conditions specified in Section 3.01 and the satisfaction of each Lender with respect to letters delivered to it from the Borrower as set forth in Sections 4.01(a), 4.01(e) and 4.01(f), each Lender that has signed this Agreement shall be deemed to have consented to, approved or accepted or to be satisfied with each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to the Lenders unless an officer of the Agent responsible for the transactions contemplated by this Agreement shall have received notice from such Lender prior to the date that the Borrower designates as the proposed Effective Date, specifying its objection thereto. The Agent shall promptly notify the Lenders and the Borrower of the occurrence of the Effective Date.

ARTICLE IVREPRESENTATIONS AND WARRANTIES

Section 4.01Representations and Warranties of the Borrower. The Borrower represents and warrants as follows:

(a)Each of the Borrower and each Material Subsidiary: (i) is a corporation or other entity duly organized and validly existing under the Laws of the jurisdiction of its incorporation or organization; (ii) has all requisite corporate or if the Material Subsidiary is not a corporation, other comparable power necessary to own its assets and carry on its business as presently conducted; (iii) has all governmental licenses, authorizations, consents and approvals necessary to own its assets and carry on its business as presently conducted, if the failure to have any such license, authorization, consent or approval is reasonably likely to have a Material Adverse Effect and except as disclosed to the Agent in the SEC Reports or by means of a letter from the Borrower to the Lenders (such letter, if any, to be delivered to the Agent for prompt distribution to the Lenders) delivered prior to the execution and delivery of this Agreement (which, in each case, shall be satisfactory to each Lender in its sole discretion) and except that (A) APS from time to time may make minor extensions of its lines, plants, services or systems prior to the time a related franchise, certificate of convenience and necessity, license or permit is procured, (B) from time to time communities served by APS may become incorporated and considerable time may elapse before such a franchise is procured, (C) certain such franchises may have expired prior to the renegotiation thereof, (D) certain minor defects and exceptions may exist which, individually and in the aggregate, are not material and (E) certain

34

franchises, certificates, licenses and permits may not be specific as to their geographical scope); and (iv) is qualified to do business in all jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure so to qualify is reasonably likely to have a Material Adverse Effect.

(b)The execution, delivery and performance by the Borrower of this Agreement and the other Loan Documents, and the consummation of the transactions contemplated hereby and thereby, are within the Borrower’s corporate powers, have been duly authorized by all necessary corporate action, and do not or did not (i) contravene the Borrower’s articles of incorporation or by-laws, (ii) contravene any Law, decree, writ, injunction or determination of any Governmental Authority, in each case applicable to or binding upon the Borrower or any of its properties, (iii) contravene any contractual restriction binding on or affecting the Borrower or (iv) cause the creation or imposition of any Lien upon the assets of the Borrower or any Material Subsidiary, except for Liens created under this Agreement and except where such contravention or creation or imposition of such Lien is not reasonably likely to have a Material Adverse Effect.

(c)No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority is required for the due execution, delivery and performance by the Borrower of this Agreement or the Notes to be delivered by it.

(d)This Agreement has been, and each of the other Loan Documents upon execution and delivery will have been, duly executed and delivered by the Borrower. This Agreement is, and each of the other Loan Documents upon execution and delivery will be, the legal, valid and binding obligation of the Borrower enforceable against the Borrower in accordance with their respective terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar Laws affecting creditors’ rights generally.

(e)(i) The Consolidated balance sheet of the Borrower as of December 31, 2018, and the related Consolidated statements of income and cash flows of the Borrower for the fiscal year then ended, accompanied by an opinion thereon of Deloitte & Touche LLP, independent registered public accountants, and the Condensed Consolidated balance sheet of the Borrower as of March 31, 2019, and the related Condensed Consolidated statements of income and cash flows of the Borrower for the three months then ended, duly certified by the chief financial officer of the Borrower, copies of which have been furnished to the Agent, fairly present in all material respects, subject, in the case of said balance sheet as of March 31, 2019, and said statements of income and cash flows for the three months then ended, to year-end audit adjustments, the Consolidated financial condition of the Borrower as at such dates and the Consolidated results of the operations of the Borrower for the periods ended on such dates, all in accordance with GAAP (except as disclosed therein); and (ii) except as disclosed to the Agent in the SEC Reports or by means of a letter from the Borrower to the Lenders (such letter, if any, to be delivered to the Agent for prompt distribution to the Lenders) delivered prior to the execution and delivery of this Agreement (which, in each case, shall be satisfactory to each Lender in its sole discretion), since December 31, 2018, there has been no Material Adverse Effect.

35

(f)There is no pending or, to the knowledge of an Authorized Officer of the Borrower, threatened action, suit, investigation, litigation or proceeding, including, without limitation, any Environmental Action, affecting the Borrower or any of its Subsidiaries before any court, governmental agency or arbitrator that (i) purports to affect the legality, validity or enforceability of this Agreement or any other Loan Document or the consummation of the transactions contemplated hereby or (ii) would be reasonably likely to have a Material Adverse Effect (except as disclosed to the Agent in the SEC Reports or by means of a letter from the Borrower to the Lenders (such letter, if any, to be delivered to the Agent for prompt distribution to the Lenders) delivered prior to the execution and delivery of this Agreement (which, in each case, shall be satisfactory to each Lender in its sole discretion)), and there has been no adverse change in the status, or financial effect on the Borrower or any of its Subsidiaries, of such disclosed litigation that would be reasonably likely to have a Material Adverse Effect.

(g)No proceeds of any Loan will be used to acquire any equity security not issued by the Borrower of a class that is registered pursuant to Section 12 of the Securities Exchange Act of 1934.

(h)The Borrower is not engaged in the business of extending credit for the purpose of purchasing or carrying margin stock (within the meaning of Regulation U issued by the Board of Governors of the Federal Reserve System), and no proceeds of any Loan will be used to purchase or carry any margin stock or to extend credit to others for the purpose of purchasing or carrying any margin stock, in any case in violation of Regulation U. After application of the proceeds of any Loan, not more than 25% of the value of the assets subject to any restriction under this Agreement on the right to sell, pledge, transfer, or otherwise dispose of such assets is represented by margin stock.

(i)The Borrower and its Subsidiaries have filed all United States of America Federal income Tax returns and all other material Tax returns which are required to be filed by them and have paid all Taxes due pursuant to such returns or pursuant to any assessment received by the Borrower or any of its Subsidiaries, except to the extent that (i) such Taxes are being contested in good faith and by appropriate proceedings and that appropriate reserves for the payment thereof have been maintained by the Borrower and its Subsidiaries in accordance with GAAP or (ii) the failure to make such filings or such payments is not reasonably likely to have a Material Adverse Effect. The charges, accruals and reserves on the books of the Borrower and its Material Subsidiaries as set forth in the most recent financial statements of the Borrower delivered to the Agent pursuant to Section 4.01(e) or Section 5.01(h)(i) or 5.01(h)(ii) hereof in respect of Taxes and other governmental charges are, in the opinion of the Borrower, adequate.

(j)Set forth on Schedule 4.01(j) hereto (as such schedule may be modified from time to time by the Borrower by written notice to the Agent) is a complete and accurate list of all the Material Subsidiaries of the Borrower.

(k)Set forth on Schedule 4.01(k) hereto is a complete and accurate list identifying any Indebtedness of the Borrower outstanding in a principal amount equal to or exceeding $5,000,000 and which is not described in the financial statements referred to in Section 4.01(e).

36

(l)The Borrower is not an “investment company”, or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended.

(m)No report, certificate or other written information furnished by the Borrower or any of its Subsidiaries to the Agent, any Arranger or any Lender in connection with the transactions contemplated hereby and the negotiation of this Agreement or delivered hereunder or any other Loan Document (as modified or supplemented by other information so furnished) at the time so furnished, when taken together as a whole with all such written information so furnished, contains an untrue statement of a material fact or omits to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, except as would not reasonably be expected to result in a Material Adverse Effect; provided that with respect to any projected financial information, forecasts, estimates or forward-looking information, the Borrower represents only that such information and materials have been prepared in good faith on the basis of assumptions believed to be reasonable at the time of preparation of such forecasts, and no representation or warranty is made as to the actual attainability of any such projections, forecasts, estimates or forward-looking information.

(n)Neither the Borrower nor any of its Subsidiaries or, to the knowledge of the Borrower, any of their respective Affiliates over which any of the foregoing exercises management control (each, a “Controlled Affiliate”) or any director or officer of the Borrower, any of its Subsidiaries or any of their respective Controlled Affiliates (each, a “Manager”) is a Prohibited Person, and the Borrower, its Subsidiaries and, to the knowledge of the Borrower, such Controlled Affiliates are in compliance with all applicable orders, rules and regulations of OFAC.

(o)Neither the Borrower nor any of its Subsidiaries or, to the knowledge of the Borrower, any of their respective Controlled Affiliates or Managers: (i) is the target of Sanctions; (ii) is owned or controlled by, or acts on behalf of, any Person that is targeted by United States or multilateral economic or trade sanctions currently in force; (iii) is, or is owned or controlled by, a Person who is located, organized or resident in a country, region or territory that is, or whose government is, the subject of Sanctions, including, without limitation, Crimea, Cuba, Iran, North Korea, Sudan and Syria, or (iv) is named, identified or described on any list of Persons with whom United States Persons may not conduct business, including any such blocked persons list, designated nationals list, denied persons list, entity list, debarred party list, unverified list, sanctions list or other such lists published or maintained by the United States, including OFAC, the United States Department of Commerce or the United States Department of State, or any other applicable Governmental Authority.

(p)None of the Borrower’s or its Subsidiaries’ assets constitute property of, or are beneficially owned, directly or indirectly, by any Person that is the target of Sanctions, including but not limited to, the International Emergency Economic Powers Act, 50 U.S.C. §§ 1701 et seq., The Trading with the Enemy Act, 50 U.S.C. App. 1 et seq. (the “Trading With the Enemy Act”), any of the foreign assets control regulations of the Treasury (31 C.F.R., Subtitle B, Chapter V, as amended) (the “Foreign Assets Control Regulations”) or any enabling legislation or regulations promulgated thereunder or executive order relating thereto (which includes, without limitation, (i) Executive Order No. 13224, effective as of September 24, 2001, and relating to Blocking Property

37

and Prohibiting Transactions With Persons Who Commit, Threaten to Commit, or Support Terrorism (66 Fed. Reg. 49079 (2001)) (the “Executive Order”) and (ii) the PATRIOT Act), if the result of such ownership would be that any Borrowing made by any Lender would be in violation of law (“Embargoed Person”); (a) no Embargoed Person has any interest of any nature whatsoever in the Borrower if the result of such interest would be that any Borrowing would be in violation of law; (b) the Borrower has not engaged in business with Embargoed Persons if the result of such business would be that any Borrowing made by any Lender would be in violation of law; (c) the Borrower will not, directly or indirectly, use the proceeds of the Borrowing, or lend, contribute or otherwise make available such proceeds to any subsidiary, joint venture partner or other Person, (i) to fund any activities or business of or with any Person, or in any country or territory, that, at the time of such funding, is, or whose government is, the subject of Sanctions, or (ii) in any other manner that would result in a violation of Sanctions or Anti-Corruption Laws by any Person (including any Person participating in the Borrowing, whether as a Lender or otherwise), and (d) neither the Borrower nor any Controlled Affiliate (i) is or will become a “blocked person” as described in the Executive Order, the Trading With the Enemy Act or the Foreign Assets Control Regulations or (ii) to the knowledge of the Borrower, engages in any dealings or transactions, or be otherwise associated, with any such “blocked person”. For purposes of determining whether or not a representation is true under this Section 4.01(p), with respect to the securities of the Borrower, the Borrower shall not be required to make any investigation into (x) the ownership of publicly traded stock or other publicly traded securities or (y) the beneficial ownership of any collective investment fund.

(q)Neither the Borrower nor any of its Subsidiaries or, to the knowledge of the Borrower and its Subsidiaries, any of their respective Managers, has failed to comply with the U.S. Foreign Corrupt Practices Act, as amended from time to time (the “FCPA”), or any other applicable Anti-Corruption Laws, and it and they have not made, offered, promised or authorized, and will not make, offer, promise or authorize, whether directly or indirectly, any payment, of anything of value to a Government Official while knowing or having a reasonable belief that all or some portion will be used for the purpose of: (a) influencing any act, decision or failure to act by a Government Official in his or her official capacity, (b) inducing a Government Official to use his or her influence with a government or instrumentality to affect any act or decision of such  government or entity or (c) securing an improper advantage, in each case in order to obtain, retain or direct business.

(r)If Borrower is required to deliver a Beneficial Ownership Certification, as of the Effective Date, the information included in the Beneficial Ownership Certification, as updated from time to time in accordance with this Agreement, is accurate, complete and correct in all respects as of the date any such update is delivered. The Borrower acknowledges and agrees that the Beneficial Ownership Certification is one of the Loan Documents.

(s)The Borrower is not an EEA Financial Institution.

ARTICLE VCOVENANTS OF THE BORROWER

38

Section 5.01Affirmative Covenants. So long as any Loan shall remain unpaid, the Borrower shall:

(a)Compliance with Laws, Etc. (i) Comply, and cause each of its Material Subsidiaries to comply, in all material respects, with all applicable Laws of Governmental Authorities, such compliance to include, without limitation, compliance with ERISA and Environmental Laws, unless the failure to so comply is not reasonably likely to have a Material Adverse Effect and (ii) comply at all times with all Laws, orders, decrees, writs, injunctions or determinations of any Governmental Authority relating to the incurrence or maintenance of Indebtedness by the Borrower, such compliance to include, without limitation, compliance with the PATRIOT Act, all applicable orders, rules and regulations of OFAC, the FCPA, the Racketeer Influenced and Corrupt Organizations Chapter of the Organized Crime Control Act of 1970 and other Anti-Corruption Laws, except (other than in the case of the PATRIOT Act, the applicable orders, rules and regulations of OFAC, or the FCPA, or any similar applicable laws) to the extent that the failure to do so could not reasonably be expected to have a Material Adverse Effect.

(b)Payment of Taxes, Etc. Pay and discharge, and cause each of its Subsidiaries to pay and discharge, before the same shall become delinquent, all Taxes imposed upon it or upon its property; provided, however, that neither the Borrower nor any of its Subsidiaries shall be required to pay or discharge any such Tax (i) that is being contested in good faith and by proper proceedings and as to which appropriate reserves are being maintained in accordance with GAAP or (ii) if the failure to pay such Tax is not reasonably likely to have a Material Adverse Effect.

(c)Maintenance of Insurance. Maintain, and cause each of its Material Subsidiaries to maintain, insurance with responsible and reputable insurance companies or associations in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties in the same general areas in which the Borrower or such Subsidiary operates; provided, however, that the Borrower and its Subsidiaries may self-insure to the same extent as other companies engaged in similar businesses and owning similar properties in the same general areas in which the Borrower or such Subsidiary operates and to the extent consistent with prudent business practice.

(d)Preservation of Corporate Existence, Etc. Preserve and maintain, and cause each of its Material Subsidiaries to preserve and maintain, its corporate existence, rights (charter and statutory) and franchises (other than “franchises” as described in Arizona Revised Statutes, Section 40-283 or any successor provision) reasonably necessary in the normal conduct of its business, if the failure to maintain such rights or privileges is reasonably likely to have a Material Adverse Effect, and, in the case of APS, will cause APS to use its commercially reasonable efforts to preserve and maintain such franchises reasonably necessary in the normal conduct of its business, except that (i) APS from time to time may make minor extensions of its lines, plants, services or systems prior to the time a related franchise, certificate of convenience and necessity, license or permit is procured, (ii) from time to time communities served by APS may become incorporated and considerable time may elapse before such a franchise is procured, (iii) certain such franchises may have expired prior to the renegotiation thereof, (iv) certain minor defects and exceptions may exist which, individually and in the aggregate, are not material and (v) certain franchises, certificates,

39

licenses and permits may not be specific as to their geographical scope; provided, however, that the Borrower and its Subsidiaries may consummate any merger or consolidation permitted under Section 5.02(b).

(e)Visitation Rights. At any reasonable time and from time to time, permit and cause each of its Subsidiaries to permit the Agent or any of the Lenders or any agents or representatives thereof, to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, the Borrower and any of its Subsidiaries, and to discuss the affairs, finances and accounts of the Borrower and any of its Subsidiaries with any of their officers or directors; provided, however, that the Borrower and its Subsidiaries reserve the right to restrict access to any of its properties in accordance with reasonably adopted procedures relating to safety and security; and providedfurther that the costs and expenses incurred by such Lender or its agents or representatives in connection with any such examinations, copies, abstracts, visits or discussions shall be, upon the occurrence and during the continuation of a Default, for the account of the Borrower and, in all other circumstances, for the account of such Lender.

(f)Keeping of Books. Keep, and cause each of its Material Subsidiaries to keep, proper books of record and account, in which full and correct entries shall be made of all financial transactions and the assets and business of the Borrower and each such Subsidiary in a manner that permits the preparation of financial statements in accordance with GAAP.

(g)Maintenance of Properties, Etc. Keep, and cause each Material Subsidiary to keep, all property useful and necessary in its business in good working order and condition (ordinary wear and tear excepted), if the failure to do so is reasonably likely to have a Material Adverse Effect, it being understood that this covenant relates only to the working order and condition of such properties and shall not be construed as a covenant not to dispose of properties.

(h)Reporting Requirements. Furnish to the Agent:

(i)as soon as available and in any event within 50days after the end of each of the first three fiscal quarters of each fiscal year of the Borrower, commencing with the fiscal quarter ending June 30, 2019, (A) for each such fiscal quarter of the Borrower, Consolidated statements of income and cash flows of the Borrower for such fiscal quarter and the related Consolidated balance sheet of the Borrower as of the end of such fiscal quarter, setting forth in each case in comparative form the corresponding figures for the corresponding fiscal quarter in (or, in the case of the balance sheet, as of the end of) the preceding fiscal year and (B) for the period commencing at the end of the previous fiscal year and ending with the end of such fiscal quarter, Consolidated statements of income and cash flows of the Borrower for such period setting forth in each case in comparative form the corresponding figures for the corresponding period in the preceding fiscal year; provided that so long as the Borrower remains subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the Borrower may provide, in satisfaction of the requirements of this first sentence of this Section 5.01(h)(i), its report on Form 10-Q for such fiscal quarter. Each set of financial statements provided under this Section 5.01(h)(i) shall be accompanied by a certificate of an Authorized Officer, which certificate shall state that said Consolidated financial statements fairly present in all material respects the Consolidated financial condition and

40

results of operations and cash flows of the Borrower in accordance with GAAP (except as disclosed therein), as at the end of, and for, such period (subject to normal year-end audit adjustments) and shall set forth reasonably detailed calculations demonstrating compliance with Section 5.03;

(ii)as soon as available and in any event within 90 days after the end of each fiscal year of the Borrower, commencing with the fiscal year ending December 31, 2019, audited Consolidated statements of income and cash flows of the Borrower for such year and the related Consolidated balance sheet of the Borrower as at the end of such year, setting forth in each case in comparative form the corresponding figures for the preceding fiscal year; provided that, so long as the Borrower remains subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the Borrower may provide, in satisfaction of the requirements of this first sentence of this Section 5.01(h)(ii), its report on Form 10-K for such fiscal year. Each set of financial statements provided pursuant to this Section 5.01(h)(ii) shall be accompanied by (A) an opinion thereon of independent certified public accountants of recognized national standing, which opinion shall state that said Consolidated financial statements fairly present in all material respects the Consolidated financial condition and results of operations of the Borrower as at the end of, and for, such fiscal year, in accordance with GAAP (except as disclosed therein) and (B) a certificate of an Authorized Officer, which certificate shall set forth reasonably detailed calculations demonstrating compliance with Section 5.03;

(iii)as soon as possible and in any event within five days after any Authorized Officer of the Borrower knows of the occurrence of each Default continuing on the date of such statement, a statement of an Authorized Officer of the Borrower setting forth details of such Default and the action that the Borrower has taken and proposes to take with respect thereto;

(iv)promptly after the sending or filing thereof, copies of all reports and registration statements (other than exhibits thereto and registration statements on Form S-8 or its equivalent) that the Borrower or any Subsidiary files with the Securities and Exchange Commission;

(v)promptly after an Authorized Officer becomes aware of the commencement thereof, notice of all actions and proceedings before any court, governmental agency or arbitrator affecting the Borrower or any of its Subsidiaries of the type described in Section 4.01(f), except, with respect to any matter referred to in Section 4.01(f)(ii), to the extent disclosed in a report on Form 8-K, Form 10-Q or Form 10-K of the Borrower;

(vi)[intentionally omitted];

(vii)promptly after the occurrence thereof, notice of the occurrence of any ERISA Event, together with (x) a written statement of an Authorized Officer of the Borrower specifying the details of such ERISA Event and the action that the Borrower has taken and proposes to take with respect thereto, (y) a copy of any notice with respect to such ERISA

41

Event that may be required to be filed with the PBGC and (z) a copy of any notice delivered by the PBGC to the Borrower or an ERISA Affiliate with respect to such ERISA Event;

(viii)as soon as possible and in any event within five days after any Authorized Officer of the Borrower knows of the occurrence thereof, notice of any change in the information provided in the Beneficial Ownership Certification that would result in a change to the list of beneficial owners identified in parts (c) or (d) of such certification; and

(ix)promptly following request therefor, (a) such information and documentation reasonably requested by the Agent or any Lender for purposes of compliance with applicable “know your customer” requirements under the PATRIOT Act or other applicable anti-money laundering laws; (b) confirmation of the accuracy of the information set forth in the most recent Beneficial Ownership Certification provided to the Agent and Lenders; or (c) such other information respecting the Borrower or any of its Subsidiaries as any Lender through the Agent may from time to time reasonably request.

Information required to be delivered pursuant to Section 5.01(h)(i), Section 5.01(h)(ii) and Section 5.01(h)(iv) above shall be deemed to have been delivered on the date on which the Borrower provides notice to the Agent that such information has been posted on the Borrower’s website on the Internet at www.pinnaclewest.com, at sec.gov/edaux/searches.htm or at another website identified in such notice and accessible by the Lenders without charge; provided that (i) such notice may be included in a certificate delivered pursuant to Section 5.01(h)(i) or Section 5.01(h)(ii) and (ii) the Borrower shall deliver paper copies of the information referred to in Section 5.01(h)(i), Section 5.01(h)(ii), and Section 5.01(h)(iv) to any Lender which requests such delivery.

(i)Change in Nature of Business. Conduct directly or through its Subsidiaries the same general type of business conducted by the Borrower and its Material Subsidiaries on the date hereof.

Section 5.02Negative Covenants. So long as any Loan shall remain unpaid, the Borrower shall not:

(a)Liens, Etc. Directly or indirectly create, incur, assume or permit to exist any Lien securing Indebtedness for borrowed money on or with respect to any property or asset (including, without limitation, the capital stock of APS) of the Borrower, whether now owned or held or hereafter acquired (unless it makes, or causes to be made, effective provision whereby the Obligations will be equally and ratably secured with any and all other obligations thereby secured so long as such other Indebtedness shall be so secured, such security to be pursuant to an agreement reasonably satisfactory to the Required Lenders); provided, however, that this Section 5.02(a) shall not apply to Liens securing Indebtedness for borrowed money (other than Indebtedness for borrowed money secured by the capital stock of APS) which do not in the aggregate exceed at any time outstanding the principal amount of $50,000,000.

(b)Mergers, Etc. Merge or consolidate with or into any Person, or permit any of its Material Subsidiaries to do so, except that (i) any Material Subsidiary of the Borrower may merge or consolidate with or into any other Material Subsidiary of the Borrower, (ii) any Subsidiary of the Borrower may merge into the Borrower or any Material Subsidiary of the Borrower and (iii)

42

the Borrower or any Material Subsidiary may merge with any other Person so long as the Borrower or such Material Subsidiary is the surviving corporation, provided, in each case, that no Default shall have occurred and be continuing at the time of such proposed transaction or would result therefrom.

(c)Sales, Etc. of Assets. Sell, lease, transfer or otherwise dispose of, or permit any of its Material Subsidiaries to sell, lease, transfer or otherwise dispose of, any assets, or grant any option or other right to purchase, lease or otherwise acquire any assets to any Person other than the Borrower or any Subsidiary of the Borrower, except (i) dispositions in the ordinary course of business, including, without limitation, sales or other dispositions of electricity and related and ancillary services, other commodities, emissions credits and similar mechanisms for reducing pollution, and damaged, obsolete, worn out or surplus property no longer required or useful in the business or operations of the Borrower or any of its Subsidiaries, (ii) sale or other disposition of patents, copyrights, trademarks or other intellectual property that are, in the Borrower’s reasonable judgment, no longer economically practicable to maintain or necessary in the conduct of the business of the Borrower or its Subsidiaries and any license or sublicense of intellectual property that does not interfere with the business of the Borrower or any Material Subsidiary, (iii) in a transaction authorized by subsection (b) of this Section, (iv) individual dispositions occurring in the ordinary course of business which involve assets with a book value not exceeding $5,000,000, (v) sales, leases, transfers or dispositions of assets during the term of this Agreement having an aggregate book value not to exceed 30% of the total of all assets properly appearing on the most recent balance sheet of the Borrower provided pursuant to Section 4.01(e)(i) or Section 5.01(h)(ii) hereof, (vi) at any time following the consummation of the Four Corners Acquisition, which occurred on December 30, 2013, and the closure by APS of Units 1, 2 and 3 of the Four Corners Power Plant near Farmington, New Mexico, as described in the SEC Reports, (A) disposition of all or any portion of APS’ interests in such Units 1, 2 and 3, or (B) disposition of all or any portion of any Subsidiary’s (other than APS) interests in Units 4 and 5 of the Four Corners Power Plant near Farmington, New Mexico, and (vii) any Lien permitted under Section 5.02(a).

(d)Ownership of APS. Except to the extent permitted under Section 5.02(b), cease at any time to own directly or indirectly at least 80% of the outstanding capital stock of APS.

Section 5.03Financial Covenant. So long as any Loan shall remain unpaid, the Borrower will maintain a ratio of (a) Consolidated Indebtedness to (b) the sum of Consolidated Indebtedness plus Consolidated Net Worth of not greater than 0.65 to 1.0.

ARTICLE VIEVENTS OF DEFAULT

Section 6.01Events of Default. If any of the following events (“Events of Default”) shall occur and be continuing:

(a)The Borrower shall fail to pay when due (i) any principal of any Loan or (ii) any interest on any Loan or any fees or other amounts payable under this Agreement or any other Loan

43

Documents, and (in the case of this clause (ii) only) such failure shall continue for a period of three Business Days; or

(b)Any representation or warranty made by the Borrower herein or by the Borrower (or any of its officers) in any certificate or other document delivered in connection with this Agreement or any other Loan Document shall prove to have been incorrect in any material respect when made or deemed made or furnished; or

(c)(i) The Borrower shall fail to perform or observe any term, covenant or agreement contained in Section 2.15, Section 5.01(d) (as to the corporate existence of the Borrower), Section 5.01(h)(iii), Section 5.01(h)(vi), Section 5.02 or Section 5.03; or (ii) the Borrower shall fail to perform or observe any term, covenant or agreement contained in Section 5.01(e) if such failure shall remain unremedied for 15 days after written notice thereof shall have been given to the Borrower by the Agent or any Lender; or (iii) the Borrower shall fail to perform or observe any other term, covenant or agreement contained in this Agreement or any other Loan Document on its part to be performed or observed if such failure shall remain unremedied for 30 days after written notice thereof shall have been given to the Borrower by the Agent or any Lender; or

(d)(i) The Borrower or any of its Material Subsidiaries shall fail to pay (A) any principal of or premium or interest on any Indebtedness that is outstanding in a principal amount of at least $35,000,000 in the aggregate (but excluding Indebtedness outstanding hereunder), or (B) an amount, or post collateral as contractually required in an amount, of at least $35,000,000 in respect of any Hedge Agreement, of the Borrower or such Material Subsidiary (as the case may be), in each case, when the same becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Indebtedness or Hedge Agreement; or (ii) any event of default shall exist under any agreement or instrument relating to any such Indebtedness and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such event is to accelerate, or to permit the acceleration of, the maturity of such Indebtedness; or

(e)The Borrower or any of its Material Subsidiaries shall fail to pay any principal of or premium or interest in respect of any operating lease in respect of which the payment obligations of the Borrower have a present value of at least $35,000,000, when the same becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in such operating lease, if the effect of such failure is to terminate, or to permit the termination of, such operating lease; or

(f)The Borrower or any of its Material Subsidiaries shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower or any of its Material Subsidiaries seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any Debtor Relief Law, or seeking the entry of an order for relief or the appointment of a receiver, trustee, custodian or other similar official for it or for

44

any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it), either such proceeding shall remain undismissed or unstayed for a period of 60 days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or the Borrower or any of its Material Subsidiaries shall take any corporate action to authorize any of the actions set forth above in this subsection (f); or

(g)Judgments or orders for the payment of money that exceed any applicable insurance coverage (the insurer of which shall be rated at least “A” by A.M. Best Company) by more than $35,000,000 in the aggregate shall be rendered against the Borrower or any Material Subsidiary and such judgments or orders shall continue unsatisfied or unstayed for a period of 45 days; or

(h)(i) Any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, but excluding any employee benefit plan of such person or its subsidiaries, and any person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan) becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934), directly or indirectly, of 30% or more of the equity securities of the Borrower entitled to vote for members of the board of directors of the Borrower; or (ii) during any period of 24 consecutive months, a majority of the members of the board of directors of the Borrower cease (other than due to death or disability) to be composed of individuals (A) who were members of that board on the first day of such period, (B) whose election or nomination to that board was approved by individuals referred to in clause (A) above constituting at the time of such election or nomination at least a majority of that board or (C) whose election or nomination to that board was approved by individuals referred to in clauses (A) and (B) above constituting at the time of such election or nomination at least a majority of that board; or

(i)(i) An ERISA Event occurs with respect to a Pension Plan or Multiemployer Plan which has resulted or could reasonably be expected to result in liability of the Borrower under Title IV of ERISA to the Pension Plan, Multiemployer Plan or the PBGC in an aggregate amount in excess of $35,000,000; or (ii) the Borrower or any ERISA Affiliate fails to pay when due, after the expiration of any applicable grace period, any installment payment with respect to its withdrawal liability under Section 4201 of ERISA under a Multiemployer Plan in an aggregate amount in excess of $35,000,000;

then, and in any such event, the Agent shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, (i) declare the Loans, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon the Loans, all such interest and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower; provided, however, that in the event of an actual or deemed entry of an order for relief with respect to the Borrower under the Bankruptcy Code of the United States of America, the Loans, all such interest and all such amounts shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived

45

by the Borrower, and (ii) exercise all rights and remedies available to it under this Agreement, the other Loan Documents and applicable Law.

ARTICLE VIITHE AGENT

Section 7.01Appointment and Authority. Each of the Lenders hereby irrevocably appoints PNC Bank, National Association to act on its behalf as the Agent hereunder and under the other Loan Documents and authorizes the Agent to take such actions on its behalf and to exercise such powers as are delegated to the Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. Except as set forth in Section 7.06, the provisions of this Article are solely for the benefit of the Agent and the Lenders, and neither the Borrower nor any of its Affiliates shall have rights as a third party beneficiary of any of such provisions.

Section 7.02Rights as a Lender. The Person serving as the Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Agent and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context otherwise requires, include the Person serving as the Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, act as the financial advisor or in any other advisory capacity for and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if such Person were not the Agent hereunder and without any duty to account therefor to the Lenders.

Section 7.03Exculpatory Provisions. The Agent shall not have any duties or obligations except those expressly set forth herein and in the other Loan Documents. Without limiting the generality of the foregoing, the Agent:

(a)shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing;

(b)shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein), provided that the Agent shall not be required to take any action that, in its opinion or the opinion of its counsel, may expose the Agent to liability or that is contrary to any Loan Document or applicable Law; and

(c)shall not, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Affiliates that is communicated to or obtained by the Person serving as the Agent or any of its Affiliates in any capacity.

The Agent shall not be liable for any action taken or not taken by it (i) with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary, or as the Agent shall believe in good faith shall be necessary, under the circumstances

46

as provided in Section 6.01 and Section 8.01) or (ii) in the absence of its own gross negligence or willful misconduct as determined by a final, non-appealable judgment by a court of competent jurisdiction. The Agent shall be deemed not to have knowledge of any Default unless and until notice describing such Default is given to the Agent by the Borrower or a Lender.

The Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document or (v) the satisfaction of any condition set forth in Article III or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Agent.

Section 7.04Reliance by Agent. The Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of any Loan that by its terms must be fulfilled to the satisfaction of a Lender, the Agent may presume that such condition is satisfactory to such Lender unless the Agent shall have received notice to the contrary from such Lender prior to the making of such Loan. The Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in good faith in accordance with the advice of any such counsel, accountants or experts.

Section 7.05Delegation of Duties. The Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub-agents appointed by the Agent. The Agent and any such sub-agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Article shall apply to any such sub-agent and to the Related Parties of the Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Agent.

Section 7.06Resignation of Agent. The Agent may at any time give notice of its resignation to the Lenders and the Borrower. Upon receipt of any such notice of resignation, the Required Lenders shall have the right, with the consent of the Borrower so long as no Event of Default has occurred and is continuing, to appoint a successor, which shall be a bank with an office in the United States of America, or an Affiliate of any such bank with an office in the United States of America. If no such successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 45 days after the retiring Agent gives notice of its resignation,

47

then the retiring Agent may, on behalf of the Lenders, appoint a successor Agent meeting the qualifications set forth above; provided that if the Agent shall notify the Borrower and the Lenders that no qualifying Person has accepted such appointment, then such resignation shall nonetheless become effective in accordance with such notice and (1) the retiring Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents (except that in the case of any collateral security held by the Agent on behalf of the Lenders under any of the Loan Documents, the retiring Agent shall continue to hold such collateral security until such time as a successor Agent is appointed) and (2) all payments, communications and determinations provided to be made by, to or through the Agent shall instead be made by or to each Lender directly, until such time as the Required Lenders appoint a successor Agent as provided for above in this Section. Upon the acceptance of a successor’s appointment as Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Agent, and the retiring Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents (if not already discharged therefrom as provided above in this Section). The fees payable by the Borrower to a successor Agent shall be as agreed between the Borrower and such successor. After the retiring Agent’s resignation hereunder and under the other Loan Documents, the provisions of this Article and Section 8.04 shall continue in effect for the benefit of such retiring Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Agent was acting as Agent.

Section 7.07Non-Reliance on Agent and Other Lenders. Each Lender acknowledges that it has, independently and without reliance upon the Agent or any other Lender or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Agent or any other Lender or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder.

Section 7.08No Other Duties, Etc. Anything herein to the contrary notwithstanding, none of the Arrangers, the Syndication Agent or any other agents listed on the cover page hereof shall have any powers, duties or responsibilities under this Agreement or any of the other Loan Documents, except in its capacity, as applicable, as the Agent or a Lender hereunder.

Section 7.09Certain ERISA Matters.

(a)Each Lender (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Agent and the Arrangers and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that at least one of the following is and will be true:

(i)such Lender is not using “plan assets” (within the meaning of 29 CFR § 2510.3-101, as modified by Section 3(42) of ERISA) of one or more Benefit Plans in connection with the Loans or the Commitments,

48

(ii)the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement,

(iii)(A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Loans, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement, or

(iv)such other representation, warranty and covenant as may be agreed in writing between the Agent, in its sole discretion, and such Lender.

(b)In addition, unless sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or such Lender has not provided another representation, warranty and covenant as provided in sub-clause (iv) in the immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Agent and the Arrangers and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that:

(i)none of the Agent or the Arrangers, or any of their respective Affiliates is a fiduciary with respect to the assets of such Lender (including in connection with the reservation or exercise of any rights by the Agent under this Agreement, any Loan Document or any documents related to hereto or thereto),

(ii)the Person making the investment decision on behalf of such Lender with respect to the entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement is independent (within the meaning of 29 CFR § 2510.3-21) and is a bank, an insurance carrier, an investment adviser, a broker-dealer or other person that holds, or has under management or control, total assets of at least $50 million, in each case as described in 29 CFR § 2510.3-21(c)(1)(i)(A)-(E),

(iii)the Person making the investment decision on behalf of such Lender with respect to the entrance into, participation in, administration of and performance of the Loans,

49

the Commitments and this Agreement is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies (including in respect of the Obligations),

(iv)the Person making the investment decision on behalf of such Lender with respect to the entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement is a fiduciary under ERISA or the Internal Revenue Code, or both, with respect to the Loans, the Commitments and this Agreement and is responsible for exercising independent judgment in evaluating the transactions hereunder, and

(v)no fee or other compensation is being paid directly to the Agent or the Arrangers or any their respective Affiliates for investment advice (as opposed to other services) in connection with the Loans, the Commitments or this Agreement.

(c)The Agent and the Arrangers hereby inform the Lenders that each such Person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity, in connection with the transactions contemplated hereby, and that such Person has a financial interest in the transactions contemplated hereby in that such Person or an Affiliate thereof (i) may receive interest or other payments with respect to the Loans, the Commitments and this Agreement, (ii) may recognize a gain if it extended the Loans or the Commitments for an amount less than the amount being paid for an interest in the Loans or the Commitments by such Lender or (iii) may receive fees or other payments in connection with the transactions contemplated hereby, the Loan Documents or otherwise, including structuring fees, commitment fees, arrangement fees, facility fees, upfront fees, underwriting fees, ticking fees, agency fees, administrative agent or collateral agent fees, utilization fees, minimum usage fees, letter of credit fees, fronting fees, deal-away or alternate transaction fees, amendment fees, processing fees, term out premiums, banker’s acceptance fees, breakage or other early termination fees or fees similar to the foregoing.

ARTICLE VIIIMISCELLANEOUS

Section 8.01Amendments, Etc. No amendment or waiver of any provision of this Agreement or any other Loan Document, nor consent to any departure by the Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Required Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall

(a)unless agreed to by each Lender directly affected thereby, (i) reduce or forgive the principal amount of any Loan, reduce the rate of or forgive any interest thereon (provided that only the consent of the Required Lenders shall be required to waive the applicability of any post-default increase in interest rates), or reduce or forgive any fees hereunder (other than fees payable to the Agent or the Arrangers for their own respective accounts), (ii) extend the final scheduled maturity date or any other scheduled date for the payment of any principal of or interest on any Loan, or extend the time of payment of any fees hereunder (other than fees payable to the Agent or the

50

Arrangers for their own respective accounts), or (iii) increase any Commitment of any such Lender over the amount thereof in effect or extend the maturity thereof (it being understood that a waiver of any Default, if agreed to by the Required Lenders or all Lenders (as may be required hereunder with respect to such waiver), shall not constitute such an increase);

(b)unless agreed to by all of the Lenders, (i) reduce the percentage of the aggregate Commitments or of the aggregate unpaid principal amount of the Loans, or the number or percentage of Lenders, that shall be required for the Lenders or any of them to take or approve, or direct the Agent to take, any action hereunder or under any other Loan Document (including as set forth in the definition of “Required Lenders”), (ii) change any other provision of this Agreement or any of the other Loan Documents requiring, by its terms, the consent or approval of all the Lenders for any amendment, modification, waiver, discharge or termination thereof or any consent to any departure by the Borrower therefrom, or (iii) change or waive any provision of Section 2.13, any other provision of this Agreement or any other Loan Document requiring pro rata treatment of any Lenders, or this Section 8.01 or Section 2.17(b); and

(c)unless agreed to by the Agent in addition to the Lenders required as provided hereinabove to take such action, affect the respective rights or obligations of the Agent hereunder or under any of the other Loan Documents.

(d)If, in connection with any proposed amendment, waiver or consent requiring the consent of “each Lender” or “each Lender directly affected thereby,” the consent of the Required Lenders is obtained, but the consent of other necessary Lenders is not obtained (any such Lender whose consent is necessary but not obtained being referred to herein as a “Non-Consenting Lender”), then the Borrower may elect to replace a Non-Consenting Lender as a Lender party to this Agreement, provided that, concurrently with such replacement, (i) another bank or other entity which is reasonably satisfactory to the Borrower and the Agent shall agree, as of such date, to purchase for cash the Loans and other Obligations due to the Non-Consenting Lender pursuant to an Assignment and Assumption and to become a Lender for all purposes under this Agreement and to assume all obligations of the Non-Consenting Lender to be terminated as of such date and to comply with the requirements of clause (b) of Section 8.07, and (ii) the Borrower shall pay to such Non-Consenting Lender in same day funds on the day of such replacement (1) all interest, fees and other amounts then accrued but unpaid to such Non-Consenting Lender by the Borrower hereunder to and including the date of termination, including without limitation payments due to such Non-Consenting Lender under Sections 2.09 and 2.12, and (2) an amount, if any, equal to the payment which would have been due to such Lender on the day of such replacement under Section 8.04(e) had the Loans of such Non-Consenting Lender been prepaid on such date rather than sold to the replacement Lender.

Section 8.02Notices, Etc.

(a)All notices and other communications provided for hereunder shall be either (x) in writing (including facsimile communication) and mailed, faxed or delivered or (y) delivered, furnished, distributed or made available as and to the extent set forth in Sections 8.02(b) and (c), if to the Borrower, at the address specified on Schedule 8.02; if to any Lender, at its Domestic Lending Office; and if to the Agent, at the address specified on Schedule 8.02; or, as to the Borrower or the Agent, at such other address as shall be designated by such party in a written notice to the other

51

parties and, as to each other party, at such other address as shall be designated by such party in a written notice to the Borrower and the Agent. All such notices and communications shall, when mailed or faxed, be effective when deposited in the mails or faxed, respectively, except that notices and communications to the Agent pursuant to Article II, Article III or Article VII shall not be effective until received by the Agent. Delivery by facsimile of an executed counterpart of any amendment or waiver of any provision of this Agreement or the Notes or of any Exhibit hereto to be executed and delivered hereunder shall be effective as delivery of a manually executed counterpart thereof. Notices delivered through electronic communications to the extent provided in subsection (b) below, shall be effective as provided in such subsection (b). Upon request of the Borrower, the Agent will provide to the Borrower (i) copies of each Administrative Questionnaire or (ii) the address of each Lender.

(b)Notices and other communications to the Lenders and the Agent hereunder may be delivered or furnished by electronic communication (including e-mail and Internet or intranet websites) pursuant to procedures approved by the Agent and agreed to by the Borrower, provided that the foregoing shall not apply to notices to any Lender pursuant to Article II if such Lender has notified the Agent and the Borrower that it is incapable of receiving notices under such Article by electronic communication. The Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it, provided that approval of such procedures may be limited to particular notices or communications. Unless the Agent and the Borrower otherwise agree, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next Business Day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.

(c)The Borrower agrees that the Agent may make materials delivered to the Agent pursuant to Section 5.01(h)(i), Section 5.01(h)(ii) and Section 5.01(h)(iv), as well as any other written information, documents, instruments and other material relating to the Borrower or any of its Subsidiaries and relating to this Agreement, the Notes or the transactions contemplated hereby, or any other materials or matters relating to this Agreement, the Notes or any of the transactions contemplated hereby (collectively, the “Communications”) available to the Lenders by posting such notices on Intralinks or a substantially similar electronic system (the “Platform”). The Borrower acknowledges that (i) the distribution of material through an electronic medium is not necessarily secure and that there are confidentiality and other risks associated with such distribution, (ii) the Platform is provided “as is” and “as available” and (iii) neither the Agent nor any of its Affiliates warrants the accuracy, adequacy or completeness of the Communications or the Platform and each expressly disclaims liability for errors or omissions in the Communications or the Platform. No warranty of any kind, express, implied or statutory, including, without limitation, any warranty of merchantability, fitness for a particular purpose, non-infringement of third party rights or freedom

52

from viruses or other code defects, is made by the Agent or any of its Affiliates in connection with the Platform.

(d)Each Lender agrees that notice to it (as provided in the next sentence) (a “Notice”) specifying that any Communications have been posted to the Platform shall constitute effective delivery of such information, documents or other materials to such Lender for purposes of this Agreement; provided that if requested by any Lender the Agent shall deliver a copy of the Communications to such Lender by e-mail, facsimile or mail. Each Lender agrees (i) to notify the Agent in writing of such Lender’s e-mail address to which a Notice may be sent by electronic transmission (including by electronic communication) on or before the date such Lender becomes a party to this Agreement (and from time to time thereafter to ensure that the Agent has on record an effective e-mail address for such Lender) and (ii) that any Notice may be sent to such e-mail address.

(e)The Borrower hereby acknowledges that certain of the Lenders may be “public-side” Lenders (i.e., Lenders that do not wish to receive material non-public information with respect to the Borrower or its securities) (each, a “Public Lender”). The Borrower hereby agrees that (w) all Communications that are to be made available to Public Lenders shall be clearly and conspicuously marked “PUBLIC” which shall mean that the word “PUBLIC” shall appear prominently on the first page thereof; (x) by marking Communications “PUBLIC,” the Borrower shall be deemed to have authorized the Agent, the Arrangers and the Lenders to treat such Communications as not containing any material non-public information with respect to the Borrower or its securities for purposes of United States of America federal and state securities laws; (y) all Communications marked “PUBLIC” are permitted to be made available through a portion of the Platform designated as “Public Investor;” and (z) the Agent and the Arrangers shall be entitled to treat any Communications that are not marked “PUBLIC” as being suitable only for posting on a portion of the Platform not marked as “Public Investor.” Notwithstanding the foregoing, the Borrower shall be under no obligation to mark any Communications “PUBLIC.” Notwithstanding anything to the contrary herein, the Borrower and the Agent need not provide to any Public Lender any information, notice, or other document hereunder that is not public information, including without limitation, the Notice of Initial Borrowing and any notice of Default.

Section 8.03No Waiver; Cumulative Remedies; Enforcement. No failure by any Lender or the Agent to exercise, and no delay by any such Person in exercising, any right, remedy, power or privilege hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by Law.

Notwithstanding anything to the contrary contained herein or in any other Loan Document, the authority to enforce rights and remedies hereunder and under the other Loan Documents against the Borrower shall be vested exclusively in, and all actions and proceedings at Law in connection with such enforcement shall be instituted and maintained exclusively by, the Agent in accordance with Article VI for the benefit of all the Lenders; provided, however, that the foregoing shall not

53

prohibit (a) the Agent from exercising on its own behalf the rights and remedies that inure to its benefit (solely in its capacity as Agent) hereunder and under the other Loan Documents, (b) any Lender from exercising setoff rights in accordance with Section 8.05 (subject to the terms of Section 2.13), or (c) any Lender from filing proofs of claim or appearing and filing pleadings on its own behalf during the pendency of a proceeding relative to the Borrower under any Debtor Relief Law; and provided, further, that if at any time there is no Person acting as Agent hereunder and under the other Loan Documents, then (i) the Required Lenders shall have the rights otherwise ascribed to the Agent pursuant to Article VI and (ii) in addition to the matters set forth in clauses (b) and (c) of the preceding proviso and subject to Section 2.13, any Lender may, with the consent of the Required Lenders, enforce any rights and remedies available to it and as authorized by the Required Lenders.

Section 8.04Costs and Expenses; Indemnity; Damage Waiver.

(a)The Borrower agrees to pay on demand all costs and expenses of the Agent in connection with the administration, modification and amendment of this Agreement, the Notes and the other Loan Documents to be delivered hereunder, including, without limitation, the reasonable fees and expenses of one law firm acting as counsel for the Agent with respect thereto and with respect to advising the Agent as to its rights and responsibilities under this Agreement. The Borrower further agrees to pay on demand all costs and expenses of the Agent and the Lenders, if any (including, without limitation, reasonable counsel fees and expenses), in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement, the Notes and the other Loan Documents to be delivered hereunder, including, without limitation, reasonable fees and expenses of counsel for the Agent and each Lender in connection with the enforcement of rights under this Section 8.04(a).

(b)The Borrower agrees to indemnify and hold harmless the Agent (and any sub-agent thereof), each Lender, each Arranger, the Syndication Agent and each Related Party of any of the foregoing (each, an “Indemnified Party”) from and against any and all claims, damages, losses, liabilities and expenses (including, without limitation, reasonable fees and expenses of counsel) incurred by or asserted or awarded against any Indemnified Party, in each case arising out of or in connection with or by reason of (including, without limitation, in connection with any investigation, litigation or proceeding or preparation of a defense in connection therewith, whether based on contract, tort or any other theory) (i) the Notes, this Agreement, any other Loan Document, any of the transactions contemplated herein or the actual or proposed use of the proceeds of any Loan, in each case, whether or not the transactions contemplated herein or therein are consummated, or (ii) the actual or alleged presence of Hazardous Materials on any property of the Borrower or any of its Subsidiaries or any Environmental Action relating in any way to the Borrower or any of its Subsidiaries, provided that such indemnity shall not, as to any Indemnified Party, be available to the extent (a) such fees and expenses are expressly stated in this Agreement to be payable by the Indemnified Party, included expenses payable under Section 2.12, Section 5.01(e) and Section 8.07(b) or (b) such claim, damage, loss, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence, willful misconduct or material breach of its obligations under this Agreement, in which case any fees and expenses previously paid or advanced by the Borrower to such Indemnified Party in respect of such indemnified obligation will be returned by such Indemnified Party. In the case

54

of an investigation, litigation or other proceeding to which the indemnity in this Section 8.04(b) applies, such indemnity shall be effective whether or not such investigation, litigation or proceeding is brought by the Borrower, its directors, equityholders or creditors or an Indemnified Party or any other Person, whether or not any Indemnified Party is otherwise a party thereto, and whether or not the transactions contemplated hereby are consummated, provided that if the Borrower and such Indemnified Party are adverse parties in any such litigation or proceeding, and the Borrower prevails in a final, non-appealable judgment by a court of competent jurisdiction, any amounts under this Section 8.04(b) previously paid or advanced by the Borrower to such Indemnified Party pursuant to this Section 8.04(b) will be returned by such Indemnified Party.

(c)To the extent that the Borrower for any reason fails to indefeasibly pay any amount required under subsection (a) or (b) of this Section to be paid by it to the Agent (or any sub-agent thereof) or any Related Party of any of the foregoing (and without limiting its obligation to do so), each Lender severally agrees to pay to the Agent (or any such sub-agent) or such Related Party, as the case may be, such Lender’s Ratable Share (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount, provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Agent (or any such sub-agent) in its capacity as such, or against any Related Party of any of the foregoing acting for the Agent (or any such sub-agent) in connection with such capacity.

(d)Without limiting the rights of indemnification of the Indemnified Parties set forth in this Agreement with respect to liabilities asserted by third parties, each party hereto also agrees not to assert any claim for special, indirect, consequential or punitive damages against the other parties hereto, or any Related Party of any party hereto, on any theory of liability, arising out of or otherwise relating to the Notes, this Agreement, any other Loan Document, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Loans. No Indemnified Party shall be liable for any damages arising from the use by unintended recipients of any information or other materials distributed by it through telecommunications, electronic or other information transmission systems (including Intralinks, SyndTrak or similar systems) in connection with this Agreement or the other Loan Documents, provided that such indemnity shall not, as to any Indemnified Party, be available to the extent such damages are found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct.

(e)If any payment of principal of, or Conversion of, any Eurodollar Rate Loan is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such Loan, as a result of a payment or Conversion pursuant to Section 2.06(d) or (e), 2.08 or 2.10, acceleration of the maturity of the Loans pursuant to Section 6.01 or for any other reason, or by an Eligible Assignee to a Lender other than on the last day of the Interest Period for such Loan upon an assignment of rights and obligations under this Agreement pursuant to Section 8.07 as a result of a demand by the Borrower pursuant to Section 2.17, the Borrower shall, upon demand by such Lender (with a copy of such demand to the Agent), pay to the Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such payment or Conversion, including, without limitation,

55

any loss (excluding loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Loan.

(f)Without prejudice to the survival of any other agreement of the Borrower hereunder, the agreements and obligations of the Borrower contained in Sections 2.02(c), 2.09, 2.12 and 8.04 shall survive the payment in full of principal, interest and all other amounts payable hereunder and under the Notes.

Section 8.05Right of Set-off. Upon (i) the occurrence and during the continuance of any Event of Default and (ii) the making of the request or the granting of the consent specified by Section 6.01 to authorize the Agent to declare the Loans due and payable pursuant to the provisions of Section 6.01, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by Law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender or any such Affiliate to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower now or hereafter existing under this Agreement or any other Loan Document to such Lender, whether or not such Lender shall have made any demand under this Agreement or such Note and although such obligations may be contingent or unmatured or are owed to a branch or office of such Lender different from the branch or office holding such deposit or obligated on such indebtedness. Each Lender agrees promptly to notify the Borrower after any such set-off and application, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Lender may have.

Section 8.06Effectiveness; Binding Effect. Except as provided in Section 3.01, this Agreement shall become effective when it shall have been executed by the Borrower and the Agent and when the Agent shall have received counterparts hereof that, when taken together, bear the signatures of each of the other parties hereto and thereafter shall be binding upon and inure to the benefit of the Borrower, the Agent and each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of the Lenders (and any purported assignment without such consent shall be null and void).

Section 8.07Successors and Assigns.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Agent and each Lender (and any purported assignment or transfer without such consent shall be null and void) and no Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of subsection (b) of this Section, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (f) of this Section. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors

56

and assigns permitted hereby, Participants to the extent provided in subsection (d) of this Section and, to the extent expressly contemplated hereby, the Related Parties of each of the Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)Any Lender may at any time assign to one or more assignees (other than to an Ineligible Institution) all or a portion of its rights and obligations under this Agreement (including all or a portion of the Loans owing to it at such time); provided that any such assignment shall be subject to the following conditions:

(i)Minimum Amounts.

(A)in the case of an assignment of the entire principal amount of the assigning Lender’s Loans at the time owing to it or in the case of an assignment to a Lender, no minimum amount need be assigned; and

(B)in any case not described in subsection (b)(i)(A) of this Section, the aggregate outstanding principal amount of the Loans of the assigning Lender subject to each such assignment, determined as of the date the Assignment and Assumption with respect to which such assignment is delivered to the Agent or, if “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date, shall not be less than $5,000,000 unless each of the Agent and, so long as no Event of Default has occurred and is continuing, the Borrower otherwise consents (each such consent not to be unreasonably withheld or delayed).

(ii)Proportionate Amounts. Each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Loans assigned, and each such assignment shall be of a constant, and not a varying, percentage of all rights and obligations under this Agreement;

(iii)Required Consents. No consent shall be required for any assignment except to the extent required by subsection (b)(i)(B) of this Section and, in addition:

(A)the consent of the Borrower (such consent not to be unreasonably withheld or delayed; provided that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Agent within ten (10) Business Days after having received notice thereof) shall be required unless (1) an Event of Default has occurred and is continuing at the time of such assignment or (2) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; and

(B)the consent of the Agent (such consent not to be unreasonably withheld or delayed) shall be required if such assignment is to a Person that is not a Lender, an Affiliate of a Lender or an Approved Fund with respect to such Lender.

(iv)Assignment and Assumption. The parties to each assignment shall execute and deliver to the Agent an Assignment and Assumption, together with a processing and

57

recordation fee in the amount of $3,500; provided, however, that no such fee shall be payable in the case of an assignment made at the request of the Borrower to an existing Lender. The assignee, if it is not a Lender, shall deliver to the Agent an Administrative Questionnaire.

(v)No Assignment to Ineligible Institutions. No such assignment shall be made to any Ineligible Institution.

Subject to acceptance and recording thereof by the Agent pursuant to subsection (c) of this Section and notice thereof to the Borrower, from and after the effective date specified in each Assignment and Assumption, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.09, 2.12 and 8.04 with respect to facts and circumstances occurring prior to the effective date of such assignment. Upon request, the Borrower (at its expense) shall execute and deliver a Note to the assignee Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this subsection shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with subsection (d) of this Section.

(c)Register. The Agent shall maintain at the Agent’s Office a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, absent manifest error, and the Borrower, the Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d)Participations. Any Lender may at any time, without the consent of, or notice to, the Borrower or the Agent, sell participations to any Person (other than an Ineligible Institution) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of the Loans owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) the Borrower, the Agent and the Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement and (iv) no participant under any such participation shall have any right to approve any amendment or waiver of any provision of this Agreement or any Note, or any consent to any departure by the Borrower therefrom, except to the extent that such amendment, waiver or consent would reduce the principal of, or interest on, any Obligations or any fees or other amounts payable hereunder, in each case to the extent subject to such participation, or postpone any date fixed for any payment of principal of, or interest on, any

58

Obligations or any fees or other amounts payable hereunder, in each case to the extent subject to such participation.

Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, waiver or other modification addressing the matters set forth in clause (iv) above to the extent subject to such participation. Subject to subsection (e) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.09, 2.12 and 8.04(e) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section. To the extent permitted by Law, each Participant also shall be entitled to the benefits of Section 8.05 as though it were a Lender, provided such Participant agrees to be subject to Section 2.13 as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any Loans or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such Loan or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Agent (in its capacity as Agent) shall have no responsibility for maintaining a Participant Register.

(e)Limitations upon Participant Rights. A Participant shall not be entitled to receive any greater payment under Section 2.09 or 2.12 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.12 unless the Borrower is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrower, to comply with Section 2.12(e) as though it were a Lender.

(f)Certain Pledges. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement (including under its Note, if any) to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

(g)The words “execution,” “signed,” “signature,” and words of like import in any Assignment and Assumption shall be deemed to include electronic signatures or the keeping of

59

records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable Law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state Laws based on the Uniform Electronic Transactions Act.

Section 8.08Confidentiality. Neither the Agent nor any Lender may disclose to any Person any confidential, proprietary or non-public information of the Borrower furnished to the Agent or the Lenders by the Borrower (such information being referred to collectively herein as the “Borrower Information”), except that each of the Agent and each of the Lenders may disclose Borrower Information (i) to its and its Affiliates’ employees, officers, directors, agents and advisors having a need to know in connection with this Agreement (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Borrower Information and instructed to keep such Borrower Information confidential on substantially the same terms as provided herein), (ii) to the extent requested by any regulatory authority or self-regulatory body, (iii) to the extent required by applicable Laws or regulations or by any subpoena or similar legal process, (iv) to any other party to this Agreement, (v) in connection with the exercise of any remedies hereunder or any suit, action or proceeding relating to this Agreement or the enforcement of rights hereunder, (vi) subject to an agreement containing provisions substantially the same as those of this Section 8.08, (A) to any assignee or participant or prospective assignee or participant, (B) to any direct, indirect, actual or prospective counterparty (and its advisor) to any swap, derivative or securitization transaction related to the obligations under this Agreement and (C) to any credit insurance provider relating to the Borrower and its Obligations, (vii) to the extent such Borrower Information (A) is or becomes generally available to the public on a non-confidential basis other than as a result of a breach of this Section 8.08 by the Agent or such Lender or their Related Parties, or (B) is or becomes available to the Agent or such Lender on a nonconfidential basis from a source other than the Borrower (provided that the source of such information was not known by the recipient after inquiry to be bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to the Borrower or any other Person with respect to such information) and (viii) with the consent of the Borrower. The obligations under this Section 8.08 shall survive for two calendar years after the date of the termination of this Agreement.

Section 8.09Governing Law. This Agreement and the Notes shall be governed by, and construed in accordance with, the Laws of the State of New York.

Section 8.10Counterparts; Integration. This Agreement may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Delivery of an executed counterpart of a signature page of this Agreement by telecopy or other electronic imaging means shall be effective as delivery of a manually executed counterpart of this Agreement. This Agreement and the other Loan Documents constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof.

60

Section 8.11Jurisdiction, Etc.

(a)Each of the parties hereto hereby submits to the exclusive jurisdiction of any New York State court or federal court of the United States of America sitting in the Borough of Manhattan in New York City, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement or the other Loan Documents, or for recognition or enforcement of any judgment, and each of the parties hereto hereby agrees that all claims in respect of any such action or proceeding may be heard and determined in any such New York State court or, to the extent permitted by Law, in such federal court.

(b)Each of the parties hereto irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection that it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the Notes in any New York State court or federal court of the United States of America sitting in New York City, and any appellate court from any thereof. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by Law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

Section 8.12Payments Set Aside. To the extent that any payment by or on behalf of the Borrower is made to the Agent or any Lender, or the Agent or any Lender exercises its right of setoff, and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by the Agent or such Lender in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding under any Debtor Relief Law or otherwise, then (a) to the extent of such recovery, the obligation or part thereof originally intended to be satisfied shall be revived and continued in full force and effect as if such payment had not been made or such setoff had not occurred, and (b) each Lender severally agrees to pay to the Agent upon demand its applicable share (without duplication) of any amount so recovered from or repaid by the Agent, plus interest thereon from the date of such demand to the date such payment is made at a rate per annum equal to the Federal Funds Rate from time to time in effect. The obligations of the Lenders under clause (b) of the preceding sentence shall survive the payment in full of the Obligations and the termination of this Agreement.

Section 8.13Patriot Act and Beneficial Ownership Regulation. The Agent and each Lender hereby notifies the Borrower that pursuant to the requirements of the PATRIOT Act and the Beneficial Ownership Regulation, it is required to obtain, verify and record information that identifies each borrower (including the Borrower), guarantor or grantor (the “Loan Parties”), which information includes the name and address of each Loan Party and other information that will allow such Lender to identify such Loan Party in accordance with the PATRIOT Act and the Beneficial Ownership Regulation. The Borrower shall provide, to the extent commercially reasonable, such information and take such actions as are reasonably requested by the Agent or any Lender in order to assist the Agent and such Lender in maintaining compliance with the PATRIOT Act and the Beneficial Ownership Regulation.

Section 8.14Waiver of Jury Trial. EACH OF THE BORROWER, THE AGENT AND THE LENDERS HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY

61

ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE NOTES OR ANY OTHER LOAN DOCUMENT OR THE ACTIONS OF THE BORROWER, THE AGENT OR ANY LENDER IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE OR ENFORCEMENT THEREOF.

Section 8.15No Advisory or Fiduciary Responsibility. In connection with all aspects of each transaction contemplated hereby, the Borrower acknowledges and agrees that: (i) the credit facilities provided for hereunder and any related arranging or other services in connection therewith (including in connection with any amendment, waiver or other modification hereof or of any other Loan Document) are an arm’s-length commercial transaction between the Borrower, on the one hand, and the Agent, each of the Lenders and each of the Arrangers, on the other hand, and the Borrower is capable of evaluating and understanding and understands and accepts the terms, risks and conditions of the transactions contemplated hereby and by the other Loan Documents (including any amendment, waiver or other modification hereof or thereof); (ii) in connection with the process leading to such transaction, each of the Agent, the Lenders and the Arrangers is and has been acting solely as a principal and is not the financial advisor, agent or fiduciary, for the Borrower or any of its Affiliates, stockholders, creditors or employees or any other Person; (iii) neither the Agent nor any Lender or any Arranger has assumed or will assume an advisory, agency or fiduciary responsibility in favor of the Borrower with respect to any of the transactions contemplated hereby or the process leading thereto, including with respect to any amendment, waiver or other modification hereof or of any other Loan Document (irrespective of whether the Agent or any Lender or any Arranger has advised or is currently advising the Borrower or any of its Affiliates on other matters) and neither the Agent nor any Lender or any Arranger has any obligation to the Borrower with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Loan Documents; (iv) the Agent, each of the Lenders and Arrangers and their respective Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its Affiliates, and neither the Agent nor any Lender or any Arranger has any obligation to disclose any of such interests by virtue of any advisory, agency or fiduciary relationship; and (v) the Agent and each Lender and each Arranger have not provided and will not provide any legal, accounting, regulatory or tax advice with respect to any of the transactions contemplated hereby (including any amendment, waiver or other modification hereof or of any other Loan Document) and the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate. The Borrower hereby waives and releases, to the fullest extent permitted by Law, any claims that it may have against the Agent and each Lender and each Arranger with respect to any breach or alleged breach of agency or fiduciary duty in connection with the Loan Documents.

Section 8.16Survival of Representations and Warranties. All representations and warranties made hereunder and in any other Loan Document or other document delivered pursuant hereto or thereto or in connection herewith or therewith shall survive the execution and delivery hereof and thereof. Such representations and warranties have been or will be relied upon by the Agent and each Lender, regardless of any investigation made by the Agent or any Lender or on their behalf, and shall continue in full force and effect as long as any Loan or any other Obligation hereunder shall remain unpaid or unsatisfied.

62

Section 8.17Severability. If any provision of this Agreement or the other Loan Documents is held to be illegal, invalid or unenforceable, (a) the legality, validity and enforceability of the remaining provisions of this Agreement and the other Loan Documents shall not be affected or impaired thereby and (b) the parties shall endeavor in good faith negotiations to replace the illegal, invalid or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the illegal, invalid or unenforceable provisions. The invalidity of a provision in a particular jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

Section 8.18Acknowledgement and Consent to Bail-In of EEA Financial Institutions. Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the Write-Down and Conversion Powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an EEA Financial Institution; and

(b)the effects of any Bail-In Action on any such liability, including, if applicable:

(i)a reduction in full or in part or cancellation of any such liability;

(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)the variation of the terms of such liability in connection with the exercise of the Write-Down and Conversion Powers of any EEA Resolution Authority.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK; SIGNATURE PAGES FOLLOW]

63

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

PINNACLE WEST CAPITAL CORPORATION

By:    /s/ Lee R. Nickloy_____________________

Name:    Lee R. Nickloy

Title:    Vice President and Treasurer

Signature Page to Pinnacle West 364-Day Term Loan Agreement

ADMINISTRATIVE AGENT:	PNC BANK, NATIONAL ASSOCIATION, as
	Agent and a Lender
	By:    /s/ Gabriel Martin
	Name: Gabriel Martín
	Title: Managing Director

Signature Page to Pinnacle West 364-Day Term Loan Agreement

LENDERS:	CITIBANK, N.A., as a Lender
	By:    /s/ Hans Lin
	Name:    Hans Lin
	Title:    Senior Vice President

Signature Page to Pinnacle West 364-Day Term Loan Agreement

SCHEDULE 1.01

COMMITMENTS AND RATABLE SHARES

Lender	Commitment		Ratable Share
PNC Bank, National Association		$25,000,000	50.00%
Citibank, N.A.		$25,000,000	50.00%
TOTAL		$50,000,000	100%

Signature Page to Pinnacle West 364-Day Term Loan Agreement

SCHEDULE 4.01(j)

SUBSIDIARIES

Arizona Public Service Company

SCHEDULE 4.01(k)

EXISTING INDEBTEDNESS

None.

SCHEDULE 8.02

CERTAIN ADDRESSES FOR NOTICES

BORROWER:

Pinnacle West Capital Corporation

400 North Fifth Street

Mail Station 9040

Phoenix, AZ 85004

Attention:     Treasurer

Telephone:    (602) 250-3300

Telecopier:    (602) 250-3902

Electronic    Lee.Nickloy@PinnacleWest.com

AGENT:

PNC Bank, National Association

500 Firstside Center

Pittsburgh, PA 15219

Facsimile No.: 877-733-1117

Telephone No.: 440-546-8120

Attention:  Melanie Squire

Email:  melanie.squire@pnc.com

EXHIBIT A — FORM OF

PROMISSORY NOTE

$________ May 9, 2019

FOR VALUE RECEIVED, the undersigned, PINNACLE WEST CAPITAL CORPORATION, an Arizona corporation (the “Borrower”), hereby promises to pay to the order of ________ or its registered assigns (the “Lender”), in accordance with the provisions of the Term Loan Agreement (as hereinafter defined), the principal amount of ________ DOLLARS ($________), or, if less, the aggregate outstanding principal amount of the Loans (as defined in the Term Loan Agreement) made by the Lender to the Borrower pursuant to the 364-Day Term Loan Agreement dated as of May 9, 2019 among the Borrower, the Lender and certain other lenders party thereto, PNC Bank, National Association, as Agent for the Lender and such other lenders, and the other agents party thereto (as amended or modified from time to time, the “Term Loan Agreement”; the terms defined therein being used herein as therein defined).

The Borrower promises to pay interest on the unpaid principal amount of the Loans from the date of the Loans until such principal amount is paid in full, at such interest rates, and payable at such times, as are specified in the Term Loan Agreement.

Both principal and interest are payable in lawful money of the United States of America to the Agent for the account of the Lender in same day funds at the Agent’s Account. The Loans owing to the Lender by the Borrower pursuant to the Term Loan Agreement, and all payments made on account of principal thereof, shall be recorded by the Lender and, prior to any transfer hereof, endorsed on the grid attached hereto which is part of this Promissory Note, provided that the failure to so record any such Loan or any payment on account thereof shall not affect the payment obligations of the Borrower hereunder or under the Term Loan Agreement.

This Promissory Note is one of the Notes referred to in, and is entitled to the benefits of, the Term Loan Agreement. The Term Loan Agreement, among other things, (i) provides for the making of Loans by the Lender to the Borrower, the indebtedness of the Borrower resulting from such Loans being evidenced by this Promissory Note and (ii) contains provisions for acceleration of the maturity hereof upon the happening of certain stated events and also for prepayments on account of principal hereof prior to the maturity hereof upon the terms and conditions therein specified.

THIS PROMISSORY NOTE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

PINNACLE WEST CAPITAL CORPORATION

By:_________________________________
Name:
Title:

LOANS AND PAYMENTS OF PRINCIPAL

Date Amount of Loan Amount of Principal Paid or Prepaid Unpaid Principal Balance Notation
Made By

EXHIBIT B — FORM OF NOTICE OF INITIAL

BORROWING

PNC Bank, National Association, as Agent

for the Lenders party

to the Term Loan Agreement

referred to below

Attention: Melanie Squire

May 9, 2019

Ladies and Gentlemen:

The undersigned, Pinnacle West Capital Corporation, an Arizona corporation (the “Borrower”), refers to the [execution version][draft dated [__]/[__]/19] of the 364-Day Term Loan Agreement (document ID number: ACTIVE 242281029v.[__]) (as amended or modified from time to time, the “Term Loan Agreement”, the terms defined therein being used herein as therein defined), among the undersigned, certain Lenders party thereto, PNC Bank, National Association, as Agent for said Lenders and the other agents party thereto, and hereby gives you notice, irrevocably, pursuant to Section 2.02 of the Term Loan Agreement that the undersigned hereby requests the Initial Borrowing under the Term Loan Agreement, and in that connection sets forth below the information relating to the Initial Borrowing as required by Section 2.02(a) of the Term Loan Agreement:

(i) The Business Day of the Initial Borrowing is May 9, 2019.

(ii) The Type of Loans comprising the Initial Borrowing is [Base Rate Loans] [Eurodollar Rate Loans].

(iii) The aggregate amount of the Initial Borrowing is $49,000,000.

[(iv) The initial Interest Period for each Eurodollar Rate Loan made as part of the Initial Borrowing is [one week][[__] month[s]].]

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Initial Borrowing:

(A)    the representations and warranties contained in Section 4.01 of the Term Loan Agreement are true and correct, both before and after giving effect to the Initial Borrowing and to the application of the proceeds thereof, as though made on and as of such date (excluding that the Initial Borrowing is not listed on Schedule 4.01(k) thereto);

(B)    no event has occurred and is continuing, or would result from the Initial Borrowing or from the application of the proceeds therefrom, that constitutes a Default; and

(C)    before and after giving effect to the Initial Borrowing and to the application of the proceeds therefrom, as though made on and as of such date, the Indebtedness of the Borrower does not exceed that permitted by (i) applicable resolutions of the Board of Directors of the Borrower or (ii) applicable Laws of any Governmental Authority.

[The Borrower hereby acknowledges and agrees as follows:

1. This Notice of Initial Borrowing is irrevocable.

2. The Borrower shall indemnify each Lender against any loss (excluding loss of anticipated profits), cost or expense incurred by such Lender as a result of any failure by the Borrower (a) to execute and deliver the Term Loan Agreement on or before May 9, 2019, (b) to fulfill the applicable conditions set forth in Article III of the Term Loan Agreement on May 9, 2019 or (c) to otherwise borrow the Eurodollar Rate Loans requested by the Borrower in this Notice of Initial Borrowing on May 9, 2019, in each case in accordance with Section 8.04(e) of the Term Loan Agreement (the terms of which Section are hereby incorporated by reference into this Notice of Initial Borrowing to the same extent and with the same force as if fully set forth herein).

3. The terms of paragraphs 1 and 2 above are not conditioned upon the execution and delivery by the Borrower, the Agent or the Lenders of the Term Loan Agreement.]

This Notice of Initial Borrowing shall be governed by, and construed in accordance with, the laws of the State of New York.

Very truly yours,

PINNACLE WEST CAPITAL CORPORATION

By:    ______________________________

Name:

Title:

EXHIBIT C — FORM OF

ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “Assignment and Assumption”) is dated as of the Effective Date set forth below and is entered into by and between [Insert name of Assignor] (the “Assignor”) and [Insert name of Assignee] (the “Assignee”). Capitalized terms used but not defined herein shall have the meanings given to them in the Term Loan Agreement identified below (as amended, restated, supplemented or otherwise modified from time to time, the “Term Loan Agreement”), receipt of a copy of which is hereby acknowledged by the Assignee. Annex 1 attached hereto (the “Standard Terms and Conditions”) is hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with the Standard Terms and Conditions and the Term Loan Agreement, as of the Effective Date referred to below, (i) all of the Assignor’s rights and obligations in its capacity as a Lender under the Term Loan Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of the Assignor under the Term Loan Agreement (including, without limitation, all Loans owing to the Assignor) and (ii) to the extent permitted to be assigned under applicable Law, all claims, suits, causes of action and any other right of the Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Term Loan Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at Law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned pursuant to clauses (i) and (ii) above being referred to herein collectively as, the “Assigned Interest”). Such sale and assignment is without recourse to the Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by the Assignor. Assignee shall deliver (if it is not already a Lender) to the Agent an Administrative Questionnaire.

1. Assignor: ________________________________

2. Assignee: ________________________________

[and is an Affiliate of [identify Lender]]

3. Borrower: Pinnacle West Capital Corporation

4. Agent: PNC Bank, National Association, as the agent under the Term Loan Agreement

5. Term Loan Agreement: 364-Day Term Loan Agreement dated as of May 9, 2019, by and among the Borrower, the Lenders party thereto, the Agent and the other agents party thereto.

6. Assigned Interest:

Aggregate Principal Amount of Loans of all Lenders	Principal Amount of Loans Assigned	Percentage Assigned of Aggregate Principal Amount of Loans Outstanding	CUSIP Number
$____________	$____________	___________%

[7. Trade Date:]

Effective Date: ________, 20___ [TO BE INSERTED BY AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR

[NAME OF ASSIGNOR]

By: ______________________

Name:

Title:

ASSIGNEE

[NAME OF ASSIGNEE]

By: _____________________

Name:

Title:

[Consented to and] Accepted:

PNC BANK, NATIONAL ASSOCIATION, as Agent

By: ______________________

Name:

Title:

[Consented to:]

PINNACLE WEST CAPITAL CORPORATION

By: _______________________

Name:

Title:

ANNEX 1 TO ASSIGNMENT AND ASSUMPTION

STANDARD TERMS AND CONDITIONS FOR

ASSIGNMENT AND ASSUMPTION

1.    Representations and Warranties.

1.1    Assignor. The Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim and (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Term Loan Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document or (iv) the performance or observance by the Borrower of any of its obligations under any Loan Document.

1.2    Assignee. The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Term Loan Agreement, (ii) it meets all the requirements to be an Eligible Assignee under Section 8.07 of the Term Loan Agreement (subject to such consents, if any, as may be required under Section 8.07 of the Term Loan Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Term Loan Agreement as a Lender thereunder and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Term Loan Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements referred to in Section 4.01(e) or delivered pursuant to Section 5.01(h), as applicable, thereof, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest, (vi) it has, independently and without reliance upon the Agent, the Assignor or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest, and (vii) if it is a Foreign Lender, attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Term Loan Agreement, duly completed and executed by the Assignee; and (b) agrees that (i) it will, independently and without reliance on the Agent, the Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2.    Payments. From and after the Effective Date, the Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, fees and other amounts) to the Assignor for amounts which have accrued to but excluding the Effective Date and to the Assignee for amounts which have accrued from and after the Effective Date.

3.    General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by facsimile or other electronic transmission shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the Law of the State of New York.

EXHIBIT D – FORM OF

INTEREST ELECTION REQUEST

[Date]

PNC Bank, National Association, as Agent for the Lenders party to the

Term Loan Agreement referred to below

500 Firstside Center

Pittsburgh, PA 15219

Facsimile No.: 877-733-1117

Email: melanie.squire@pnc.com

Attention: Melanie Squire

Ladies and Gentlemen:

The undersigned, Pinnacle West Capital Corporation, an Arizona corporation (the “Borrower”), refers to the 364-Day Term Loan Agreement, dated as of May 9, 2019 (as amended, restated, supplemented, or otherwise modified from time to time, the “Term Loan Agreement”, the terms defined therein and not otherwise defined herein being used herein as therein defined), among the Borrower, the Lenders named therein and from time to time party thereto, PNC Bank, National Association, as Agent for said Lenders and the other agents party thereto, and hereby gives you notice, irrevocably, that the undersigned requests a [Conversion] [continuation] of a Borrowing (the “Existing Borrowing”) under the Term Loan Agreement, and in that connection has set forth below the information relating to such [Conversion] [continuation] (the “Proposed [Conversion] [Continuation]”) as required by the definition of “Interest Period” contained in Section 1.01 of the Term Loan Agreement and/or Section 2.07 of the Term Loan Agreement, as applicable:

(i)    The Business Day of the Proposed [Conversion] [Continuation] is _______ ___, 20__.

(ii)    The Type of Loans comprising the Existing Borrowing is [Base Rate Loans] [Eurodollar Rate Loans having an Interest Period of [one week][____ month(s)].

(iii)    The aggregate amount of the Proposed [Conversion] [Continuation] is $______________.

(iv)    The Type of Loans to which such Existing Borrowing is proposed to be [Converted] [continued] is [Base Rate Loans] [Eurodollar Rate Loans].

[(v)    The initial Interest Period for the Eurodollar Rate Loans made as part of the Proposed [Conversion] [Continuation] is [one week][____ month(s).]

The undersigned hereby certifies that the Borrower’s request for the Proposed [Conversion] [Continuation] is made in compliance with the definition of “Interest Period” contained in Section 1.01 of the Term Loan Agreement and with Sections 2.06 and 2.07 of the Term Loan Agreement. [The undersigned hereby acknowledges that the delivery of this Interest Election Request shall constitute a representation and warranty by the Borrower that, on the date of the Proposed [Conversion] [Continuation], no Event of Default has occurred and is continuing (unless the Borrower informs the Agent otherwise prior to the date of the Proposed [Conversion] [Continuation], in which case the Proposed [Conversion] [Continuation] shall not be made.]

Very truly yours,

PINNACLE WEST CAPITAL CORPORATION

By:    __________________________________

Name:

Title:

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Donald E. Brandt, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:    August 8, 2019

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James R. Hatfield, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:    August 8, 2019

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Donald E. Brandt, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:    August 8, 2019

/s/ Donald E. Brandt

Donald E. Brandt

Chairman and Chief Executive Officer

1

EX-31.4

Exhibit 31.4

CERTIFICATION

I, James R. Hatfield, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:    August 8, 2019

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

1

EX-32.1

Exhibit 32.1

CERTIFICATION

OF

CHIEF EXECUTIVE OFFICER

AND

CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended June 30, 2019 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:      August 8, 2019

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended June 30, 2019 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:     August 8, 2019

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

OF

CHIEF EXECUTIVE OFFICER

AND

CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended June 30, 2019 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:      August 8, 2019

/s/ Donald E. Brandt

Donald E. Brandt

Chairman and Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended June 30, 2019 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:      August 8, 2019

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 01, 2019
Entity Information [Line Items]
Entity Shell Company	false
Entity Interactive Data Current	Yes
Security Exchange Name	NYSE
Trading Symbol	PNW
Title of 12(b) Security	Common Stock
Entity Tax Identification Number	86-0512431
Entity Address, Address Line One	400 North Fifth Street, P.O. Box 53999
Entity Address, City or Town	Phoenix
Entity Address, State or Province	AZ
Entity Address, Postal Zip Code	85072-3999
City Area Code	(602)
Local Phone Number	250-1000
Entity File Number	1-8962
Document Transition Report	false
Document Quarterly Report	true
Entity Registrant Name	PINNACLE WEST CAPITAL CORPORATION
Entity Central Index Key	0000764622
Document Type	10-Q
Document Period End Date	Jun. 30, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding (in shares)		112,303,854
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Incorporation, State or Country Code	AZ
APS
Entity Information [Line Items]
Entity Shell Company	false
Entity Interactive Data Current	Yes
Entity Tax Identification Number	86-0011170
Entity Address, Address Line One	400 North Fifth Street, P.O. Box 53999
Entity Address, City or Town	Phoenix
Entity Address, State or Province	AZ
Entity Address, Postal Zip Code	85072-3999
City Area Code	(602)
Local Phone Number	250-1000
Entity File Number	1-4473
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	0000007286
Document Type	10-Q
Document Period End Date	Jun. 30, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding (in shares)		71,264,947
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Incorporation, State or Country Code	AZ

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
OPERATING REVENUES	$ 869,501	$ 974,123	$ 1,610,031	$ 1,666,837
OPERATING EXPENSES
Fuel and purchased power	242,222	257,087	472,810	454,197
Operations and maintenance	227,543	268,397	473,177	534,079
Depreciation and amortization	147,374	145,436	296,081	290,261
Taxes other than income taxes	55,090	53,607	110,180	107,207
Other expenses	683	7,434	1,110	7,597
Total	672,912	731,961	1,353,358	1,393,341
OPERATING INCOME	196,589	242,162	256,673	273,496
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,572	13,073	18,760	27,152
Pension and other postretirement non-service credits - net	6,374	12,006	11,488	24,865
Other income (Note 9)	12,885	6,598	20,054	10,583
Other expense (Note 9)	(4,350)	(3,771)	(8,708)	(7,000)
Total	22,481	27,906	41,594	55,600
INTEREST EXPENSE
Interest charges	57,465	60,708	118,118	119,662
Allowance for borrowed funds used during construction	(4,494)	(6,291)	(11,159)	(13,046)
Total	52,971	54,417	106,959	106,616
INCOME BEFORE INCOME TAXES	166,099	215,651	191,308	222,480
INCOME TAXES	17,080	44,039	19,498	42,774
NET INCOME	149,019	171,612	171,810	179,706
Less: Net income attributable to noncontrolling interests (Note 6)	4,874	4,874	9,747	9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 144,145	$ 166,738	$ 162,063	$ 169,959
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	112,337	112,115	112,381	112,067
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	112,651	112,471	112,734	112,482
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 1.28	$ 1.49	$ 1.44	$ 1.52
Net income attributable to common shareholders - diluted (in dollars per share)	$ 1.28	$ 1.48	$ 1.44	$ 1.51
APS
OPERATING REVENUES	$ 869,501	$ 971,963	$ 1,610,031	$ 1,663,969
OPERATING EXPENSES
Fuel and purchased power	242,222	270,138	472,810	472,148
Operations and maintenance	224,143	251,999	464,518	506,600
Depreciation and amortization	147,354	144,533	296,039	288,645
Taxes other than income taxes	55,081	53,269	110,159	106,511
Other expenses	683	434	1,110	597
Total	669,483	720,373	1,344,636	1,374,501
OPERATING INCOME	200,018	251,590	265,395	289,468
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,572	13,073	18,760	27,152
Pension and other postretirement non-service credits - net	6,757	12,389	12,256	25,586
Other income (Note 9)	11,691	6,235	18,107	10,007
Other expense (Note 9)	(3,428)	(3,372)	(7,306)	(6,318)
Total	22,592	28,325	41,817	56,427
INTEREST EXPENSE
Interest charges	53,591	57,731	110,256	113,889
Allowance for borrowed funds used during construction	(4,494)	(6,291)	(11,159)	(13,046)
Total	49,097	51,440	99,097	100,843
INCOME BEFORE INCOME TAXES	173,513	228,475	208,115	245,052
INCOME TAXES	18,463	45,776	19,916	47,882
NET INCOME	155,050	182,699	188,199	197,170
Less: Net income attributable to noncontrolling interests (Note 6)	4,874	4,874	9,747	9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 150,176	$ 177,825	$ 178,452	$ 187,423

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
NET INCOME	$ 149,019	$ 171,612	$ 171,810	$ 179,706
Derivative instruments:
Net unrealized gain (loss), net of tax expense	0	0	0	(96)
Reclassification of net realized loss, net of tax expense	404	456	732	865
Pension and other postretirement benefits activity, net of tax benefit	(1,539)	(4,739)	(660)	(3,839)
Total other comprehensive income (loss)	(1,135)	(4,283)	72	(3,070)
COMPREHENSIVE INCOME	147,884	167,329	171,882	176,636
Less: Comprehensive income attributable to noncontrolling interests	4,874	4,874	9,747	9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	143,010	162,455	162,135	166,889
APS
NET INCOME	155,050	182,699	188,199	197,170
Derivative instruments:
Net unrealized gain (loss), net of tax expense	0	0	0	(96)
Reclassification of net realized loss, net of tax expense	404	456	732	865
Pension and other postretirement benefits activity, net of tax benefit	(1,653)	(4,764)	(901)	(3,907)
Total other comprehensive income (loss)	(1,249)	(4,308)	(169)	(3,138)
COMPREHENSIVE INCOME	153,801	178,391	188,030	194,032
Less: Comprehensive income attributable to noncontrolling interests	4,874	4,874	9,747	9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 148,927	$ 173,517	$ 178,283	$ 184,285

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net unrealized loss, tax expense	$ 0	$ 0	$ 0	$ 96
Reclassification of net realized loss, tax expense (benefit)	134	150	242	232
Pension and other postretirement (benefits) activity, tax benefit (expense)	506	1,558	218	1,115
APS
Net unrealized loss, tax expense	0	0	0	96
Reclassification of net realized loss, tax expense (benefit)	134	150	242	232
Pension and other postretirement (benefits) activity, tax benefit (expense)	$ 544	$ 1,566	$ 297	$ 1,260

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 1,648	$ 5,766
Customer and other receivables	263,836	267,887
Accrued unbilled revenues	193,657	137,170
Allowance for doubtful accounts	(3,095)	(4,069)
Materials and supplies (at average cost)	289,928	269,065
Fossil fuel (at average cost)	25,453	25,029
Assets from risk management activities (Note 7)	459	1,113
Deferred fuel and purchased power regulatory asset (Note 4)	30,559	37,164
Other regulatory assets (Note 4)	153,900	129,738
Other current assets	72,222	56,128
Total current assets	1,028,567	924,991
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	950,448	851,134
Other special use funds (Notes 11 and 12)	241,558	236,101
Other assets	97,322	103,247
Total investments and other assets	1,289,328	1,190,482
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	19,630,407	18,736,628
Accumulated depreciation and amortization	(6,470,935)	(6,366,014)
Net	13,159,472	12,370,614
Construction work in progress	568,890	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	103,841	105,775
Intangible assets, net of accumulated amortization	261,584	262,902
Nuclear fuel, net of accumulated amortization	159,633	120,217
Total property, plant and equipment	14,253,420	14,029,570
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,431	1,342,941
Operating lease right-of-use assets (Note 16)	176,219	0
Assets for other postretirement benefits (Note 5)	56,336	46,906
Other	40,365	129,312
Total deferred debits	1,594,351	1,519,159
TOTAL ASSETS	18,165,666	17,664,202
CURRENT LIABILITIES
Accounts payable	327,969	277,336
Accrued taxes	158,921	154,819
Accrued interest	50,581	61,107
Common dividends payable	82,824	82,675
Short-term borrowings (Note 3)	432,373	76,400
Current maturities of long-term debt (Note 3)	250,000	500,000
Customer deposits	84,177	91,174
Liabilities from risk management activities (Note 7)	58,834	35,506
Liabilities for asset retirements	21,950	19,842
Operating lease liabilities (Note 16)	60,596	0
Regulatory liabilities (Note 4)	231,857	165,876
Other current liabilities	140,879	184,229
Total current liabilities	1,900,961	1,648,964
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,838,145	1,807,421
Regulatory liabilities (Note 4)	2,287,892	2,325,976
Liabilities for asset retirements	723,005	706,703
Liabilities for pension benefits (Note 5)	356,928	443,170
Liabilities from risk management activities (Note 7)	21,592	24,531
Customer advances	174,411	137,153
Coal mine reclamation	197,443	212,785
Deferred investment tax credit	197,749	200,405
Unrecognized tax benefits	26,271	22,517
Operating lease liabilities (Note 16)	53,005	0
Other	144,142	147,640
Total deferred credits and other	6,020,583	6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,361,595 and 112,159,896 issued at respective dates	2,648,234	2,634,265
Treasury stock at cost; 58,219 and 58,135 shares at respective dates	(5,140)	(4,825)
Total common stock	2,643,094	2,629,440
Retained earnings	2,637,620	2,641,183
Accumulated other comprehensive loss	(47,636)	(47,708)
Total shareholders’ equity	5,233,078	5,222,915
Noncontrolling interests (Note 6)	124,165	125,790
Total equity	5,357,243	5,348,705
Long-term debt less current maturities (Note 3)	4,886,879	4,638,232
TOTAL LIABILITIES AND EQUITY	18,165,666	17,664,202
APS
CURRENT ASSETS
Cash and cash equivalents	1,355	5,707
Customer and other receivables	253,501	257,654
Accrued unbilled revenues	193,657	137,170
Allowance for doubtful accounts	(3,095)	(4,069)
Materials and supplies (at average cost)	289,928	269,065
Fossil fuel (at average cost)	25,453	25,029
Assets from risk management activities (Note 7)	459	1,113
Deferred fuel and purchased power regulatory asset (Note 4)	30,559	37,164
Other regulatory assets (Note 4)	153,900	129,738
Other current assets	49,697	35,111
Total current assets	995,414	893,682
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	950,448	851,134
Other special use funds (Notes 11 and 12)	241,558	236,101
Other assets	46,089	40,817
Total investments and other assets	1,238,095	1,128,052
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	19,626,920	18,733,142
Accumulated depreciation and amortization	(6,467,684)	(6,362,771)
Net	13,159,236	12,370,371
Construction work in progress	568,890	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	103,841	105,775
Intangible assets, net of accumulated amortization	261,429	262,746
Nuclear fuel, net of accumulated amortization	159,633	120,217
Total property, plant and equipment	14,253,029	14,029,171
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,431	1,342,941
Operating lease right-of-use assets (Note 16)	174,320	0
Assets for other postretirement benefits (Note 5)	52,611	43,212
Other	39,523	128,265
Total deferred debits	1,587,885	1,514,418
TOTAL ASSETS	18,074,423	17,565,323
CURRENT LIABILITIES
Accounts payable	319,435	266,277
Accrued taxes	175,922	176,357
Accrued interest	49,703	60,228
Common dividends payable	82,800	82,700
Short-term borrowings (Note 3)	376,873	0
Current maturities of long-term debt (Note 3)	250,000	500,000
Customer deposits	84,177	91,174
Liabilities from risk management activities (Note 7)	58,834	35,506
Liabilities for asset retirements	21,950	19,842
Operating lease liabilities (Note 16)	60,395	0
Regulatory liabilities (Note 4)	231,857	165,876
Other current liabilities	138,423	178,137
Total current liabilities	1,850,369	1,576,097
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,831,660	1,812,664
Regulatory liabilities (Note 4)	2,287,892	2,325,976
Liabilities for asset retirements	723,005	706,703
Liabilities for pension benefits (Note 5)	340,154	425,404
Liabilities from risk management activities (Note 7)	21,592	24,531
Customer advances	174,411	137,153
Coal mine reclamation	197,443	212,785
Deferred investment tax credit	197,749	200,405
Unrecognized tax benefits	42,313	41,861
Operating lease liabilities (Note 16)	51,158	0
Other	121,052	125,511
Total deferred credits and other	5,988,429	6,012,993
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY
Total common stock	178,162	178,162
Additional paid-in capital	2,721,696	2,721,696
Retained earnings	2,801,110	2,788,256
Accumulated other comprehensive loss	(27,276)	(27,107)
Total shareholders’ equity	5,673,692	5,661,007
Noncontrolling interests (Note 6)	124,165	125,790
Total equity	5,797,857	5,786,797
Long-term debt less current maturities (Note 3)	4,437,768	4,189,436
Total capitalization	10,235,625	9,976,233
TOTAL LIABILITIES AND EQUITY	$ 18,074,423	$ 17,565,323

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2019	Dec. 31, 2018
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common stock, par value (in dollars per share)
Common stock, authorized shares (in shares)	150,000,000	150,000,000
Common stock, issued shares (in shares)	112,361,595	112,159,896
Treasury stock at cost, shares (in shares)	58,219	58,135

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 171,810	$ 179,706
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	332,185	325,550
Deferred fuel and purchased power	(16,702)	(50,112)
Deferred fuel and purchased power amortization	23,307	50,851
Allowance for equity funds used during construction	(18,760)	(27,152)
Deferred income taxes	4,326	33,711
Deferred investment tax credit	(2,656)	(2,778)
Stock compensation	13,725	13,189
Changes in current assets and liabilities:
Customer and other receivables	3,543	(18,672)
Accrued unbilled revenues	(56,487)	(95,453)
Materials, supplies and fossil fuel	(21,287)	(22,970)
Other current assets	(16,121)	11,069
Accounts payable	65,874	36,614
Accrued taxes	4,102	8,140
Other current liabilities	(61,270)	9,410
Change in other long-term assets	(82,850)	23,927
Change in other long-term liabilities	3,195	(79,228)
Net cash flow provided by operating activities	345,934	395,802
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(541,401)	(679,949)
Contributions in aid of construction	18,909	19,339
Allowance for borrowed funds used during construction	(11,159)	(13,046)
Proceeds from nuclear decommissioning trust sales and other special use funds	309,354	258,401
Investment in nuclear decommissioning trust and other special use funds	(310,494)	(259,542)
Other	7,153	(4,299)
Net cash flow used for investing activities	(527,638)	(679,096)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324	0
Short-term borrowing and payments — net	363,973	500,849
Short-term debt borrowings	49,000	45,000
Short-term debt repayments	(57,000)	(25,000)
Dividends paid on common stock	(161,979)	(151,942)
Repayment of long-term debt	(500,000)	(82,000)
Common stock equity issuance - net of purchases	(2,360)	(2,294)
Distributions to noncontrolling interests	(11,372)	(11,372)
Net cash flow provided by financing activities	177,586	273,241
NET DECREASE IN CASH AND CASH EQUIVALENTS	(4,118)	(10,053)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,766	13,892
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,648	3,839
Supplemental disclosure of cash flow information
Income taxes, net of refunds	10,788	10,032
Interest, net of amounts capitalized	114,717	104,249
Significant non-cash investing and financing activities:
Accrued capital expenditures	108,056	65,995
APS
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	188,199	197,170
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	332,143	323,934
Deferred fuel and purchased power	(16,702)	(50,112)
Deferred fuel and purchased power amortization	23,307	50,851
Allowance for equity funds used during construction	(18,760)	(27,152)
Deferred income taxes	(10,625)	10,372
Deferred investment tax credit	(2,656)	(2,778)
Changes in current assets and liabilities:
Customer and other receivables	3,645	(9,254)
Accrued unbilled revenues	(56,487)	(95,453)
Materials, supplies and fossil fuel	(21,287)	(23,073)
Other current assets	(14,613)	7,552
Accounts payable	68,399	39,573
Accrued taxes	(435)	26,412
Other current liabilities	(57,709)	7,395
Change in other long-term assets	(84,946)	34,947
Change in other long-term liabilities	3,253	(84,643)
Net cash flow provided by operating activities	334,726	405,741
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(541,401)	(670,841)
Contributions in aid of construction	18,909	19,339
Allowance for borrowed funds used during construction	(11,159)	(13,046)
Proceeds from nuclear decommissioning trust sales and other special use funds	309,354	258,227
Investment in nuclear decommissioning trust and other special use funds	(310,494)	(259,367)
Other	(1,612)	(1,221)
Net cash flow used for investing activities	(536,403)	(666,909)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324	0
Short-term borrowing and payments — net	376,873	499,949
Short-term debt borrowings	0	25,000
Short-term debt repayments	0	(25,000)
Dividends paid on common stock	(165,500)	(155,500)
Repayment of long-term debt	(500,000)	(82,000)
Distributions to noncontrolling interests	(11,372)	(11,372)
Net cash flow provided by financing activities	197,325	251,077
NET DECREASE IN CASH AND CASH EQUIVALENTS	(4,352)	(10,091)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,707	13,851
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,355	3,760
Supplemental disclosure of cash flow information
Income taxes, net of refunds	35,573	24,689
Interest, net of amounts capitalized	107,169	98,478
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 108,056	$ 65,995

XML

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($) $ in Thousands		Total	Common Stock	Treasury Stock	Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests	APS	APS Common Stock	APS Additional Paid-In Capital	APS Retained Earnings		APS Accumulated Other Comprehensive Income (Loss)		APS Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2017			(111,816,170)	(64,463)							(71,264,947)
Balance at beginning of period at Dec. 31, 2017		$ 5,135,730	$ 2,614,805	$ (5,624)	$ 2,442,511		$ (45,002)		$ 129,040	$ 5,385,869	$ 178,162	$ 2,571,696	$ 2,533,954		$ (26,983)		$ 129,040
Increase (Decrease) in Shareholders' Equity
Net income		179,706			169,959				9,747	197,170			187,423				9,747
Other comprehensive loss		(3,070)					(3,070)			(3,138)					(3,138)
Dividends on common stock		(155,620)			(155,620)					(155,599)			(155,599)
Issuance of common stock (in shares)			174,052
Issuance of common stock		9,867	$ 9,867
Purchase of treasury stock (in shares)	[1]			(81,177)
Purchase of treasury stock	[1]	(6,277)		$ (6,277)
Reissuance of treasury stock for stock-based compensation and other (in shares)				128,007
Reissuance of treasury stock for stock-based compensation and other		10,470		$ 10,470	0				0
Reclassification of income tax effects related to new tax reform		(8,552)			8,552	[2]	(8,552)	[2]					5,038	[3]	(5,038)	[3]
Capital activities by noncontrolling interests		(11,372)							(11,372)	(11,372)							(11,372)
Ending balance (in shares) at Jun. 30, 2018			(111,990,222)	(17,633)							(71,264,947)
Balance at end of period at Jun. 30, 2018		5,159,434	$ 2,624,672	$ (1,431)	2,465,402		(56,624)		127,415	5,412,930	$ 178,162	2,571,696	2,570,816		(35,159)		127,415
Beginning balance (in shares) at Mar. 31, 2018			(111,961,963)	(29,097)							(71,264,947)
Balance at beginning of period at Mar. 31, 2018		5,153,671	$ 2,620,261	$ (2,431)	2,454,268		(52,341)		133,914	5,401,512	$ 178,162	2,571,696	2,548,591		(30,851)		133,914
Increase (Decrease) in Shareholders' Equity
Net income		171,612			166,738				4,874	182,699			177,825				4,874
Other comprehensive loss		(4,283)					(4,283)			(4,308)					(4,308)
Other										(1)							(1)
Dividends on common stock		(155,604)			(155,604)					(155,600)			(155,600)
Issuance of common stock (in shares)			28,259
Issuance of common stock		4,411	$ 4,411
Reissuance of treasury stock for stock-based compensation and other (in shares)				11,464
Reissuance of treasury stock for stock-based compensation and other		999		$ 1,000	0				(1)
Capital activities by noncontrolling interests		(11,372)							(11,372)	(11,372)							(11,372)
Ending balance (in shares) at Jun. 30, 2018			(111,990,222)	(17,633)							(71,264,947)
Balance at end of period at Jun. 30, 2018		$ 5,159,434	$ 2,624,672	$ (1,431)	2,465,402		(56,624)		127,415	5,412,930	$ 178,162	2,571,696	2,570,816		(35,159)		127,415
Beginning balance (in shares) at Dec. 31, 2018		(112,159,896)	(112,159,896)	(58,135)							(71,264,947)
Balance at beginning of period at Dec. 31, 2018		$ 5,348,705	$ 2,634,265	$ (4,825)	2,641,183		(47,708)		125,790	5,786,797	$ 178,162	2,721,696	2,788,256		(27,107)		125,790
Increase (Decrease) in Shareholders' Equity
Net income		171,810			162,063				9,747	188,199			178,452				9,747
Other comprehensive loss		72					72			(169)					(169)
Dividends on common stock		(165,626)			(165,626)					(165,598)			(165,598)
Issuance of common stock (in shares)			201,699
Issuance of common stock		13,969	$ 13,969
Purchase of treasury stock (in shares)	[1]			(75,791)
Purchase of treasury stock	[1]	(6,882)		$ (6,882)
Reissuance of treasury stock for stock-based compensation and other (in shares)				75,707
Reissuance of treasury stock for stock-based compensation and other		6,567		$ 6,567	0				0
Capital activities by noncontrolling interests		$ (11,372)							(11,372)	(11,372)							(11,372)
Ending balance (in shares) at Jun. 30, 2019		(112,361,595)	(112,361,595)	(58,219)							(71,264,947)
Balance at end of period at Jun. 30, 2019		$ 5,357,243	$ 2,648,234	$ (5,140)	2,637,620		(47,636)		124,165	5,797,857	$ 178,162	2,721,696	2,801,110		(27,276)		124,165
Beginning balance (in shares) at Mar. 31, 2019			(112,340,322)	(63,271)							(71,264,947)
Balance at beginning of period at Mar. 31, 2019		5,381,725	$ 2,644,063	$ (5,586)	2,659,086		(46,501)		130,663	5,821,026	$ 178,162	2,721,696	2,816,532		(26,027)		130,663
Increase (Decrease) in Shareholders' Equity
Net income		149,019			144,145				4,874	155,050			150,176				4,874
Other comprehensive loss		(1,135)					(1,135)			(1,249)					(1,249)
Dividends on common stock		(165,611)			(165,611)					(165,598)			(165,598)
Issuance of common stock (in shares)			21,273
Issuance of common stock		4,171	$ 4,171
Reissuance of treasury stock for stock-based compensation and other (in shares)				5,052
Reissuance of treasury stock for stock-based compensation and other		446		$ 446	0				0
Capital activities by noncontrolling interests		$ (11,372)							(11,372)	(11,372)							(11,372)
Ending balance (in shares) at Jun. 30, 2019		(112,361,595)	(112,361,595)	(58,219)							(71,264,947)
Balance at end of period at Jun. 30, 2019		$ 5,357,243	$ 2,648,234	$ (5,140)	$ 2,637,620		$ (47,636)		$ 124,165	$ 5,797,857	$ 178,162	$ 2,721,696	$ 2,801,110		$ (27,276)		$ 124,165

[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

[2] 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.

[3] 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.

XML

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) Parenthetical - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Statement of Stockholders' Equity [Abstract]
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 1.48	$ 1.39	$ 1.48	$ 1.39

XML

Consolidation and Nature of Operations

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation and Nature of Operations

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, 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 Form 10-K.

Supplemental Cash Flow Information

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

	Six Months Ended June 30,
	2019		2018
Cash paid during the period for:
Income taxes, net of refunds	$	10,788	$	10,032
Interest, net of amounts capitalized	114,717		104,249
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	108,056	$	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562		—
Dividends accrued but not yet paid	82,824		77,821

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

	Six Months Ended   June 30,
	2019		2018
Cash paid during the period for:
Income taxes, net of refunds	$	35,573	$	24,689
Interest, net of amounts capitalized	107,169		98,478
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	108,056	$	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562		—
Dividends accrued but not yet paid	82,800		77,800

XML

Revenue

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

Sources of Revenue

We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Our retail electric services and tariff rates are regulated by the ACC. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC").

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Retail residential electric service	$	432,568	$	500,247	$	784,134	$	816,922
Retail non-residential electric service	395,929		435,500		728,597		778,689
Wholesale energy sales	21,991		15,392		58,443		27,481
Transmission services for others	15,157		15,489		30,406		30,334
Other sources	3,856		7,495		8,451		13,411
Total operating revenues	$	869,501	$	974,123	$	1,610,031	$	1,666,837

Revenue Activities

Our revenues are primarily derived from activities that are classified as revenues from contracts with customers. This includes sales of electricity to our regulated retail customers and wholesale and transmission activities. Our revenues from contracts with customers for the three and six months ended June 30, 2019 were $858 million and $1,578 million, and for the three and six months ended June 30, 2018 were $954 million and $1,640 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and six months ended June 30, 2019, our revenues that do not qualify as revenue from contracts with customers were $12 million and $32 million, and for the three and six months ended June 30, 2018 were $20 million and $27 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 June 30, 2019 or December 31, 2018.

XML

Long-Term Debt and Liquidity Matters

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Long-Term Debt and Liquidity Matters

Long-Term Debt and Liquidity Matters

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

Pinnacle West

On May 9, 2019, Pinnacle West entered into a $50 million term loan agreement that matures May 7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR') plus 0.55% per annum. At June 30, 2019, Pinnacle West had $46 million in outstanding borrowings under the agreement.

At June 30, 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 June 30, 2019, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $10 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, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.

At June 30, 2019, 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 June 30, 2019, APS had $377 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.

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

Debt Fair Value

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

	As of June 30, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	449,111	$	449,124	$	448,796	$	443,955
APS	4,687,768		5,119,091		4,689,436		4,789,608
Total	$	5,136,879	$	5,568,215	$	5,138,232	$	5,233,563

XML

Regulatory Matters

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Regulatory Matters

Regulatory Matters

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 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") 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 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;

• an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;

• rate design changes, including:

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

▪ 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.

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 were consolidated, and APS requested and was granted intervention. 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. The Arizona Supreme Court denied review.

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 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. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC reconsidered the matter and adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

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 customers regarding the new rates approved in the 2017 Rate Case Decision. On April 23, 2019, the ACC Staff indicated that they would need some additional time beyond May 3, 2019 to file the requested report.

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

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

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

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

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

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

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

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

APS cannot predict the outcome or impact of the future rate case to be filed no later than October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they 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 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. The ACC has not yet ruled on the 2019 RES Implementation Plan.

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 2020 RES Implementation Plan.

On July 2, 2019, ACC Staff issued 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 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. Clean peak sales would include nuclear energy as a clean resource. 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 (“LFCR”) mechanism (see below for discussion on 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 May 7, 2019, APS filed a request for an extension to file its 2020 DSM Plan no later than December 31, 2019. On July 10, 2019, the ACC approved this request.

 Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2019 and 2018 (dollars in thousands):

	Six Months Ended June 30,
	2019			2018
Beginning balance	$	37,164		$	75,637
Deferred fuel and purchased power costs — current period	16,702			50,112
Amounts charged to customers	(23,307		)	(50,851		)
Ending balance	$	30,559		$	74,898

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

On November 30, 2018, APS filed its PSA rate for the PSA year beginning February 1, 2019. That rate was $0.001658 per kWh and consisted of a forward component of $0.000536 per kWh and a historical component of $0.001122 per kWh. The 2019 PSA rate is a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019.

Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters.  In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS's rate case (the "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 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.

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 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, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease from 2017 levels). On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the delay in implementation does not have an adverse effect on APS.

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 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 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 addressed 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 proposed this refund begin July 1, 2019.  APS 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.

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 was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.45 cents per kWh on May 1, 2019, with a requested effective date of September 1, 2019.  This price also reflects the 10% annual reduction discussed above.  The ACC has not yet ruled on this request.

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

See "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. 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 and all answering briefs are due on August 21, 2019. 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 also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters.

Renewable Energy Ballot Initiative

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 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 ("IRP") process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued 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 July 2, 2019, 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.  Clean peak sales would include nuclear energy as a clean resource. The ACC held stakeholder meetings and workshops on ACC Staff’s draft energy rules on July 30 and July 31, 2019 and additional stakeholder workshops will be held in August 2019. APS cannot predict the outcome of this matter.

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 IRP from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request. On August 1, 2019, APS filed its Preliminary IRP.

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. A hearing is set to begin on August 27, 2019 regarding APS’s application. APS cannot predict the outcome of this matter.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.  On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15.  During the moratorium on disconnections, APS cannot charge late fees and interest on amounts that are past due from customers.  Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts.  The emergency rule changes will be effective for 180 days and may be renewed once.  During that time, the ACC will begin a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rules changes.  The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. In July 2019, certain Arizona electric cooperatives filed a request for rehearing of the emergency rules for disconnections on several grounds, including that Attorney General certification is required for such rulemaking. APS currently estimates that the disconnection moratorium will result in an impact to its 2019 operating results of approximately $5 million to $10 million pre-tax depending on certain assumptions, including customer behaviors. APS is further assessing the impact to its financial statements beyond 2019, which will be affected by the results of final rulemaking related to disconnections.

Retail Electric Competition Rules

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

competition rules was held on July 30, 2019. 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.

Four Corners 

SCE-Related Matters. On December 30, 2013, 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. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million 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 from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provided for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $44 million as of June 30, 2019 and is being amortized in rates over a total of 10 years.

 As part of APS’s acquisition of SCE’s interest in 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 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 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. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. APS cannot predict the outcome of the remand proceeding.

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 cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") 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 a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.

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 ($81 million as of June 30, 2019), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.

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

Navajo Plant

The co-owners of the Navajo Generating Station (the "Navajo Plant") and the Navajo Nation agreed 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 plant ($83 million as of June 30, 2019) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.    

Regulatory Assets and Liabilities 

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

	Amortization Through	June 30, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	712,907	$	—	$	733,351
Retired power plant costs	2033	28,182		153,122		28,182		167,164
Income taxes — allowance for funds used during construction ("AFUDC") equity	2049	6,457		152,388		6,457		151,467
Deferred fuel and purchased power — mark-to-market (Note 7)	2023	55,729		21,516		31,728		23,768
Deferred fuel and purchased power (b) (c)	2020	30,559		—		37,164		—
Four Corners cost deferral	2024	8,077		36,190		8,077		40,228
Income taxes — investment tax credit basis adjustment	2047	1,079		25,170		1,079		25,522
Lost fixed cost recovery (b)	2020	25,746		—		32,435		—
Palo Verde VIEs (Note 6)	2046	—		20,325		—		20,015
Deferred compensation	2036	—		37,572		—		36,523
Deferred property taxes	2027	8,569		62,072		8,569		66,356
Loss on reacquired debt	2038	1,637		12,850		1,637		13,668
Tax expense of Medicare subsidy	2024	1,235		5,772		1,235		6,176
TCA balancing account (b)	2021	5,381		3,895		3,860		772
AG-1 deferral	2022	2,787		4,110		2,654		5,819
Mead-Phoenix transmission line CIAC	2050	332		9,878		332		10,044
Coal reclamation	2026	1,546		16,250		1,546		15,607
SCR deferral	N/A	—		37,919		—		23,276
Tax expense adjuster mechanism (b)	2019	3,149		—		—		—
Ocotillo deferral	N/A	—		9,495		—		—
Other	Various	3,994		—		1,947		3,185
Total regulatory assets (d)		$	184,459	$	1,321,431	$	166,902	$	1,342,941

(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."

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

	Amortization Through	June 30, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)	(b)	$	68,651	$	1,178,216	$	—	$	1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)	2058	6,302		241,633		6,302		243,691
Asset retirement obligations	2057	—		359,912		—		278,585
Removal costs	(c)	50,701		153,847		39,866		177,533
Other postretirement benefits	(d)	37,821		105,214		37,864		125,903
Income taxes — deferred investment tax credit	2047	2,164		50,414		2,164		51,120
Income taxes — change in rates	2048	2,764		69,171		2,769		70,069
Spent nuclear fuel	2027	6,578		53,769		6,503		57,002
Renewable energy standard (b)	2021	40,639		4,950		44,966		20
Demand side management (b)	2021	7,191		24,146		14,604		4,123
Sundance maintenance	2030	1,641		15,495		1,278		17,228
Deferred gains on utility property	2022	3,423		5,372		4,423		6,581
Four Corners coal reclamation	2038	1,858		17,540		1,858		17,871
Tax expense adjustor mechanism (b)	2020	1,663		—		3,237		—
Other	Various	461		8,213		42		3,541
Total regulatory liabilities		$	231,857	$	2,287,892	$	165,876	$	2,325,976

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

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

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

(d)

See Note 5.

XML

Retirement Plans and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Retirement Plans and Other Postretirement Benefits

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.

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
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018			2019			2018
Service cost — benefits earned during the period	$	12,408		$	14,121		$	24,951		$	28,334		$	4,470		$	5,445		$	9,184		$	10,550
Non-service costs (credits):
Interest cost on benefit obligation	34,069			31,338			68,421			62,345			7,421			6,973			14,947			14,074
Expected return on plan assets	(43,049		)	(45,759		)	(85,942		)	(91,426		)	(9,603		)	(10,520		)	(19,206		)	(21,041		)
Amortization of:
Prior service credit	—			—			—			—			(9,455		)	(9,461		)	(18,910		)	(18,921		)
Net actuarial loss	10,053			8,259			21,292			16,041			—			—			—			—
Net periodic benefit cost (credit)	$	13,481		$	7,959		$	28,722		$	15,294		$	(7,167	)	$	(7,563	)	$	(13,985	)	$	(15,338	)
Portion of cost (credit) charged to expense	$	7,000		$	2,769		$	15,244		$	5,011		$	(5,063	)	$	(5,119	)	$	(9,880	)	$	(10,724	)

Contributions

We have made voluntary contributions of $120 million to our pension plan year-to-date in 2019. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $350 million during the 2019-2021 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.

XML

Palo Verde Sale Leaseback Variable Interest Entities

6 Months Ended

Jun. 30, 2019

Variable Interest Entities [Abstract]

Palo Verde Sale Leaseback Variable Interest Entities

Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually 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 and six months ended June 30, 2019 of $5 million and $10 million, respectively, and for the three and six months ended June 30, 2018 of $5 million and $10 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands):

	June 30, 2019		December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	103,841	$	105,775
Equity — Noncontrolling interests	124,165		125,790

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 million beginning in 2019, 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.

XML

Derivative Accounting

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Accounting

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.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of June 30, 2019 and December 31, 2018, 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	June 30, 2019	December 31, 2018
Power	GWh	1,000	250
Gas	Billion cubic feet	218	218

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

 

	Financial Statement Location	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts		2019			2018			2019			2018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	$	(538	)	$	(606	)	$	(974	)	$	(1,097	)

(a) During the three and six months ended June 30, 2019 and 2018, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that a net loss of approximately $1 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.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

 

	Financial Statement Location	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts		2019			2018			2019			2018
Net Loss Recognized in Income	Operating revenues	$	—		$	(341	)	$	—		$	(1,560	)
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(49,686		)	3,384			(41,516		)	(30,705		)
Total		$	(49,686	)	$	3,043		$	(41,516	)	$	(32,265	)

(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.

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 June 30, 2019 and December 31, 2018.  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.

As of June 30, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,558		$	(2,939	)	$	619		$	(160	)	$	459
Investments and other assets	76			—			76			—			76
Total assets	3,634			(2,939		)	695			(160		)	535
Current liabilities	(60,588		)	2,939			(57,649		)	(1,185		)	(58,834		)
Deferred credits and other	(21,592		)	—			(21,592		)	—			(21,592		)
Total liabilities	(82,180		)	2,939			(79,241		)	(1,185		)	(80,426		)
Total	$	(78,546	)	$	—		$	(78,546	)	$	(1,345	)	$	(79,891	)

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

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

(c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of ($160).

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
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113
Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)

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

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

(c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

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 June 30, 2019, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. 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 June 30, 2019 (dollars in thousands):

	June 30, 2019
Aggregate fair value of derivative instruments in a net liability position	$	82,064
Cash collateral posted	—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	80,804

(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 $95 million if our debt credit ratings were to fall below investment grade.

XML

Commitments and Contingencies

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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.

APS has submitted four claims pursuant to the terms of the August 18, 2014 settlement agreement, for four separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $74.2 million for these claims (APS’s share is $21.6 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). APS submitted its most recent 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 million (APS's share is $3.0 million). On February 11, 2019 and April 10, 2019 (in response to APS's request for reconsideration), the DOE approved in total a payment of $10.2 million (APS’s share is $3.0 million). On June 7, 2019, 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 $13.9 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 $13.5 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.    

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage

insurance for a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $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 $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 June 30, 2019, our fuel and purchased power commitments have increased approximately $100 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, there have been no material changes, as of June 30, 2019, outside the normal course of business in contractual obligations from the information provided in our 2018 Form 10-K. See Note 3 for discussion regarding changes in our 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. We estimate that our costs related to this investigation and study will be approximately $2 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 RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the

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

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. In addition, APS and certain other parties not named in the remaining RID service provider lawsuit may be brought into the litigation via third-party complaints filed by the current direct 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 the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. 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 is 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 - 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 and details related to the resulting regulatory asset.

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.

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 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 the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required 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 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 EPA approval for a state-specific CCR permitting program. With respect to 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 issuing 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.

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 future action a number of other proposed changes contemplated in a March 1, 2018 proposal. For the final rule issued on July 17, 2018, 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 action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time APS cannot predict the eventual results of this rulemaking proceeding concerning boron.

On 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 to take regulatory action on remand to revise its 2015 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 certain unlined CCR surface impoundments until October 2020. In response, EPA filed a motion to remand but not vacate that deadline extension regulation. On March 13, 2019, the Court issued its ruling on the pending motions concerning the October 2020 deadline for closure initiation and granted remand without vacatur. This ruling allows the current October 2020 deadline 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 CCR surface impoundments. We cannot predict the outcome of EPA’s remand rulemaking concerning the October 2020 deadline for closure initiation.

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 of CCR in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS's share of incremental costs is approximately $1 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. 

APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, all such disposal units must cease operating and initiate closure by October of 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 assessment during the summer of 2019. During this assessment, APS will gather additional groundwater data, solicit input from the public, host public hearings, and select remedies. As such, this $5 million cost estimate may change based upon APS’s performance of the CCR rule’s corrective action assessment process. 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 any potential change to the cost estimate would have a material impact on our financial position, results of operations or cash flows.

Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA's 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and those regulations had been stayed pending judicial review.

The ACE are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions (e.g., the Navajo Nation) with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal, the finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs in the near future.

We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. This action will likely be subject to judicial review and the outcome of those proceedings cannot be predicted. In addition, to the extent that the ACE regulations go into effect as finalized, it is not clear how the state of Arizona or EPA Region IX (i.e., as to the Navajo Nation) will implement these regulations as applied to the Cholla and Four Corners facilities, respectively.

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. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit. We cannot predict the outcome of any further proceedings.

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. On April 30, 2019, EPA issued a proposed NPDES permit for Four Corners and took comment on this proposal through July 1, 2019. As part of this proposal, EPA is contemplating a December 31, 2023 compliance deadline governing Four Corners for the recently updated effluent guidelines for bottom-ash transport water. EPA currently projects that it will take final action on this permit proposal by September 30, 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.

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 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.

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) is approximately $10 million, which is due to 4CA at December 31, 2019.

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 June 30, 2019, standby letters of credit totaled $1.7 million and will expire in 2020. As of June 30, 2019, surety bonds expiring through 2020 totaled $17 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.

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2019. In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See "Four Corners - 4CA Matter" above for information related to this guarantee.) 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 to be immaterial.

XML

Other Income and Other Expense

6 Months Ended

Jun. 30, 2019

Other Income and Expenses [Abstract]

Other Income and Other Expense

Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Other income:
Interest income	$	2,699		$	2,408		$	5,001		$	4,299
Debt return on Four Corners SCR (Note 4)	4,887			4,188			9,731			6,280
Debt return on Ocotillo modernization project (Note 4)	5,294			—			5,294			—
Miscellaneous	5			2			28			4
Total other income	$	12,885		$	6,598		$	20,054		$	10,583
Other expense:
Non-operating costs	$	(3,481	)	$	(3,278	)	$	(6,185	)	$	(4,924	)
Investment losses — net	(491		)	(174		)	(729		)	(350		)
Miscellaneous	(378		)	(319		)	(1,794		)	(1,726		)
Total other expense	$	(4,350	)	$	(3,771	)	$	(8,708	)	$	(7,000	)

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Other income:
Interest income	$	1,504		$	2,046		$	3,054		$	3,724
Debt return on Four Corners SCR (Note 4)	4,887			4,188			9,731			6,280
Debt return on Ocotillo modernization project (Note 4)	5,294			—			5,294			—
Miscellaneous	6			1			28			3
Total other income	$	11,691		$	6,235		$	18,107		$	10,007
Other expense:
Non-operating costs	$	(3,049	)	$	(3,057	)	$	(5,517	)	$	(4,596	)
Miscellaneous	(379		)	(315		)	(1,789		)	(1,722		)
Total other expense	$	(3,428	)	$	(3,372	)	$	(7,306	)	$	(6,318	)

XML

Earnings Per Share

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2019 and 2018 (in thousands, except per share amounts):

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2019		2018		2019		2018
Net income attributable to common shareholders	$	144,145	$	166,738	$	162,063	$	169,959
Weighted average common shares outstanding — basic	112,337		112,115		112,381		112,067
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	314		356		353		415
Weighted average common shares outstanding — diluted	112,651		112,471		112,734		112,482
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	1.28	$	1.49	$	1.44	$	1.52
Net income attributable to common shareholders — diluted	$	1.28	$	1.48	$	1.44	$	1.51

XML

Fair Value Measurements

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

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

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

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. 

We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of 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 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 7 in the 2018 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

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

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 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 medical account. See Note 12 for additional discussion about our investment accounts.

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

Fixed Income Securities

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

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

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.

Fair Value Tables

The following table presents the fair value at June 30, 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 (Level 3)			Other				Balance at June 30, 2019
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	3,198		$	436		$	(3,099	)	(a)	$	535
Nuclear decommissioning trust:
Equity securities	5,319		—			—			6,665			(b)	11,984
U.S. commingled equity funds	—		—			—			469,375			(c)	469,375
U.S. Treasury debt	162,044		—			—			—				162,044
Corporate debt	—		115,674			—			—				115,674
Mortgage-backed securities	—		113,179			—			—				113,179
Municipal bonds	—		67,158			—			—				67,158
Other fixed income	—		11,034			—			—				11,034
Subtotal nuclear decommissioning trust	167,363		307,045			—			476,040				950,448
Other special use funds:
Equity securities	13,200		—			—			997			(b)	14,197
U.S. Treasury debt	214,712		—			—			—				214,712
Municipal bonds	—		12,649			—			—				12,649
Subtotal other special use funds	227,912		12,649			—			997				241,558
Total assets	$	395,275	$	322,892		$	436		$	473,938			$	1,192,541
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(68,992	)	$	(13,189	)	$	1,755		(a)	$	(80,426	)

(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.

The following table presents the fair value at December 31, 2018 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 (Level 3)			Other				Balance at December 31, 2018
Assets
Cash equivalents	$	1,200	$	—		$	—		$	—			$	1,200
Risk management activities — derivative instruments:
Commodity contracts	—		3,140			2			(2,029		)	(a)	1,113
Nuclear decommissioning trust:
Equity securities	5,203		—			—			2,148			(b)	7,351
U.S. commingled equity funds	—		—			—			396,805			(c)	396,805
U.S. Treasury debt	148,173		—			—			—				148,173
Corporate debt	—		96,656			—			—				96,656
Mortgage-backed securities	—		113,115			—			—				113,115
Municipal bonds	—		79,073			—			—				79,073
Other fixed income	—		9,961			—			—				9,961
Subtotal nuclear decommissioning trust	153,376		298,805			—			398,953				851,134
Other special use funds:
Equity securities	45,130		—			—			593			(b)	45,723
U.S. Treasury debt	173,310		—			—			—				173,310
Municipal bonds	—		17,068			—			—				17,068
Subtotal other special use funds	218,440		17,068			—			593				236,101
Total assets	$	373,016	$	319,013		$	2		$	397,517			$	1,089,548
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(52,696	)	$	(8,216	)	$	875		(a)	$	(60,037	)

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

(b) Represents net pending securities sales and purchases.

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

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).

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

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 June 30, 2019 and December 31, 2018:

	June 30, 2019 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	294	$	11,675	Discounted cash flows	Electricity forward price (per MWh)	$18.27 - $30.11	$	26.78
Natural Gas:
Forward Contracts (a)	142		1,514		Discounted cash flows	Natural gas forward price (per MMBtu)	$0.05 - $2.88	$	2.41
Total	$	436	$	13,189

(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.

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2019			2018			2019			2018
Net derivative balance at beginning of period	$	(5,612	)	$	(19,754	)	$	(8,214	)	$	(18,256	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(8,731		)	(989		)	(10,310		)	(3,311		)
Settlements	2,431			494			2,949			1,276
Transfers into Level 3 from Level 2	(3,096		)	(2,534		)	(3,098		)	(4,979		)
Transfers from Level 3 into Level 2	2,255			13,425			5,920			15,912
Net derivative balance at end of period	$	(12,753	)	$	(9,358	)	$	(12,753	)	$	(9,358	)
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 $53 million as of June 30, 2019 and $61 million as of December 31, 2018 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.

XML

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

6 Months Ended

Jun. 30, 2019

Investments, Debt and Equity Securities [Abstract]

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

Investments in Nuclear Decommissioning Trust and Other Special Use Funds

We have investments in debt and equity securities held in nuclear decommissioning trust, coal reclamation escrow account, and an active union employee medical account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our 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 Trust - To fund the future costs APS expects to incur to decommission Palo Verde, APS established an external decommissioning trust 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 trust. Because of the ability of APS to recover decommissioning

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

Coal Reclamation Escrow Account - APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities. Activities relating to APS coal reclamation escrow account investments are included within the other special use funds in the table below.

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 and 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) in other regulatory assets. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

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 and other special use fund assets at June 30, 2019 and December 31, 2018 (dollars in thousands):  

	June 30, 2019
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trust		Other Special Use Funds		Total
Equity securities	$	474,694	$	13,200	$	487,894		$	291,295	$	—
Available for sale-fixed income securities	469,089		227,361		696,450		(a)	24,638		(696		)
Other	6,665		997		7,662		(b)	—		—
Total	$	950,448	$	241,558	$	1,192,006		$	315,933	$	(696	)

(a) As of June 30, 2019, the amortized cost basis of these available-for-sale investments is $672 million.

(b) Represents net pending securities sales and purchases.

	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trust		Other Special Use Funds		Total
Equity securities	$	402,008	$	45,130	$	447,138		$	222,147	$	(459	)
Available for sale-fixed income securities	446,978		190,378		637,356		(a)	8,634		(6,778		)
Other	2,148		593		2,741		(b)	—		—
Total	$	851,134	$	236,101	$	1,087,235		$	230,781	$	(7,237	)

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

(b) Represents net pending securities sales and purchases.

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,
	Nuclear Decommissioning Trust			Other Special Use Funds		Total
2019
Realized gains	$	2,643		$	—	$	2,643
Realized losses	(1,700		)	—		(1,700		)
Proceeds from the sale of securities (a)	93,559			36,747		130,306
2018
Realized gains	$	1,484		$	—	$	1,484
Realized losses	(2,978		)	—		(2,978		)
Proceeds from the sale of securities (a)	122,790			2,426		125,216

(a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

	Six Months Ended June 30,
	Nuclear Decommissioning Trust			Other Special Use Funds		Total
2019
Realized gains	$	3,746		$	—	$	3,746
Realized losses	(3,105		)	—		(3,105		)
Proceeds from the sale of securities (a)	216,152			93,202		309,354
2018
Realized gains	$	2,298		$	1	$	2,299
Realized losses	(5,025		)	—		(5,025		)
Proceeds from the sale of securities (a)	253,246			4,981		258,227

(a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

     The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2019, is as follows (dollars in thousands):

	Nuclear Decommissioning Trust (a)		Coal Reclamation Escrow Account		Active Union Medical Trust		Total
Less than one year	$	37,373	$	22,253	$	40,219	$	99,845
1 year – 5 years	126,745		17,449		140,569		284,763
5 years – 10 years	113,989		1,807		—		115,796
Greater than 10 years	190,982		5,064		—		196,046
Total	$	469,089	$	46,573	$	180,788	$	696,450

(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.

XML

New Accounting Standards

6 Months Ended

Jun. 30, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

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.

ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in 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. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

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 entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments are 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 this new accounting standard and the impacts it may have on our financial statements.

XML

Changes in Accumulated Other Comprehensive Loss

6 Months Ended

Jun. 30, 2019

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Changes in Accumulated Other Comprehensive Loss

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Three Months Ended June 30
Balance March 31, 2019	$	(45,118	)		$	(1,383	)		$	(46,501	)
OCI (loss) before reclassifications	(2,422		)		—				(2,422		)
Amounts reclassified from accumulated other comprehensive loss	883			(a)	404			(b)	1,287
Balance June 30, 2019	$	(46,657	)		$	(979	)		$	(47,636	)
Balance March 31, 2018	$	(49,494	)		$	(2,847	)		$	(52,341	)
OCI (loss) before reclassifications	(5,928		)		—				(5,928		)
Amounts reclassified from accumulated other comprehensive loss	1,189			(a)	456			(b)	1,645
Balance June 30, 2018	$	(54,233	)		$	(2,391	)		$	(56,624	)

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Six Months Ended June 30
Balance December 31, 2018	$	(45,997	)		$	(1,711	)		$	(47,708	)
OCI (loss) before reclassifications	(2,422		)		—				(2,422		)
Amounts reclassified from accumulated other comprehensive loss	1,762			(a)	732			(b)	2,494
Balance June 30, 2019	$	(46,657	)		$	(979	)		$	(47,636	)
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)
OCI (loss) before reclassifications	(5,928		)		(96		)		(6,024		)
Amounts reclassified from accumulated other comprehensive loss	2,089			(a)	865			(b)	2,954
Reclassification of income tax effect related to tax reform	(7,954		)	(c)	(598		)	(c)	(8,552		)
Balance June 30, 2018	$	(54,233	)		$	(2,391	)		$	(56,624	)

(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.

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 and six months ended June 30, 2019 and 2018 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Three Months Ended June 30
Balance March 31, 2019	$	(24,644	)		$	(1,383	)		$	(26,027	)
OCI (loss) before reclassifications	(2,414		)		—				(2,414		)
Amounts reclassified from accumulated other comprehensive loss	761			(a)	404			(b)	1,165
Balance June 30, 2019	$	(26,297	)		$	(979	)		$	(27,276	)
Balance March 31, 2018	$	(28,004	)		$	(2,847	)		$	(30,851	)
OCI (loss) before reclassifications	(5,790		)		—				(5,790		)
Amounts reclassified from accumulated other comprehensive loss	1,026			(a)	456			(b)	1,482
Balance June 30, 2018	$	(32,768	)		$	(2,391	)		$	(35,159	)

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Six Months Ended June 30
Balance December 31, 2018	$	(25,396	)		$	(1,711	)		$	(27,107	)
OCI (loss) before reclassifications	(2,414		)		—				(2,414		)
Amounts reclassified from accumulated other comprehensive loss	1,513			(a)	732			(b)	2,245
Balance June 30, 2019	$	(26,297	)		$	(979	)		$	(27,276	)
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)
OCI (loss) before reclassifications	(5,790		)		(96		)		(5,886		)
Amounts reclassified from accumulated other comprehensive loss	1,883			(a)	865			(b)	2,748
Reclassification of income tax effect related to tax reform	(4,440		)	(c)	(598		)	(c)	(5,038		)
Balance June 30, 2018	$	(32,768	)		$	(2,391	)		$	(35,159	)

(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.

XML

Income Taxes

6 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

Income Taxes

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 period. As a result, the Company began amortization in March 2019. As of June 30, 2019, the Company has recorded $19.4 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On April 10, 2019, the Company filed a request with the ACC which addresses the amortization of depreciation related excess deferred taxes. See Note 4 for more details.

In August 2018, Treasury proposed regulations that clarify 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 proposed regulations are ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. 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. In a footnote, the JCT indicated that a technical correction bill may be necessary 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 property placed in service on or after January 1, 2018, the Company currently believes the continued availability of bonus depreciation is not “more likely than not” to be sustained upon examination. As a result, the Company has not recognized any current or deferred tax benefits related to bonus depreciation for property placed in service on or after January 1, 2018.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 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 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2014.

XML

Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Leases

Leases

We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2019 through 2050. Substantially all of our leasing activities relate to APS.

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

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 tables provide information related to our lease costs for the three and six months ended June 30, 2019 (dollars in thousands):

	Three Months Ended June 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	14,063	$	4,414	$	18,477
Variable lease cost	41,529		360		41,889
Short-term lease cost	—		1,812		1,812
Total lease cost	$	55,592	$	6,586	$	62,178

	Six Months Ended June 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	14,063	$	8,762	$	22,825
Variable lease cost	58,820		360		59,180
Short-term lease cost	—		2,665		2,665
Total lease cost	$	72,883	$	11,787	$	84,670

Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Condensed Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.

The following table provides information related to the maturity of our operating lease liabilities at June 30, 2019 (dollars in thousands):

	June 30, 2019
Year	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
2019 (remaining six months of 2019)	$	49,051	$	7,335	$	56,386
2020	—		12,868		12,868
2021	—		10,029		10,029
2022	—		6,988		6,988
2023	—		5,838		5,838
2024	—		3,691		3,691
Thereafter	—		38,506		38,506
Total lease commitments	49,051		85,255		134,306
Less imputed interest	294		20,411		20,705
Total lease liabilities	$	48,757	$	64,844	$	113,601

We recognize lease assets and liabilities upon lease commencement. At June 30, 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. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million over the term of the arrangements.

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:

	June 30, 2019
Weighted average remaining lease term	8 years
Weighted average discount rate (a)	3.84	%

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

	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	11,987

XML

New Accounting Standards (Policies)

6 Months Ended

Jun. 30, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

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.

ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in 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. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

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 entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments are 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 this new accounting standard and the impacts it may have on our financial statements.

XML

Consolidation and Nature of Operations (Tables)

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of supplemental cash flow information

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

	Six Months Ended June 30,
	2019		2018
Cash paid during the period for:
Income taxes, net of refunds	$	10,788	$	10,032
Interest, net of amounts capitalized	114,717		104,249
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	108,056	$	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562		—
Dividends accrued but not yet paid	82,824		77,821

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

	Six Months Ended   June 30,
	2019		2018
Cash paid during the period for:
Income taxes, net of refunds	$	35,573	$	24,689
Interest, net of amounts capitalized	107,169		98,478
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	108,056	$	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562		—
Dividends accrued but not yet paid	82,800		77,800

XML

Revenue (Tables)

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Retail residential electric service	$	432,568	$	500,247	$	784,134	$	816,922
Retail non-residential electric service	395,929		435,500		728,597		778,689
Wholesale energy sales	21,991		15,392		58,443		27,481
Transmission services for others	15,157		15,489		30,406		30,334
Other sources	3,856		7,495		8,451		13,411
Total operating revenues	$	869,501	$	974,123	$	1,610,031	$	1,666,837

XML

Long-Term Debt and Liquidity Matters (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Schedule of estimated fair value of long-term debt, including current maturities

The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

	As of June 30, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	449,111	$	449,124	$	448,796	$	443,955
APS	4,687,768		5,119,091		4,689,436		4,789,608
Total	$	5,136,879	$	5,568,215	$	5,138,232	$	5,233,563

XML

Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Schedule of changes in the deferred fuel and purchased power regulatory asset

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2019 and 2018 (dollars in thousands):

	Six Months Ended June 30,
	2019			2018
Beginning balance	$	37,164		$	75,637
Deferred fuel and purchased power costs — current period	16,702			50,112
Amounts charged to customers	(23,307		)	(50,851		)
Ending balance	$	30,559		$	74,898

Schedule of regulatory assets

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

	Amortization Through	June 30, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	712,907	$	—	$	733,351
Retired power plant costs	2033	28,182		153,122		28,182		167,164
Income taxes — allowance for funds used during construction ("AFUDC") equity	2049	6,457		152,388		6,457		151,467
Deferred fuel and purchased power — mark-to-market (Note 7)	2023	55,729		21,516		31,728		23,768
Deferred fuel and purchased power (b) (c)	2020	30,559		—		37,164		—
Four Corners cost deferral	2024	8,077		36,190		8,077		40,228
Income taxes — investment tax credit basis adjustment	2047	1,079		25,170		1,079		25,522
Lost fixed cost recovery (b)	2020	25,746		—		32,435		—
Palo Verde VIEs (Note 6)	2046	—		20,325		—		20,015
Deferred compensation	2036	—		37,572		—		36,523
Deferred property taxes	2027	8,569		62,072		8,569		66,356
Loss on reacquired debt	2038	1,637		12,850		1,637		13,668
Tax expense of Medicare subsidy	2024	1,235		5,772		1,235		6,176
TCA balancing account (b)	2021	5,381		3,895		3,860		772
AG-1 deferral	2022	2,787		4,110		2,654		5,819
Mead-Phoenix transmission line CIAC	2050	332		9,878		332		10,044
Coal reclamation	2026	1,546		16,250		1,546		15,607
SCR deferral	N/A	—		37,919		—		23,276
Tax expense adjuster mechanism (b)	2019	3,149		—		—		—
Ocotillo deferral	N/A	—		9,495		—		—
Other	Various	3,994		—		1,947		3,185
Total regulatory assets (d)		$	184,459	$	1,321,431	$	166,902	$	1,342,941

(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."

Schedule of regulatory liabilities

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

	Amortization Through	June 30, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)	(b)	$	68,651	$	1,178,216	$	—	$	1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)	2058	6,302		241,633		6,302		243,691
Asset retirement obligations	2057	—		359,912		—		278,585
Removal costs	(c)	50,701		153,847		39,866		177,533
Other postretirement benefits	(d)	37,821		105,214		37,864		125,903
Income taxes — deferred investment tax credit	2047	2,164		50,414		2,164		51,120
Income taxes — change in rates	2048	2,764		69,171		2,769		70,069
Spent nuclear fuel	2027	6,578		53,769		6,503		57,002
Renewable energy standard (b)	2021	40,639		4,950		44,966		20
Demand side management (b)	2021	7,191		24,146		14,604		4,123
Sundance maintenance	2030	1,641		15,495		1,278		17,228
Deferred gains on utility property	2022	3,423		5,372		4,423		6,581
Four Corners coal reclamation	2038	1,858		17,540		1,858		17,871
Tax expense adjustor mechanism (b)	2020	1,663		—		3,237		—
Other	Various	461		8,213		42		3,541
Total regulatory liabilities		$	231,857	$	2,287,892	$	165,876	$	2,325,976

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

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

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

(d)

See Note 5.

XML

Retirement Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)

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
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018			2019			2018
Service cost — benefits earned during the period	$	12,408		$	14,121		$	24,951		$	28,334		$	4,470		$	5,445		$	9,184		$	10,550
Non-service costs (credits):
Interest cost on benefit obligation	34,069			31,338			68,421			62,345			7,421			6,973			14,947			14,074
Expected return on plan assets	(43,049		)	(45,759		)	(85,942		)	(91,426		)	(9,603		)	(10,520		)	(19,206		)	(21,041		)
Amortization of:
Prior service credit	—			—			—			—			(9,455		)	(9,461		)	(18,910		)	(18,921		)
Net actuarial loss	10,053			8,259			21,292			16,041			—			—			—			—
Net periodic benefit cost (credit)	$	13,481		$	7,959		$	28,722		$	15,294		$	(7,167	)	$	(7,563	)	$	(13,985	)	$	(15,338	)
Portion of cost (credit) charged to expense	$	7,000		$	2,769		$	15,244		$	5,011		$	(5,063	)	$	(5,119	)	$	(9,880	)	$	(10,724	)

XML

Palo Verde Sale Leaseback Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2019

Variable Interest Entities [Abstract]

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

Our Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands):

	June 30, 2019		December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	103,841	$	105,775
Equity — Noncontrolling interests	124,165		125,790

XML

Derivative Accounting (Tables)

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)

As of June 30, 2019 and December 31, 2018, 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	June 30, 2019	December 31, 2018
Power	GWh	1,000	250
Gas	Billion cubic feet	218	218

Gains and losses from derivative instruments in designated cash flow accounting hedges relationships

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

 

	Financial Statement Location	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts		2019			2018			2019			2018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	$	(538	)	$	(606	)	$	(974	)	$	(1,097	)

(a) During the three and six months ended June 30, 2019 and 2018, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b)

Amounts are before the effect of PSA deferrals.

Gains and losses from derivative instruments not designated as accounting hedges instruments

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

 

	Financial Statement Location	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts		2019			2018			2019			2018
Net Loss Recognized in Income	Operating revenues	$	—		$	(341	)	$	—		$	(1,560	)
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(49,686		)	3,384			(41,516		)	(30,705		)
Total		$	(49,686	)	$	3,043		$	(41,516	)	$	(32,265	)

(a)

Amounts are before the effect of PSA deferrals.

Schedule of offsetting assets

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 June 30, 2019 and December 31, 2018.  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.

As of June 30, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,558		$	(2,939	)	$	619		$	(160	)	$	459
Investments and other assets	76			—			76			—			76
Total assets	3,634			(2,939		)	695			(160		)	535
Current liabilities	(60,588		)	2,939			(57,649		)	(1,185		)	(58,834		)
Deferred credits and other	(21,592		)	—			(21,592		)	—			(21,592		)
Total liabilities	(82,180		)	2,939			(79,241		)	(1,185		)	(80,426		)
Total	$	(78,546	)	$	—		$	(78,546	)	$	(1,345	)	$	(79,891	)

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

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

(c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of ($160).

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
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113
Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)

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

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

(c)

Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

Schedule of offsetting liabilities

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 June 30, 2019 and December 31, 2018.  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.

As of June 30, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,558		$	(2,939	)	$	619		$	(160	)	$	459
Investments and other assets	76			—			76			—			76
Total assets	3,634			(2,939		)	695			(160		)	535
Current liabilities	(60,588		)	2,939			(57,649		)	(1,185		)	(58,834		)
Deferred credits and other	(21,592		)	—			(21,592		)	—			(21,592		)
Total liabilities	(82,180		)	2,939			(79,241		)	(1,185		)	(80,426		)
Total	$	(78,546	)	$	—		$	(78,546	)	$	(1,345	)	$	(79,891	)

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

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

(c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of ($160).

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
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113
Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)

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

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

(c)

Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

Information about derivative instruments that have credit-risk-related contingent features

The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2019 (dollars in thousands):

	June 30, 2019
Aggregate fair value of derivative instruments in a net liability position	$	82,064
Cash collateral posted	—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	80,804

(a)

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

XML

Other Income and Other Expense (Tables)

6 Months Ended

Jun. 30, 2019

Other Income and Expenses [Abstract]

Detail of other income and other expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Other income:
Interest income	$	2,699		$	2,408		$	5,001		$	4,299
Debt return on Four Corners SCR (Note 4)	4,887			4,188			9,731			6,280
Debt return on Ocotillo modernization project (Note 4)	5,294			—			5,294			—
Miscellaneous	5			2			28			4
Total other income	$	12,885		$	6,598		$	20,054		$	10,583
Other expense:
Non-operating costs	$	(3,481	)	$	(3,278	)	$	(6,185	)	$	(4,924	)
Investment losses — net	(491		)	(174		)	(729		)	(350		)
Miscellaneous	(378		)	(319		)	(1,794		)	(1,726		)
Total other expense	$	(4,350	)	$	(3,771	)	$	(8,708	)	$	(7,000	)

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Other income:
Interest income	$	1,504		$	2,046		$	3,054		$	3,724
Debt return on Four Corners SCR (Note 4)	4,887			4,188			9,731			6,280
Debt return on Ocotillo modernization project (Note 4)	5,294			—			5,294			—
Miscellaneous	6			1			28			3
Total other income	$	11,691		$	6,235		$	18,107		$	10,007
Other expense:
Non-operating costs	$	(3,049	)	$	(3,057	)	$	(5,517	)	$	(4,596	)
Miscellaneous	(379		)	(315		)	(1,789		)	(1,722		)
Total other expense	$	(3,428	)	$	(3,372	)	$	(7,306	)	$	(6,318	)

XML

Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Schedule of earnings per weighted average common share outstanding

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2019 and 2018 (in thousands, except per share amounts):

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2019		2018		2019		2018
Net income attributable to common shareholders	$	144,145	$	166,738	$	162,063	$	169,959
Weighted average common shares outstanding — basic	112,337		112,115		112,381		112,067
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	314		356		353		415
Weighted average common shares outstanding — diluted	112,651		112,471		112,734		112,482
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	1.28	$	1.49	$	1.44	$	1.52
Net income attributable to common shareholders — diluted	$	1.28	$	1.48	$	1.44	$	1.51

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Fair value of assets and liabilities that are measured at fair value on a recurring basis

The following table presents the fair value at June 30, 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 (Level 3)			Other				Balance at June 30, 2019
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	3,198		$	436		$	(3,099	)	(a)	$	535
Nuclear decommissioning trust:
Equity securities	5,319		—			—			6,665			(b)	11,984
U.S. commingled equity funds	—		—			—			469,375			(c)	469,375
U.S. Treasury debt	162,044		—			—			—				162,044
Corporate debt	—		115,674			—			—				115,674
Mortgage-backed securities	—		113,179			—			—				113,179
Municipal bonds	—		67,158			—			—				67,158
Other fixed income	—		11,034			—			—				11,034
Subtotal nuclear decommissioning trust	167,363		307,045			—			476,040				950,448
Other special use funds:
Equity securities	13,200		—			—			997			(b)	14,197
U.S. Treasury debt	214,712		—			—			—				214,712
Municipal bonds	—		12,649			—			—				12,649
Subtotal other special use funds	227,912		12,649			—			997				241,558
Total assets	$	395,275	$	322,892		$	436		$	473,938			$	1,192,541
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(68,992	)	$	(13,189	)	$	1,755		(a)	$	(80,426	)

(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.

The following table presents the fair value at December 31, 2018 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 (Level 3)			Other				Balance at December 31, 2018
Assets
Cash equivalents	$	1,200	$	—		$	—		$	—			$	1,200
Risk management activities — derivative instruments:
Commodity contracts	—		3,140			2			(2,029		)	(a)	1,113
Nuclear decommissioning trust:
Equity securities	5,203		—			—			2,148			(b)	7,351
U.S. commingled equity funds	—		—			—			396,805			(c)	396,805
U.S. Treasury debt	148,173		—			—			—				148,173
Corporate debt	—		96,656			—			—				96,656
Mortgage-backed securities	—		113,115			—			—				113,115
Municipal bonds	—		79,073			—			—				79,073
Other fixed income	—		9,961			—			—				9,961
Subtotal nuclear decommissioning trust	153,376		298,805			—			398,953				851,134
Other special use funds:
Equity securities	45,130		—			—			593			(b)	45,723
U.S. Treasury debt	173,310		—			—			—				173,310
Municipal bonds	—		17,068			—			—				17,068
Subtotal other special use funds	218,440		17,068			—			593				236,101
Total assets	$	373,016	$	319,013		$	2		$	397,517			$	1,089,548
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(52,696	)	$	(8,216	)	$	875		(a)	$	(60,037	)

(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.

Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2019 and December 31, 2018:

	June 30, 2019 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	294	$	11,675	Discounted cash flows	Electricity forward price (per MWh)	$18.27 - $30.11	$	26.78
Natural Gas:
Forward Contracts (a)	142		1,514		Discounted cash flows	Natural gas forward price (per MMBtu)	$0.05 - $2.88	$	2.41
Total	$	436	$	13,189

(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.

Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2019			2018			2019			2018
Net derivative balance at beginning of period	$	(5,612	)	$	(19,754	)	$	(8,214	)	$	(18,256	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(8,731		)	(989		)	(10,310		)	(3,311		)
Settlements	2,431			494			2,949			1,276
Transfers into Level 3 from Level 2	(3,096		)	(2,534		)	(3,098		)	(4,979		)
Transfers from Level 3 into Level 2	2,255			13,425			5,920			15,912
Net derivative balance at end of period	$	(12,753	)	$	(9,358	)	$	(12,753	)	$	(9,358	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

XML

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)

6 Months Ended

Jun. 30, 2019

Investments, Debt and Equity Securities [Abstract]

Fair value of APS's nuclear decommissioning trust fund assets

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at June 30, 2019 and December 31, 2018 (dollars in thousands):  

	June 30, 2019
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trust		Other Special Use Funds		Total
Equity securities	$	474,694	$	13,200	$	487,894		$	291,295	$	—
Available for sale-fixed income securities	469,089		227,361		696,450		(a)	24,638		(696		)
Other	6,665		997		7,662		(b)	—		—
Total	$	950,448	$	241,558	$	1,192,006		$	315,933	$	(696	)

(a) As of June 30, 2019, the amortized cost basis of these available-for-sale investments is $672 million.

(b) Represents net pending securities sales and purchases.

	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trust		Other Special Use Funds		Total
Equity securities	$	402,008	$	45,130	$	447,138		$	222,147	$	(459	)
Available for sale-fixed income securities	446,978		190,378		637,356		(a)	8,634		(6,778		)
Other	2,148		593		2,741		(b)	—		—
Total	$	851,134	$	236,101	$	1,087,235		$	230,781	$	(7,237	)

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

(b) Represents net pending securities sales and purchases.

Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Three Months Ended June 30,
	Nuclear Decommissioning Trust			Other Special Use Funds		Total
2019
Realized gains	$	2,643		$	—	$	2,643
Realized losses	(1,700		)	—		(1,700		)
Proceeds from the sale of securities (a)	93,559			36,747		130,306
2018
Realized gains	$	1,484		$	—	$	1,484
Realized losses	(2,978		)	—		(2,978		)
Proceeds from the sale of securities (a)	122,790			2,426		125,216

(a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

	Six Months Ended June 30,
	Nuclear Decommissioning Trust			Other Special Use Funds		Total
2019
Realized gains	$	3,746		$	—	$	3,746
Realized losses	(3,105		)	—		(3,105		)
Proceeds from the sale of securities (a)	216,152			93,202		309,354
2018
Realized gains	$	2,298		$	1	$	2,299
Realized losses	(5,025		)	—		(5,025		)
Proceeds from the sale of securities (a)	253,246			4,981		258,227

(a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

     The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2019, is as follows (dollars in thousands):

	Nuclear Decommissioning Trust (a)		Coal Reclamation Escrow Account		Active Union Medical Trust		Total
Less than one year	$	37,373	$	22,253	$	40,219	$	99,845
1 year – 5 years	126,745		17,449		140,569		284,763
5 years – 10 years	113,989		1,807		—		115,796
Greater than 10 years	190,982		5,064		—		196,046
Total	$	469,089	$	46,573	$	180,788	$	696,450

(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.

Fair value of fixed income securities, summarized by contractual maturities

     The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2019, is as follows (dollars in thousands):

	Nuclear Decommissioning Trust (a)		Coal Reclamation Escrow Account		Active Union Medical Trust		Total
Less than one year	$	37,373	$	22,253	$	40,219	$	99,845
1 year – 5 years	126,745		17,449		140,569		284,763
5 years – 10 years	113,989		1,807		—		115,796
Greater than 10 years	190,982		5,064		—		196,046
Total	$	469,089	$	46,573	$	180,788	$	696,450

(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.

XML

Changes in Accumulated Other Comprehensive Loss (Tables)

6 Months Ended

Jun. 30, 2019

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component

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 and six months ended June 30, 2019 and 2018 (dollars in thousands):

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Three Months Ended June 30
Balance March 31, 2019	$	(45,118	)		$	(1,383	)		$	(46,501	)
OCI (loss) before reclassifications	(2,422		)		—				(2,422		)
Amounts reclassified from accumulated other comprehensive loss	883			(a)	404			(b)	1,287
Balance June 30, 2019	$	(46,657	)		$	(979	)		$	(47,636	)
Balance March 31, 2018	$	(49,494	)		$	(2,847	)		$	(52,341	)
OCI (loss) before reclassifications	(5,928		)		—				(5,928		)
Amounts reclassified from accumulated other comprehensive loss	1,189			(a)	456			(b)	1,645
Balance June 30, 2018	$	(54,233	)		$	(2,391	)		$	(56,624	)

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Six Months Ended June 30
Balance December 31, 2018	$	(45,997	)		$	(1,711	)		$	(47,708	)
OCI (loss) before reclassifications	(2,422		)		—				(2,422		)
Amounts reclassified from accumulated other comprehensive loss	1,762			(a)	732			(b)	2,494
Balance June 30, 2019	$	(46,657	)		$	(979	)		$	(47,636	)
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)
OCI (loss) before reclassifications	(5,928		)		(96		)		(6,024		)
Amounts reclassified from accumulated other comprehensive loss	2,089			(a)	865			(b)	2,954
Reclassification of income tax effect related to tax reform	(7,954		)	(c)	(598		)	(c)	(8,552		)
Balance June 30, 2018	$	(54,233	)		$	(2,391	)		$	(56,624	)

(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.

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 and six months ended June 30, 2019 and 2018 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Three Months Ended June 30
Balance March 31, 2019	$	(24,644	)		$	(1,383	)		$	(26,027	)
OCI (loss) before reclassifications	(2,414		)		—				(2,414		)
Amounts reclassified from accumulated other comprehensive loss	761			(a)	404			(b)	1,165
Balance June 30, 2019	$	(26,297	)		$	(979	)		$	(27,276	)
Balance March 31, 2018	$	(28,004	)		$	(2,847	)		$	(30,851	)
OCI (loss) before reclassifications	(5,790		)		—				(5,790		)
Amounts reclassified from accumulated other comprehensive loss	1,026			(a)	456			(b)	1,482
Balance June 30, 2018	$	(32,768	)		$	(2,391	)		$	(35,159	)

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Six Months Ended June 30
Balance December 31, 2018	$	(25,396	)		$	(1,711	)		$	(27,107	)
OCI (loss) before reclassifications	(2,414		)		—				(2,414		)
Amounts reclassified from accumulated other comprehensive loss	1,513			(a)	732			(b)	2,245
Balance June 30, 2019	$	(26,297	)		$	(979	)		$	(27,276	)
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)
OCI (loss) before reclassifications	(5,790		)		(96		)		(5,886		)
Amounts reclassified from accumulated other comprehensive loss	1,883			(a)	865			(b)	2,748
Reclassification of income tax effect related to tax reform	(4,440		)	(c)	(598		)	(c)	(5,038		)
Balance June 30, 2018	$	(32,768	)		$	(2,391	)		$	(35,159	)

(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.

XML

Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Lease cost

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

	June 30, 2019
Weighted average remaining lease term	8 years
Weighted average discount rate (a)	3.84	%

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

	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	11,987

The following tables provide information related to our lease costs for the three and six months ended June 30, 2019 (dollars in thousands):

	Three Months Ended June 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	14,063	$	4,414	$	18,477
Variable lease cost	41,529		360		41,889
Short-term lease cost	—		1,812		1,812
Total lease cost	$	55,592	$	6,586	$	62,178

	Six Months Ended June 30, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	14,063	$	8,762	$	22,825
Variable lease cost	58,820		360		59,180
Short-term lease cost	—		2,665		2,665
Total lease cost	$	72,883	$	11,787	$	84,670

Schedule of future minimum payments

The following table provides information related to the maturity of our operating lease liabilities at June 30, 2019 (dollars in thousands):

	June 30, 2019
Year	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
2019 (remaining six months of 2019)	$	49,051	$	7,335	$	56,386
2020	—		12,868		12,868
2021	—		10,029		10,029
2022	—		6,988		6,988
2023	—		5,838		5,838
2024	—		3,691		3,691
Thereafter	—		38,506		38,506
Total lease commitments	49,051		85,255		134,306
Less imputed interest	294		20,411		20,705
Total lease liabilities	$	48,757	$	64,844	$	113,601

We recognize lease assets and liabilities upon lease commencement. At June 30, 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. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million over the term of the arrangements.

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

XML

Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash paid during the period for:
Income taxes, net of refunds	$ 10,788	$ 10,032
Interest, net of amounts capitalized	114,717	104,249
Significant non-cash investing and financing activities:
Accrued capital expenditures	108,056	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562	0
Dividends accrued but not yet paid	82,824	77,821
APS
Cash paid during the period for:
Income taxes, net of refunds	35,573	24,689
Interest, net of amounts capitalized	107,169	98,478
Significant non-cash investing and financing activities:
Accrued capital expenditures	108,056	65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	4,562	0
Dividends accrued but not yet paid	$ 82,800	$ 77,800

XML

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Operating revenues	$ 869,501	$ 974,123	$ 1,610,031	$ 1,666,837
Regulatory cost recovery revenue	12,000	20,000	32,000	27,000
Electric Service | Retail residential electric service
Disaggregation of Revenue [Line Items]
Operating revenues	432,568	500,247	784,134	816,922
Electric Service | Retail non-residential electric service
Disaggregation of Revenue [Line Items]
Operating revenues	395,929	435,500	728,597	778,689
Electric Service | Wholesale energy sales
Disaggregation of Revenue [Line Items]
Operating revenues	21,991	15,392	58,443	27,481
Transmission Services For Others
Disaggregation of Revenue [Line Items]
Operating revenues	15,157	15,489	30,406	30,334
Other sources
Disaggregation of Revenue [Line Items]
Operating revenues	3,856	7,495	8,451	13,411
Electric and Transmission Service
Disaggregation of Revenue [Line Items]
Operating revenues	$ 858,000	$ 954,000	$ 1,578,000	$ 1,640,000

XML

Long-Term Debt and Liquidity Matters - Narrative (Details)	May 09, 2019 USD ($)	Mar. 01, 2019 USD ($)	Feb. 26, 2019 USD ($)	Jun. 30, 2019 USD ($) Facility	May 08, 2019 USD ($)	Feb. 28, 2019 USD ($)
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing June 2019
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)					$ 150,000,000
Pinnacle West | Revolving Credit Facility | Revolving credit Facility maturing July 2023
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)				$ 300,000,000
Current borrowing capacity on credit facility				200,000,000
Long-term line of credit				0
Pinnacle West | Term Loan
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)	$ 50,000,000
Long-term line of credit				46,000,000
Pinnacle West | Letter of Credit | Revolving credit Facility maturing July 2023
Long-Term Debt and Liquidity Matters
Outstanding letters of credit				0
Pinnacle West | Commercial paper | Revolving credit Facility maturing July 2023
Long-Term Debt and Liquidity Matters
Commercial paper				10,000,000
APS | Term Loan
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)			$ 200,000,000
APS | Senior notes
Long-Term Debt and Liquidity Matters
Debt instrument, face amount						$ 300,000,000
Debt instrument, interest rate		8.75%				4.25%
APS | Revolving Credit Facility | Revolving credit Facility maturing July 2023
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)				700,000,000
Current borrowing capacity on credit facility				500,000,000
APS | Revolving Credit Facility | Term Loan Facility
Long-Term Debt and Liquidity Matters
Extinguishment of debt		$ 500,000,000
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)				1,400,000,000
Current borrowing capacity on credit facility				1,000,000,000
Long-term line of credit				$ 0
Number of line of credit facilities | Facility				2
APS | Revolving Credit Facility | Revolving credit facility maturing June 2022
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)				$ 700,000,000
Current borrowing capacity on credit facility				500,000,000
APS | Commercial paper
Long-Term Debt and Liquidity Matters
Maximum commercial paper support available under credit facility				500,000,000
APS | Commercial paper | Revolving Credit Facility Maturing in 2022 and 2023
Long-Term Debt and Liquidity Matters
Commercial paper				$ 377,000,000
LIBOR | Pinnacle West | Term Loan
Long-Term Debt and Liquidity Matters
Debt instrument, basis spread on variable rate	0.55%
LIBOR | APS | Term Loan
Long-Term Debt and Liquidity Matters
Debt instrument, basis spread on variable rate			0.50%

XML

Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 5,136,879	$ 5,138,232
Fair Value	5,568,215	5,233,563
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	449,111	448,796
Fair Value	449,124	443,955
APS
Estimated fair value of long-term debt, including current maturities
Carrying Amount	4,687,768	4,689,436
Fair Value	$ 5,119,091	$ 4,789,608

XML

Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS	Jan. 03, 2018 Customer	Nov. 13, 2017 USD ($)	Mar. 27, 2017 USD ($) $ / kWh	Jun. 30, 2019 appeal
Public Utilities, General Disclosures [Line Items]
Approximate percentage of increase in average customer bill			3.28%
Approximate percentage of increase in average residential customer bill	4.54%		4.54%
Net retail base rate, increase			$ 94,600,000
Non-fuel and non-depreciation base rate, increase			87,200,000
Fuel-related base rate decrease			53,600,000
Base rate increase, changes in depreciation schedules			$ 61,000,000.0
Authorized return on common equity (as a percent)			10.00%
Percentage of debt in capital structure			44.20%
Percentage of common equity in capital structure			55.80%
Rate matter, resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh			0.129
Periodic metering infrastructure opt-out fee		$ 5
Number of appeals | appeal				2
Number of customers named in complaint | Customer	25
AZ Sun Program Phase 2
Public Utilities, General Disclosures [Line Items]
Public utilities, minimum annual renewable energy standard and tariff			$ 10,000,000
Public utilities, maximum annual renewable energy standard and tariff			$ 15,000,000
Minimum
Public Utilities, General Disclosures [Line Items]
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh			0.00016
Maximum
Public Utilities, General Disclosures [Line Items]
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh			0.00050

XML

Regulatory Matters - Cost Recovery Mechanism and Net Metering (Details)																			1 Months Ended	6 Months Ended		12 Months Ended
	Jun. 01, 2019 USD ($)	Apr. 10, 2019 USD ($)	Feb. 15, 2019 USD ($)	Feb. 01, 2019 $ / kWh	Aug. 13, 2018 USD ($)	Jun. 01, 2018 USD ($)	May 01, 2018 $ / kWh	Feb. 20, 2018	Feb. 15, 2018 USD ($)	Feb. 01, 2018 $ / kWh	Jan. 08, 2018 USD ($)	Nov. 20, 2017 USD ($)	Aug. 19, 2017 $ / kWh	Jun. 01, 2017 USD ($)	Feb. 01, 2017 $ / kWh	Jan. 13, 2017 USD ($)	Dec. 20, 2016 $ / kWh	Feb. 01, 2016 $ / kWh	Aug. 31, 2016	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2017 USD ($) $ / kWh	Dec. 31, 2012 $ / kWh	Jul. 01, 2019 USD ($)	Dec. 31, 2018 USD ($)	Jun. 29, 2018 USD ($)	Nov. 14, 2017 USD ($)	Sep. 01, 2017 USD ($)	Jun. 30, 2017 USD ($)
Change in regulatory asset
Deferred fuel and purchased power costs — current period																				$ 16,702,000	$ 50,112,000
Amounts charged to customers																				(23,307,000)	(50,851,000)
Ballot Initiative, proposed required energy supply from renewable sources (as a percent)								50.00%
APS
Change in regulatory asset
Deferred fuel and purchased power costs — current period																				16,702,000	50,112,000
Amounts charged to customers																				$ (23,307,000)	(50,851,000)
Lost Fixed Cost Recovery Mechanisms | APS
Change in regulatory asset
Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh																								0.031
Fixed costs recoverable per non-residential power lost (in dollars per kWh) | $ / kWh																								0.023
Fixed cost recoverable per power lost (in dollars per kWh) | $ / kWh																							0.025
Percentage of retail revenues																				1.00%
Amount of adjustment representing prorated sales losses approval																$ 63,700,000
Increase (decrease) in amount of adjustment representing prorated sales losses			$ (24,500,000)						$ (3,000,000)
Amount of adjustment representing prorated sales losses pending approval			$ 36,200,000						$ 60,700,000
ACC | APS
Change in regulatory asset
Program term																			2 years
Gross-up for revenue requirement of rate regulation		$ 34,500,000			$ 86,500,000						$ 119,100,000
Deferred taxes amortization, period		28 years 6 months
ACC | RES | APS
Settlement Agreement
Plan term																				5 years
ACC | RES 2018 | APS
Settlement Agreement
Amount of proposed budget																											$ 89,900,000			$ 90,000,000
ACC | RES 2018 | APS | Solar Communities
Change in regulatory asset
Program term												3 years
ACC | Demand Side Management Adjustor Charge 2018 | APS
Settlement Agreement
Amount of proposed budget																										$ 34,100,000		$ 52,600,000	$ 52,600,000
ACC | Power Supply Adjustor (PSA) | APS
Change in regulatory asset
Beginning balance																				$ 37,164,000	75,637,000	$ 37,164,000
Deferred fuel and purchased power costs — current period																				16,702,000	50,112,000
Amounts charged to customers																				(23,307,000)	(50,851,000)
Ending balance																				30,559,000	$ 74,898,000		$ 75,637,000
PSA rate (in dollars per kWh) | $ / kWh				0.001658						0.004555			0.000555		(0.001348)
PSA rate for prior year (in dollars per kWh) | $ / kWh				0.000536						0.002009			0.000876		(0.001027)
Forward component of increase in PSA (in dollars per kWh) | $ / kWh				0.001122						0.002546			(0.000321)		(0.000321)
Maximum increase (decrease) in PSA rate | $ / kWh										0.004
Fuel and purchased power costs, excess annual limit																				$ 16,400,000
ACC | Net Metering | APS
Change in regulatory asset
Cost of service, resource comparison proxy method, maximum annual percentage decrease																	10.00%
Cost of service for interconnected DG system customers, grandfathered period																	20 years
Cost of service for new customers, guaranteed export price period																	10 years
First-year export energy price (in dollars per kWh) | $ / kWh																	0.129
Second-year export energy price (in dollars per kWh) | $ / kWh							0.116
United States Federal Energy Regulatory Commission | Open Access Transmission Tariff | APS
Change in regulatory asset
Increase (decrease) in annual wholesale transmission rates	$ (4,900,000)					$ (22,700,000)								$ (35,100,000)
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS
Change in regulatory asset
Historical component of increase in PSA (in dollars per kWh) | $ / kWh				(0.002897)														0.001678
Minimum | ACC | RES 2018 | APS | Solar Communities
Change in regulatory asset
Required annual capital investment												$ 10,000,000
Maximum | ACC | RES 2018 | APS | Solar Communities
Change in regulatory asset
Required annual capital investment												$ 15,000,000
Subsequent Event | ACC | RES 2018 | APS
Settlement Agreement
Amount of proposed budget																									$ 86,300,000
Forecast | Minimum | ACC | APS
Change in regulatory asset
Operating Results																						5,000,000
Forecast | Maximum | ACC | APS
Change in regulatory asset
Operating Results																						$ 10,000,000

XML

Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions			1 Months Ended		3 Months Ended	6 Months Ended
	Dec. 23, 2014	Dec. 30, 2013	Sep. 30, 2018	Apr. 30, 2018	Jun. 30, 2016	Jun. 30, 2019	Dec. 31, 2015
SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Ownership interest acquired		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1		$ 58.5	$ 67.5
Net receipt due to negotiation of alternate arrangement		$ 40.0
Four Corners cost deferral | SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Regulatory assets, non-current						$ 44.0
Regulatory noncurrent asset amortization period						10 years
Retired power plant costs
Business Acquisition [Line Items]
Net book value						$ 81.0
Navajo Plant
Business Acquisition [Line Items]
Net book value						$ 83.0
Four Corners | SCE
Business Acquisition [Line Items]
Regulatory assets, non-current							$ 12.0
Regulatory asset, write off amount					$ 12.0

XML

Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Detail of regulatory assets
Current	$ 184,459	$ 166,902
Non-Current	1,321,431	1,342,941
Pension
Detail of regulatory assets
Current	0	0
Non-Current	712,907	733,351
Retired power plant costs
Detail of regulatory assets
Current	28,182	28,182
Non-Current	153,122	167,164
Income taxes — allowance for funds used during construction (AFUDC) equity
Detail of regulatory assets
Current	6,457	6,457
Non-Current	152,388	151,467
Deferred fuel and purchased power — mark-to-market (Note 7)
Detail of regulatory assets
Current	55,729	31,728
Non-Current	21,516	23,768
Deferred fuel and purchased power
Detail of regulatory assets
Current	30,559	37,164
Non-Current	0	0
Four Corners cost deferral
Detail of regulatory assets
Current	8,077	8,077
Non-Current	36,190	40,228
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Current	1,079	1,079
Non-Current	25,170	25,522
Lost fixed cost recovery
Detail of regulatory assets
Current	25,746	32,435
Non-Current	0	0
Palo Verde VIEs (Note 6)
Detail of regulatory assets
Current	0	0
Non-Current	20,325	20,015
Deferred compensation
Detail of regulatory assets
Current	0	0
Non-Current	37,572	36,523
Deferred property taxes
Detail of regulatory assets
Current	8,569	8,569
Non-Current	62,072	66,356
Loss on reacquired debt
Detail of regulatory assets
Current	1,637	1,637
Non-Current	12,850	13,668
Tax expense of Medicare subsidy
Detail of regulatory assets
Current	1,235	1,235
Non-Current	5,772	6,176
TCA balancing account
Detail of regulatory assets
Current	5,381	3,860
Non-Current	3,895	772
AG-1 deferral
Detail of regulatory assets
Current	2,787	2,654
Non-Current	4,110	5,819
Mead-Phoenix transmission line CIAC
Detail of regulatory assets
Current	332	332
Non-Current	9,878	10,044
Coal reclamation
Detail of regulatory assets
Current	1,546	1,546
Non-Current	16,250	15,607
SCR deferral
Detail of regulatory assets
Current	0	0
Non-Current	37,919	23,276
Tax expense adjustor mechanism
Detail of regulatory assets
Current	3,149	0
Non-Current	0	0
Ocotillo deferral
Detail of regulatory assets
Current	0	0
Non-Current	9,495	0
Other
Detail of regulatory assets
Current	3,994	1,947
Non-Current	$ 0	$ 3,185

XML

Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Detail of regulatory liabilities
Current	$ 231,857	$ 165,876
Non-Current	2,287,892	2,325,976
Asset retirement obligations
Detail of regulatory liabilities
Current	0	0
Non-Current	359,912	278,585
Removal costs
Detail of regulatory liabilities
Current	50,701	39,866
Non-Current	153,847	177,533
Other postretirement benefits
Detail of regulatory liabilities
Current	37,821	37,864
Non-Current	105,214	125,903
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Current	2,164	2,164
Non-Current	50,414	51,120
Income taxes — change in rates
Detail of regulatory liabilities
Current	2,764	2,769
Non-Current	69,171	70,069
Spent nuclear fuel
Detail of regulatory liabilities
Current	6,578	6,503
Non-Current	53,769	57,002
Renewable energy standard
Detail of regulatory liabilities
Current	40,639	44,966
Non-Current	4,950	20
Demand side management
Detail of regulatory liabilities
Current	7,191	14,604
Non-Current	24,146	4,123
Sundance maintenance
Detail of regulatory liabilities
Current	1,641	1,278
Non-Current	15,495	17,228
Deferred gains on utility property
Detail of regulatory liabilities
Current	3,423	4,423
Non-Current	5,372	6,581
Four Corners coal reclamation
Detail of regulatory liabilities
Current	1,858	1,858
Non-Current	17,540	17,871
Tax expense adjustor mechanism
Detail of regulatory liabilities
Current	1,663	3,237
Non-Current	0	0
Other
Detail of regulatory liabilities
Current	461	42
Non-Current	8,213	3,541
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)
Detail of regulatory liabilities
Current	68,651	0
Non-Current	1,178,216	1,272,709
United States Federal Energy Regulatory Commission | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)
Detail of regulatory liabilities
Current	6,302	6,302
Non-Current	$ 241,633	$ 243,691

XML

Retirement Plans and Other Postretirement Benefits - Narrative (Details)	6 Months Ended
	Jun. 30, 2019 USD ($)
Pension Benefits
Contributions
Voluntary employer contributions to pension plan	$ 120,000,000
Minimum employer contributions for the next three years	0
Maximum employer contributions for the next two years (up to)	350,000,000
Other Benefits
Contributions
Estimated future employer contributions in next three years	$ 0

XML

Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Amortization of:
Portion of cost (credit) charged to expense	$ (6,374)	$ (12,006)	$ (11,488)	$ (24,865)
Pension Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	12,408	14,121	24,951	28,334
Interest cost on benefit obligation	34,069	31,338	68,421	62,345
Expected return on plan assets	(43,049)	(45,759)	(85,942)	(91,426)
Amortization of:
Prior service credit	0	0	0	0
Net actuarial loss	10,053	8,259	21,292	16,041
Net periodic benefit cost (credit)	13,481	7,959	28,722	15,294
Portion of cost (credit) charged to expense	7,000	2,769	15,244	5,011
Other Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	4,470	5,445	9,184	10,550
Interest cost on benefit obligation	7,421	6,973	14,947	14,074
Expected return on plan assets	(9,603)	(10,520)	(19,206)	(21,041)
Amortization of:
Prior service credit	(9,455)	(9,461)	(18,910)	(18,921)
Net actuarial loss	0	0	0	0
Net periodic benefit cost (credit)	(7,167)	(7,563)	(13,985)	(15,338)
Portion of cost (credit) charged to expense	$ (5,063)	$ (5,119)	$ (9,880)	$ (10,724)

XML

Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2019 USD ($) power_plant	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) power_plant Lease	Jun. 30, 2018 USD ($)	Dec. 31, 1986 Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,874,000	$ 4,874,000	$ 9,747,000	$ 9,747,000
APS
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts	3		3		3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,874,000	4,874,000	$ 9,747,000	9,747,000
APS | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 5,000,000	$ 5,000,000	10,000,000	$ 10,000,000
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period			299,000,000
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period			$ 456,000,000
APS | Consolidation of VIEs | Through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease			1
APS | Consolidation of VIEs | Through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease			2
APS | Consolidation of VIEs | Period 2017 through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments			$ 23,000,000
APS | Consolidation of VIEs | Period 2024 through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments			$ 16,000,000
APS | Consolidation of VIEs | Period 2024 through 2033 | Maximum
Palo Verde Sale Leaseback Variable Interest Entities
Lease period (up to)			2 years

XML

Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$ 103,841	$ 105,775
Equity — Noncontrolling interests	124,165	125,790
APS
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	103,841	105,775
Equity — Noncontrolling interests	124,165	125,790
APS | Consolidation of VIEs
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	103,841	105,775
Equity — Noncontrolling interests	$ 124,165	$ 125,790

XML

Derivative Accounting - Narrative (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Commodity Contracts
Derivative Accounting
Additional collateral to counterparties for energy related non-derivative instrument contracts	$ 95,000,000		$ 95,000,000
Commodity Contracts | Designated as Hedging Instruments
Derivative Accounting
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	$ 0	$ 0	0	$ 0
Estimated loss before income taxes to be reclassified from accumulated other comprehensive income			$ 1,000,000
APS
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%		100.00%

XML

Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts GWh in Thousands, Bcf in Thousands	Jun. 30, 2019 GWh Bcf	Dec. 31, 2018 GWh Bcf
Outstanding gross notional amount of derivatives
Power | GWh	1,000	250
Gas | Bcf	218	218

XML

Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Designated as Hedging Instruments
Gains and losses from derivative instruments
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	$ 0	$ 0	$ 0	$ 0
Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(538,000)	(606,000)	(974,000)	(1,097,000)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income	(49,686,000)	3,043,000	(41,516,000)	(32,265,000)
Not Designated as Hedging Instruments | Operating revenues
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income	0	(341,000)	0	(1,560,000)
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income	$ (49,686,000)	$ 3,384,000	$ (41,516,000)	$ (30,705,000)

XML

Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($)	Jun. 30, 2019	Dec. 31, 2018
Assets
Gross Recognized Derivatives	$ 535,000	$ 1,113,000
Liabilities
Amount Reported on Balance Sheets	(80,426,000)	(60,037,000)
Commodity Contracts
Assets
Gross Recognized Derivatives	3,634,000	3,142,000
Amounts Offset	(2,939,000)	(2,185,000)
Net Recognized Derivatives	695,000	957,000
Other	160,000	(156,000)
Amount Reported on Balance Sheets	535,000	1,113,000
Liabilities
Gross Recognized Derivatives	(82,180,000)	(60,912,000)
Amounts Offset	2,939,000	2,185,000
Net Recognized Derivatives	(79,241,000)	(58,727,000)
Other	(1,185,000)	(1,310,000)
Amount Reported on Balance Sheets	(80,426,000)	(60,037,000)
Assets and Liabilities
Gross Recognized Derivatives	(78,546,000)	(57,770,000)
Amounts Offset	0	0
Net Recognized Derivatives	(78,546,000)	(57,770,000)
Other	(1,345,000)	(1,154,000)
Amount Reported on Balance Sheets	(79,891,000)	(58,924,000)
Commodity Contracts | Current assets
Assets
Gross Recognized Derivatives	3,558,000	3,106,000
Amounts Offset	(2,939,000)	(2,149,000)
Net Recognized Derivatives	619,000	957,000
Other	160,000	(156,000)
Amount Reported on Balance Sheets	459,000	1,113,000
Commodity Contracts | Investments and other assets
Assets
Gross Recognized Derivatives	76,000	36,000
Amounts Offset	0	(36,000)
Net Recognized Derivatives	76,000	0
Other	0	0
Amount Reported on Balance Sheets	76,000	0
Commodity Contracts | Current liabilities
Liabilities
Gross Recognized Derivatives	(60,588,000)	(36,345,000)
Amounts Offset	2,939,000	2,149,000
Net Recognized Derivatives	(57,649,000)	(34,196,000)
Other	(1,185,000)	(1,310,000)
Amount Reported on Balance Sheets	(58,834,000)	(35,506,000)
Commodity Contracts | Deferred credits and other
Liabilities
Gross Recognized Derivatives	(21,592,000)	(24,567,000)
Amounts Offset	0	36,000
Net Recognized Derivatives	(21,592,000)	(24,531,000)
Other	0	0
Amount Reported on Balance Sheets	$ (21,592,000)	$ (24,531,000)

XML

Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Jun. 30, 2019 USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	$ 82,064
Cash collateral posted	0
Additional cash collateral in the event credit-risk-related contingent features were fully triggered	$ 80,804

XML

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)			2 Months Ended	6 Months Ended	84 Months Ended
	Oct. 31, 2018 USD ($)	Aug. 18, 2014 USD ($)	Apr. 10, 2019 USD ($)	Jun. 30, 2019 USD ($) power_plant	Jun. 30, 2018 USD ($) time_period claim	Dec. 31, 1986 Trust
Commitments and Contingencies
Purchase obligation, increase				$ 100,000,000
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount	$ 10,200,000	$ 57,400,000	$ 10,200,000		$ 74,200,000
APS
Commitments and Contingencies
Maximum insurance against public liability per occurrence for a nuclear incident (up to)				13,900,000,000
Maximum available nuclear liability insurance (up to)				450,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program				13,500,000,000
Maximum retrospective premium assessment per reactor for each nuclear liability incident				137,600,000
Annual limit per incident with respect to maximum retrospective premium assessment				$ 20,500,000
Number of VIE lessor trusts				3		3
Maximum potential retrospective assessment per incident of APS				$ 120,100,000
Annual payment limitation with respect to maximum potential retrospective premium assessment				17,900,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde				2,800,000,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment				25,500,000
Collateral assurance provided based on rating triggers				$ 73,400,000
Period to provide collateral assurance based on rating triggers				20 days
APS | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount	$ 3,000,000.0	$ 16,700,000	$ 3,000,000.0		$ 21,600,000
Number of claims submitted | claim					4
Number of settlement agreement time periods | time_period					4

XML

Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - APS - Contaminated groundwater wells $ in Millions				6 Months Ended
	Apr. 05, 2018 plaintiff	Dec. 16, 2016 plaintiff	Aug. 06, 2013 Defendant	Jun. 30, 2019 USD ($)
Loss Contingencies [Line Items]
Costs related to investigation and study under Superfund site | $				$ 2
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant			24
Number of plaintiffs		2
Settled Litigation
Loss Contingencies [Line Items]
Number of plaintiffs	2

XML

Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($) $ in Millions			6 Months Ended	12 Months Ended
	Jul. 03, 2018	Jul. 06, 2016	Jun. 30, 2019	Dec. 31, 2017	Dec. 31, 2018
APS | Letters of Credit Expiring in 2020
Financial Assurances
Outstanding letters of credit			$ 1.7
APS | Surety Bonds Expiring in 2020
Financial Assurances
Surety bonds expiring, amount			17.0
4C Acquisition, LLC | Four Corners
Environmental Matters
Percentage of share of cost of control		7.00%
4C Acquisition, LLC | Coal Supply Agreement Arbitration | Four Corners
Four Corners Coal Supply Agreement
Proceeds from operating and maintenance cost reimbursement				$ 10.0
Reimbursement payments due to 4CA			$ 10.0		$ 20.0
NTEC | Four Corners
Four Corners Coal Supply Agreement
Option to purchase ownership interest (as a percent)	7.00%	7.00%
Proceeds from operating and maintenance cost reimbursement	$ 70.0
NTEC | Coal Supply Agreement Arbitration | Four Corners
Four Corners Coal Supply Agreement
Option to purchase ownership interest (as a percent)		7.00%
Regional Haze Rules | APS | Four Corners Units 4 and 5
Environmental Matters
Percentage of share of cost of control			63.00%
Expected environmental cost			$ 400.0
Regional Haze Rules | APS | Natural gas tolling contract obligations | Four Corners Units 4 and 5
Environmental Matters
Additional percentage share of cost of control			7.00%
Regional Haze Rules | APS | Four Corners | Four Corners Units 4 and 5
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate			$ 45.0
Regional Haze Rules | APS | Navajo Plant
Environmental Matters
Expected environmental cost			200.0
Coal combustion waste | APS | Four Corners
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate			22.0
Coal combustion waste | APS | Navajo Plant
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate			1.0
Coal combustion waste | APS | Cholla and Four Corners
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate			5.0
Minimum | Coal combustion waste | APS | Cholla
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate			$ 15.0

XML

Other Income and Other Expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Other income:
Interest income	$ 2,699	$ 2,408	$ 5,001	$ 4,299
Miscellaneous	5	2	28	4
Total other income	12,885	6,598	20,054	10,583
Other expense:
Non-operating costs	(3,481)	(3,278)	(6,185)	(4,924)
Investment losses — net	(491)	(174)	(729)	(350)
Miscellaneous	(378)	(319)	(1,794)	(1,726)
Total other expense	(4,350)	(3,771)	(8,708)	(7,000)
APS
Other income:
Interest income	1,504	2,046	3,054	3,724
Miscellaneous	6	1	28	3
Total other income	11,691	6,235	18,107	10,007
Other expense:
Non-operating costs	(3,049)	(3,057)	(5,517)	(4,596)
Miscellaneous	(379)	(315)	(1,789)	(1,722)
Total other expense	(3,428)	(3,372)	(7,306)	(6,318)
SCR deferral
Other income:
Debt return on Four Corners SCR (Note 4)	4,887	4,188	9,731	6,280
SCR deferral | APS
Other income:
Debt return on Four Corners SCR (Note 4)	4,887	4,188	9,731	6,280
Ocotillo deferral
Other income:
Debt return on Four Corners SCR (Note 4)	5,294	0	5,294	0
Ocotillo deferral | APS
Other income:
Debt return on Four Corners SCR (Note 4)	$ 5,294	$ 0	$ 5,294	$ 0

XML

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 144,145	$ 166,738	$ 162,063	$ 169,959
Weighted average common shares outstanding - basic (in shares)	112,337	112,115	112,381	112,067
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units (in shares)	314	356	353	415
Weighted average common shares outstanding — diluted (in shares)	112,651	112,471	112,734	112,482
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic (in dollars per share)	$ 1.28	$ 1.49	$ 1.44	$ 1.52
Net income attributable to common shareholders - diluted (in dollars per share)	$ 1.28	$ 1.48	$ 1.44	$ 1.51

XML

Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Assets
Cash equivalents		$ 1,200
Commodity contracts, assets	$ 535	1,113
Commodity contracts, liabilities	(3,099)	(2,029)
Nuclear decommissioning trust	950,448	851,134
Nuclear decommissioning trust, other	476,040	398,953
Other special use funds	241,558	236,101
Other special use funds, other	997	593
Total assets	1,192,541	1,089,548
Total assets, other	473,938	397,517
Liabilities
Total, other	1,755	875
Amount reported on balance sheet	(80,426)	(60,037)
Equity securities
Assets
Nuclear decommissioning trust	11,984	7,351
Nuclear decommissioning trust, other	6,665	2,148
Other special use funds	14,197	45,723
Other special use funds, other	997	593
U.S. commingled equity funds
Assets
Nuclear decommissioning trust	469,375	396,805
U.S. Treasury debt
Assets
Nuclear decommissioning trust	162,044	148,173
Other special use funds	214,712	173,310
Corporate debt
Assets
Nuclear decommissioning trust	115,674	96,656
Mortgage-backed securities
Assets
Nuclear decommissioning trust	113,179	113,115
Municipal bonds
Assets
Nuclear decommissioning trust	67,158	79,073
Other special use funds	12,649	17,068
Other fixed income
Assets
Nuclear decommissioning trust	11,034	9,961
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash equivalents		1,200
Commodity contracts, assets	0	0
Nuclear decommissioning trust	167,363	153,376
Other special use funds	227,912	218,440
Total assets	395,275	373,016
Liabilities
Gross derivative liability	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities
Assets
Nuclear decommissioning trust	5,319	5,203
Other special use funds	13,200	45,130
Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury debt
Assets
Nuclear decommissioning trust	162,044	148,173
Other special use funds	214,712	173,310
Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate debt
Assets
Nuclear decommissioning trust	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Assets
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other fixed income
Assets
Nuclear decommissioning trust	0	0
Significant Other Observable Inputs (Level 2)
Assets
Cash equivalents		0
Commodity contracts, assets	3,198	3,140
Nuclear decommissioning trust	307,045	298,805
Other special use funds	12,649	17,068
Total assets	322,892	319,013
Liabilities
Gross derivative liability	(68,992)	(52,696)
Significant Other Observable Inputs (Level 2) | Equity securities
Assets
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Significant Other Observable Inputs (Level 2) | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	0	0
Significant Other Observable Inputs (Level 2) | U.S. Treasury debt
Assets
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	115,674	96,656
Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	113,179	113,115
Significant Other Observable Inputs (Level 2) | Municipal bonds
Assets
Nuclear decommissioning trust	67,158	79,073
Other special use funds	12,649	17,068
Significant Other Observable Inputs (Level 2) | Other fixed income
Assets
Nuclear decommissioning trust	11,034	9,961
Significant Unobservable Inputs (Level 3)
Assets
Cash equivalents		0
Commodity contracts, assets	436	2
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Total assets	436	2
Liabilities
Gross derivative liability	(13,189)	(8,216)
Significant Unobservable Inputs (Level 3) | Equity securities
Assets
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Significant Unobservable Inputs (Level 3) | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	0	0
Significant Unobservable Inputs (Level 3) | U.S. Treasury debt
Assets
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Significant Unobservable Inputs (Level 3) | Corporate debt
Assets
Nuclear decommissioning trust	0	0
Significant Unobservable Inputs (Level 3) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	0	0
Significant Unobservable Inputs (Level 3) | Municipal bonds
Assets
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Significant Unobservable Inputs (Level 3) | Other fixed income
Assets
Nuclear decommissioning trust	0	0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	$ 469,375	$ 396,805

XML

Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) - Forward Price $ in Thousands	Jun. 30, 2019 USD ($) $ / MWh	Dec. 31, 2018 USD ($) $ / MWh
Significant Unobservable Inputs (Level 3)
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	$ 436	$ 2
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $	13,189	$ 8,216
Electricity forward contracts | Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input		17.88
Electricity forward contracts | Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input		37.03
Electricity forward contracts | Significant Unobservable Inputs (Level 3)
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	294	$ 0
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $	$ 11,675	$ 2,456
Electricity forward contracts | Significant Unobservable Inputs (Level 3) | Weighted-Average
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input	26.78	26.10
Electricity forward contracts | Significant Unobservable Inputs (Level 3) | Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input	18.27
Electricity forward contracts | Significant Unobservable Inputs (Level 3) | Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input	30.11
Natural gas contracts | Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input		1.79
Natural gas contracts | Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input		2.92
Natural gas contracts | Significant Unobservable Inputs (Level 3)
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	$ 142	$ 2
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $	$ 1,514	$ 5,760
Natural gas contracts | Significant Unobservable Inputs (Level 3) | Weighted-Average
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input	2.41	2.48
Natural gas contracts | Significant Unobservable Inputs (Level 3) | Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input	(0.23)
Natural gas contracts | Significant Unobservable Inputs (Level 3) | Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input	2.88

XML

Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net derivative balance at beginning of period	$ (5,612)	$ (19,754)	$ (8,214)	$ (18,256)
Deferred as a regulatory asset or liability	(8,731)	(989)	(10,310)	(3,311)
Settlements	2,431	494	2,949	1,276
Transfers into Level 3 from Level 2	(3,096)	(2,534)	(3,098)	(4,979)
Transfers from Level 3 into Level 2	2,255	13,425	5,920	15,912
Net derivative balance at end of period	(12,753)	(9,358)	(12,753)	(9,358)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0	$ 0	$ 0

XML

Fair Value Measurements - Financial Instruments Not Carried at Fair Value (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Stated interest rate for notes receivable	3.90%
Note receivable, net book value	$ 53	$ 61

XML

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Nuclear decommissioning trust fund assets
Fair Value	$ 1,192,006		$ 1,192,006		$ 1,087,235
Total Unrealized Gains	315,933		315,933		230,781
Total Unrealized Losses	(696)		(696)		(7,237)
Amortized cost	672,000		672,000		635,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	2,643	$ 1,484	3,746	$ 2,299
Realized losses	(1,700)	(2,978)	(3,105)	(5,025)
Proceeds from the sale of securities	130,306	125,216	309,354	258,227
Equity securities
Nuclear decommissioning trust fund assets
Equity securities	487,894		487,894		447,138
Total Unrealized Gains	291,295		291,295		222,147
Total Unrealized Losses	0		0		459
Available for sale-fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	696,450		696,450		637,356
Total Unrealized Gains	24,638		24,638		8,634
Total Unrealized Losses	(696)		(696)		(6,778)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	99,845		99,845
1 year – 5 years	284,763		284,763
5 years – 10 years	115,796		115,796
Greater than 10 years	196,046		196,046
Total	696,450		696,450
Other
Nuclear decommissioning trust fund assets
Fair Value	7,662		7,662		2,741
Total Unrealized Gains	0		0		0
Total Unrealized Losses	0		0		0
Nuclear Decommissioning Trust
Nuclear decommissioning trust fund assets
Fair Value	950,448		950,448		851,134
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	2,643	1,484	3,746	2,298
Realized losses	(1,700)	(2,978)	(3,105)	(5,025)
Proceeds from the sale of securities	93,559	122,790	216,152	253,246
Nuclear Decommissioning Trust | Equity securities
Nuclear decommissioning trust fund assets
Equity securities	474,694		474,694		402,008
Nuclear Decommissioning Trust | Available for sale-fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	469,089		469,089		446,978
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	37,373		37,373
1 year – 5 years	126,745		126,745
5 years – 10 years	113,989		113,989
Greater than 10 years	190,982		190,982
Total	469,089		469,089
Nuclear Decommissioning Trust | Other
Nuclear decommissioning trust fund assets
Fair Value	6,665		6,665		2,148
Other Special Use Funds
Nuclear decommissioning trust fund assets
Fair Value	241,558		241,558		236,101
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	0	0	0	1
Realized losses	0	0	0	0
Proceeds from the sale of securities	36,747	$ 2,426	93,202	$ 4,981
Other Special Use Funds | Equity securities
Nuclear decommissioning trust fund assets
Equity securities	13,200		13,200		45,130
Other Special Use Funds | Available for sale-fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	227,361		227,361		190,378
Other Special Use Funds | Other
Nuclear decommissioning trust fund assets
Fair Value	997		997		$ 593
Coal Reclamation Escrow Account | Available for sale-fixed income securities
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	22,253		22,253
1 year – 5 years	17,449		17,449
5 years – 10 years	1,807		1,807
Greater than 10 years	5,064		5,064
Total	46,573		46,573
Active Union Medical Trust | Available for sale-fixed income securities
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	40,219		40,219
1 year – 5 years	140,569		140,569
5 years – 10 years	0		0
Greater than 10 years	0		0
Total	$ 180,788		$ 180,788

XML

Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		$ 5,381,725	$ 5,153,671	$ 5,348,705	$ 5,135,730
OCI (loss) before reclassifications		(2,422)	(5,928)	(2,422)	(6,024)
Amounts reclassified from accumulated other comprehensive loss		1,287	1,645	2,494	2,954
Reclassification of income tax effect related to tax reform					(8,552)
Balance at end of period		5,357,243	5,159,434	5,357,243	5,159,434
Pension and Other Postretirement Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(45,118)	(49,494)	(45,997)	(42,440)
OCI (loss) before reclassifications		(2,422)	(5,928)	(2,422)	(5,928)
Amounts reclassified from accumulated other comprehensive loss		883	1,189	1,762	2,089
Reclassification of income tax effect related to tax reform					(7,954)
Balance at end of period		(46,657)	(54,233)	(46,657)	(54,233)
Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(1,383)	(2,847)	(1,711)	(2,562)
OCI (loss) before reclassifications		0	0	0	(96)
Amounts reclassified from accumulated other comprehensive loss		404	456	732	865
Reclassification of income tax effect related to tax reform					(598)
Balance at end of period		(979)	(2,391)	(979)	(2,391)
Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(46,501)	(52,341)	(47,708)	(45,002)
Reclassification of income tax effect related to tax reform	[1]				(8,552)
Balance at end of period		(47,636)	(56,624)	(47,636)	(56,624)
APS
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		5,821,026	5,401,512	5,786,797	5,385,869
OCI (loss) before reclassifications		(2,414)	(5,790)
Amounts reclassified from accumulated other comprehensive loss		1,165	1,482
Balance at end of period		5,797,857	5,412,930	5,797,857	5,412,930
APS | Pension and Other Postretirement Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(24,644)	(28,004)	(25,396)	(24,421)
OCI (loss) before reclassifications		(2,414)	(5,790)	(2,414)	(5,790)
Amounts reclassified from accumulated other comprehensive loss		761	1,026	1,513	1,883
Reclassification of income tax effect related to tax reform					(4,440)
Balance at end of period		(26,297)	(32,768)	(26,297)	(32,768)
APS | Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(1,383)	(2,847)	(1,711)	(2,562)
OCI (loss) before reclassifications		0	0	0	(96)
Amounts reclassified from accumulated other comprehensive loss		404	456	732	865
Reclassification of income tax effect related to tax reform					(598)
Balance at end of period		(979)	(2,391)	(979)	(2,391)
APS | Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(26,027)	(30,851)	(27,107)	(26,983)
OCI (loss) before reclassifications				(2,414)	(5,886)
Amounts reclassified from accumulated other comprehensive loss				2,245	2,748
Reclassification of income tax effect related to tax reform	[2]				(5,038)
Balance at end of period		$ (27,276)	$ (35,159)	$ (27,276)	$ (35,159)

[1] 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.

[2] 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.

XML

Income Taxes (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Reduction in net deferred income tax liabilities		$ 1,140.0
Non-depreciation and amortization	$ 19.4

XML

Leases - Additional information (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating Leased Assets [Line Items]
Operating lease right-of-use assets (Note 16)	$ 176,219	$ 194,000	$ 0
Operating lease, liability	113,601	119,000
Other	(40,365)		(129,312)
Other current liabilities	(140,879)		$ (184,229)
Lease not yet commenced	$ 705,000
Accounting Standards Update 2016-02
Operating Leased Assets [Line Items]
Other		85,000
Other current liabilities		$ 10,000

XML

Leases - Lease costs (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Operating Leased Assets [Line Items]
Operating lease cost	$ 18,477	$ 22,825
Variable lease cost	41,889	59,180
Short-term lease cost	1,812	2,665
Total lease cost	62,178	84,670
Purchased Power Lease Contracts
Operating Leased Assets [Line Items]
Operating lease cost	14,063	14,063
Variable lease cost	41,529	58,820
Short-term lease cost	0	0
Total lease cost	55,592	72,883
Land, Property & Equipment Leases
Operating Leased Assets [Line Items]
Operating lease cost	4,414	8,762
Variable lease cost	360	360
Short-term lease cost	1,812	2,665
Total lease cost	$ 6,586	$ 11,787

XML

Leases - Maturity of our operating lease liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Jan. 01, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
2019 (remaining six months of 2019)	$ 56,386
2019			$ 68,246
2020	12,868		12,428
2021	10,029		9,478
2022	6,988		6,513
2023	5,838		5,359
2024	3,691
Thereafter	38,506
Thereafter			42,236
Total lease commitments	134,306		144,260
Less imputed interest	20,705
Total lease liabilities	113,601	$ 119,000
Purchased Power Lease Contracts
Lessee, Lease, Description [Line Items]
2019 (remaining six months of 2019)	49,051
2019			54,499
2020	0		0
2021	0		0
2022	0		0
2023	0		0
2024	0
Thereafter	0
Thereafter			0
Total lease commitments	49,051		54,499
Less imputed interest	294
Total lease liabilities	48,757
Land, Property & Equipment Leases
Lessee, Lease, Description [Line Items]
2019 (remaining six months of 2019)	7,335
2019			13,747
2020	12,868		12,428
2021	10,029		9,478
2022	6,988		6,513
2023	5,838		5,359
2024	3,691
Thereafter	38,506
Thereafter			42,236
Total lease commitments	85,255		$ 89,761
Less imputed interest	20,411
Total lease liabilities	$ 64,844

XML

Leases - Other additional information related to operating lease liabilities (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2019 USD ($)
Leases [Abstract]
Weighted average remaining lease term	8 years
Weighted average discount rate (a)	3.84%
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows	$ 11,987