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 March 31, 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 (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona  85072-3999 (602) 250-1000	86-0512431
1-4473	ARIZONA PUBLIC SERVICE COMPANY (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona  85072-3999 (602) 250-1000	86-0011170

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 April 24, 2019: 112,277,359
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of April 24, 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		4
Item 1.	Financial Statements	4
	Pinnacle West Capital Corporation	5
	Arizona Public Service Company	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	66
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	88
Item 4.	Controls and Procedures	88
Part II		89
Item 1.	Legal Proceedings	89
Item 1A.	Risk Factors	89
Item 5.	Other Information	89
Item 6.	Exhibits	90
Signatures		93

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

2

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.

3

PART I — FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

	Page
Pinnacle West Condensed Consolidated Statements of Income for Three Months Ended March 31, 2019 and 2018	5
Pinnacle West Condensed Consolidated Statements of Comprehensive Income for Three Months Ended March 31, 2019 and 2018	6
Pinnacle West Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018	7
Pinnacle West Condensed Consolidated Statements of Cash Flows for Three Months Ended March 31, 2019 and 2018	9
Pinnacle West Condensed Consolidated Statements of Changes in Equity for Three Months Ended March 31, 2019 and 2018	10
APS Condensed Consolidated Statements of Income for Three Months Ended March 31, 2019 and 2018	11
APS Condensed Consolidated Statements of Comprehensive Income for Three Months Ended March 31, 2019 and 2018	12
APS Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018	13
APS Condensed Consolidated Statements of Cash Flows for Three Months Ended March 31, 2019 and 2018	15
APS Condensed Consolidated Statements of Changes in Equity for Three Months Ended March 31, 2019 and 2018	16
Combined Notes to Condensed Consolidated Financial Statements	17
Note 1. Consolidation and Nature of Operations	17
Note 2. Revenue	18
Note 3. Long-Term Debt and Liquidity Matters	19
Note 4. Regulatory Matters	20
Note 5. Retirement Plans and Other Postretirement Benefits	34
Note 6. Palo Verde Sale Leaseback Variable Interest Entities	35
Note 7. Derivative Accounting	36
Note 8. Commitments and Contingencies	41
Note 9. Other Income and Other Expense	49
Note 10. Earnings Per Share	50
Note 11. Fair Value Measurements	50
Note 12. Investment in Nuclear Decommissioning Trusts and Other Special Use Funds	56
Note 13. New Accounting Standards	59
Note 14. Changes in Accumulated Other Comprehensive Loss	60
Note 15. Income Taxes	61
Note 16. Leases	63

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended   March 31,
	2019			2018
OPERATING REVENUES (NOTE 2)	$	740,530		$	692,714
OPERATING EXPENSES
Fuel and purchased power	230,588			197,110
Operations and maintenance	245,634			265,682
Depreciation and amortization	148,707			144,825
Taxes other than income taxes	55,090			53,600
Other expenses	427			163
Total	680,446			661,380
OPERATING INCOME	60,084			31,334
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	11,188			14,079
Pension and other postretirement non-service credits - net	5,114			12,859
Other income (Note 9)	7,169			3,985
Other expense (Note 9)	(4,358		)	(3,229		)
Total	19,113			27,694
INTEREST EXPENSE
Interest charges	60,653			58,954
Allowance for borrowed funds used during construction	(6,665		)	(6,755		)
Total	53,988			52,199
INCOME BEFORE INCOME TAXES	25,209			6,829
INCOME TAXES	2,418			(1,265		)
NET INCOME	22,791			8,094
Less: Net income attributable to noncontrolling interests (Note 6)	4,873			4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	17,918		$	3,221
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	112,337			112,017
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,735			112,493
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	0.16		$	0.03
Net income attributable to common shareholders — diluted	$	0.16		$	0.03

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

5

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   March 31,
	2019		2018
NET INCOME	$	22,791	$	8,094
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $0 and $96	—		(96		)
Reclassification of net realized loss, net of tax benefit of $108 and $82	328		409
Pension and other postretirement benefits activity, net of tax expense of $288 and $443	879		900
Total other comprehensive income	1,207		1,213
COMPREHENSIVE INCOME	23,998		9,307
Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	19,125	$	4,434

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

6

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2019			December 31, 2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,109		$	5,766
Customer and other receivables	249,568			267,887
Accrued unbilled revenues	114,077			137,170
Allowance for doubtful accounts	(2,455		)	(4,069		)
Materials and supplies (at average cost)	280,857			269,065
Fossil fuel (at average cost)	26,294			25,029
Assets from risk management activities (Note 7)	763			1,113
Deferred fuel and purchased power regulatory asset (Note 4)	7,583			37,164
Other regulatory assets (Note 4)	127,642			129,738
Other current assets	65,951			56,128
Total current assets	876,389			924,991
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	919,309			851,134
Other special use funds (Notes 11 and 12)	238,207			236,101
Other assets	99,446			103,247
Total investments and other assets	1,256,962			1,190,482
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	18,763,499			18,736,628
Accumulated depreciation and amortization	(6,398,512		)	(6,366,014		)
Net	12,364,987			12,370,614
Construction work in progress	1,233,018			1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	104,808			105,775
Intangible assets, net of accumulated amortization	267,998			262,902
Nuclear fuel, net of accumulated amortization	142,610			120,217
Total property, plant and equipment	14,113,421			14,029,570
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,507			1,342,941
Operating lease right-of-use assets (Note 16)	193,897			—
Assets for other postretirement benefits (Note 5)	52,674			46,906
Other	39,257			129,312
Total deferred debits	1,607,335			1,519,159
TOTAL ASSETS	$	17,854,107		$	17,664,202

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

7

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2019			December 31, 2018
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	263,656		$	277,336
Accrued taxes	199,949			154,819
Accrued interest	50,074			61,107
Common dividends payable	—			82,675
Short-term borrowings (Note 3)	244,050			76,400
Current maturities of long-term debt (Note 3)	250,000			500,000
Customer deposits	87,263			91,174
Liabilities from risk management activities (Note 7)	33,289			35,506
Liabilities for asset retirements	22,823			19,842
Operating lease liabilities (Note 16)	65,435			—
Regulatory liabilities (Note 4)	260,404			165,876
Other current liabilities	114,361			184,229
Total current liabilities	1,591,304			1,648,964
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)	4,886,108			4,638,232
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,811,689			1,807,421
Regulatory liabilities (Note 4)	2,272,082			2,325,976
Liabilities for asset retirements	712,885			706,703
Liabilities for pension benefits (Note 5)	384,492			443,170
Liabilities from risk management activities (Note 7)	14,844			24,531
Customer advances	155,894			137,153
Coal mine reclamation	214,037			212,785
Deferred investment tax credit	200,052			200,405
Unrecognized tax benefits	26,042			22,517
Operating lease liabilities (Note 16)	53,704			—
Other	149,249			147,640
Total deferred credits and other	5,994,970			6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,340,322 and 112,159,896 issued at respective dates	2,644,063			2,634,265
Treasury stock at cost; 63,271 and 58,135 shares at respective dates	(5,586		)	(4,825		)
Total common stock	2,638,477			2,629,440
Retained earnings	2,659,086			2,641,183
Accumulated other comprehensive loss	(46,501		)	(47,708		)
Total shareholders’ equity	5,251,062			5,222,915
Noncontrolling interests (Note 6)	130,663			125,790
Total equity	5,381,725			5,348,705
TOTAL LIABILITIES AND EQUITY	$	17,854,107		$	17,664,202

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

8

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

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

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)

	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		—				—			3,221			—			4,873		8,094
Other comprehensive income		—				—			—			1,213			—		1,213
Dividends on common stock		—				—			(16		)	—			—		(16		)
Issuance of common stock	145,793	5,456				—			—			—			—		5,456
Purchase of treasury stock (a)		—		(81,177	)	(6,277		)	—			—			—		(6,277		)
Reissuance of treasury stock for stock-based compensation and other		—		116,543		9,470			—			—			1		9,471
Reclassification of income tax effects related to new tax reform (b)		—				—			8,552			(8,552		)	—		—
Balance, March 31, 2018	111,961,963	$	2,620,261	(29,097	)	$	(2,431	)	$	2,454,268		$	(52,341	)	$	133,914	$	5,153,671
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		—				—			17,918			—			4,873		22,791
Other comprehensive income		—				—			—			1,207			—		1,207
Dividends on common stock		—				—			(15		)	—			—		(15		)
Issuance of common stock	180,426	9,798				—			—			—			—		9,798
Purchase of treasury stock (a)		—		(75,791	)	(6,882		)	—			—			—		(6,882		)
Reissuance of treasury stock for stock-based compensation and other		—		70,655		6,121			—			—			—		6,121
Balance, March 31, 2019	112,340,322	$	2,644,063	(63,271	)	$	(5,586	)	$	2,659,086		$	(46,501	)	$	130,663	$	5,381,725

(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   March 31,
	2019			2018
OPERATING REVENUES	$	740,530		$	692,006
OPERATING EXPENSES
Fuel and purchased power	230,588			202,010
Operations and maintenance	240,375			254,601
Depreciation and amortization	148,685			144,112
Taxes other than income taxes	55,078			53,242
Other expenses	427			163
Total	675,153			654,128
OPERATING INCOME	65,377			37,878
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	11,188			14,079
Pension and other postretirement non-service credits - net	5,499			13,197
Other income (Note 9)	6,416			3,772
Other expense (Note 9)	(3,878		)	(2,945		)
Total	19,225			28,103
INTEREST EXPENSE
Interest charges	56,665			56,158
Allowance for borrowed funds used during construction	(6,665		)	(6,755		)
Total	50,000			49,403
INCOME BEFORE INCOME TAXES	34,602			16,578
INCOME TAXES	1,453			2,106
NET INCOME	33,149			14,472
Less: Net income attributable to noncontrolling interests (Note 6)	4,873			4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	28,276		$	9,599

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   March 31,
	2019		2018
NET INCOME	$	33,149	$	14,472
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $0 and $96	—		(96		)
Reclassification of net realized loss, net of tax benefit of $108 and $82	328		409
Pension and other postretirement benefits activity, net of tax expense of $247 and $306	752		857
Total other comprehensive income	1,080		1,170
COMPREHENSIVE INCOME	34,229		15,642
Less: Comprehensive income attributable to noncontrolling interests	4,873		4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	29,356	$	10,769

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

12

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2019			December 31, 2018
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	18,760,012		$	18,733,142
Accumulated depreciation and amortization	(6,395,265		)	(6,362,771		)
Net	12,364,747			12,370,371
Construction work in progress	1,233,018			1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	104,808			105,775
Intangible assets, net of accumulated amortization	267,842			262,746
Nuclear fuel, net of accumulated amortization	142,610			120,217
Total property, plant and equipment	14,113,025			14,029,171
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	919,309			851,134
Other special use funds (Notes 11 and 12)	238,207			236,101
Other assets	42,090			40,817
Total investments and other assets	1,199,606			1,128,052
CURRENT ASSETS
Cash and cash equivalents	6,080			5,707
Customer and other receivables	238,270			257,654
Accrued unbilled revenues	114,077			137,170
Allowance for doubtful accounts	(2,455		)	(4,069		)
Materials and supplies (at average cost)	280,857			269,065
Fossil fuel (at average cost)	26,294			25,029
Assets from risk management activities (Note 7)	763			1,113
Deferred fuel and purchased power regulatory asset (Note 4)	7,583			37,164
Other regulatory assets (Note 4)	127,642			129,738
Other current assets	44,417			35,111
Total current assets	843,528			893,682
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,507			1,342,941
Operating lease right-of-use assets (Note 16)	191,957			—
Assets for other postretirement benefits (Note 5)	48,961			43,212
Other	38,299			128,265
Total deferred debits	1,600,724			1,514,418
TOTAL ASSETS	$	17,756,883		$	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) 

	March 31, 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	2,816,532			2,788,256
Accumulated other comprehensive loss	(26,027		)	(27,107		)
Total shareholder equity	5,690,363			5,661,007
Noncontrolling interests (Note 6)	130,663			125,790
Total equity	5,821,026			5,786,797
Long-term debt less current maturities (Note 3)	4,437,155			4,189,436
Total capitalization	10,258,181			9,976,233
CURRENT LIABILITIES
Short-term borrowings (Note 3)	157,500			—
Current maturities of long-term debt (Note 3)	250,000			500,000
Accounts payable	257,124			266,277
Accrued taxes	230,591			176,357
Accrued interest	47,585			60,228
Common dividends payable	—			82,700
Customer deposits	87,263			91,174
Liabilities from risk management activities (Note 7)	33,289			35,506
Liabilities for asset retirements	22,823			19,842
Operating lease liabilities (Note 16)	65,267			—
Regulatory liabilities (Note 4)	260,404			165,876
Other current liabilities	114,665			178,137
Total current liabilities	1,526,511			1,576,097
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,815,368			1,812,664
Regulatory liabilities (Note 4)	2,272,082			2,325,976
Liabilities for asset retirements	712,885			706,703
Liabilities for pension benefits (Note 5)	367,296			425,404
Liabilities from risk management activities (Note 7)	14,844			24,531
Customer advances	155,894			137,153
Coal mine reclamation	214,037			212,785
Deferred investment tax credit	200,052			200,405
Unrecognized tax benefits	42,084			41,861
Operating lease liabilities (Note 16)	51,805			—
Other	125,844			125,511
Total deferred credits and other	5,972,191			6,012,993
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
TOTAL LIABILITIES AND EQUITY	$	17,756,883		$	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)

	Three Months Ended   March 31,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	33,149		$	14,472
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	167,779			162,853
Deferred fuel and purchased power	16,709			(18,950		)
Deferred fuel and purchased power amortization	12,872			20,002
Allowance for equity funds used during construction	(11,188		)	(14,079		)
Deferred income taxes	(1,205		)	533
Deferred investment tax credit	(353		)	(147		)
Changes in current assets and liabilities:
Customer and other receivables	16,541			90,647
Accrued unbilled revenues	23,093			(6,555		)
Materials, supplies and fossil fuel	(13,057		)	(16,747		)
Other current assets	(9,598		)	(1,237		)
Accounts payable	30,774			(24,592		)
Accrued taxes	54,234			54,106
Other current liabilities	(81,627		)	(15,771		)
Change in other long-term assets	(64,516		)	3,722
Change in other long-term liabilities	14,525			(70,928		)
Net cash flow provided by operating activities	188,132			177,329
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(259,446		)	(355,039		)
Contributions in aid of construction	7,938			8,569
Allowance for borrowed funds used during construction	(6,665		)	(6,755		)
Proceeds from nuclear decommissioning trust sales and other special use funds	179,048			130,456
Investment in nuclear decommissioning trust and other special use funds	(179,618		)	(131,027		)
Other	(1,140		)	(1,183		)
Net cash flow used for investing activities	(259,883		)	(354,979		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324			—
Short-term borrowings and payments — net	157,500			255,500
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		)	—
Dividends paid on common stock	(82,700		)	(77,700		)
Net cash flow provided by financing activities	72,124			177,800
NET INCREASE IN CASH AND CASH EQUIVALENTS	373			150
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,707			13,851
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	6,080		$	14,001

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)

	Common Stock			Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total
	Shares	Amount
Balance, January 1, 2018	71,264,947	$	178,162	$	2,571,696	$	2,533,954	$	(26,983	)	$	129,040	$	5,385,869
Net income		—		—		9,599		—			4,873		14,472
Other comprehensive income		—		—		—		1,170			—		1,170
Other		—		—		—		—			1		1
Reclassification of income tax effects related to new tax reform (a)		—		—		5,038		(5,038		)	—		—
Balance, March 31, 2018	71,264,947	$	178,162	$	2,571,696	$	2,548,591	$	(30,851	)	$	133,914	$	5,401,512
Balance, January 1, 2019	71,264,947	$	178,162	$	2,721,696	$	2,788,256	$	(27,107	)	$	125,790	$	5,786,797
Net income		—		—		28,276		—			4,873		33,149
Other comprehensive income		—		—		—		1,080			—		1,080
Balance, March 31, 2019	71,264,947	$	178,162	$	2,721,696	$	2,816,532	$	(26,027	)	$	130,663	$	5,821,026

(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.

16

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.

17

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

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

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

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

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

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").

18

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

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 months ended March 31, 2019 and 2018 were $721 million and $683 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three months ended March 31, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $20 million and $10 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of March 31, 2019 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

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

At March 31, 2019, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2019,

19

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

APS

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

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

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

At March 31, 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 March 31, 2019, APS had $158 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 APS’s other outstanding letters of credit.

Debt Fair Value

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

	As of March 31, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	448,953	$	446,835	$	448,796	$	443,955
APS	4,687,155		4,942,057		4,689,436		4,789,608
Total	$	5,136,108	$	5,388,892	$	5,138,232	$	5,233,563

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

20

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the agreement include the following:

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

• an authorized return on common equity of 10.0%;

• a capital structure comprised of 44.2% debt and 55.8% common equity;

• a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;

• a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") 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.

21

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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 January 9, 2019, the ACC Commissioners voted to open a docket for this matter.  On April 23, 2019, the ACC Staff indicated that they may need some additional time beyond May 3, 2019 to file the requested report. APS does not believe that the rate review will have a material impact on our current financial position, results of operations or cash flows.  However, depending

22

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Cost Recovery Mechanisms

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

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

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

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan including a waiver of the distributed energy requirements for the 2018 implementation year.

On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. The ACC has not yet ruled on the 2019 RES Implementation Plan.

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

23

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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.

 Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2019 and 2018 (dollars in thousands):

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

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

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

24

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

 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

25

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

26

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 is 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 reflects the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018.

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

27

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

28

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 received subsequent requests on these matters and continues to respond to such follow-on requests. Pinnacle West and APS cannot predict the outcome of these matters.

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

In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals.  The rulemaking will consider possible modifications to existing ACC rules, such as the Renewable Energy Standard, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On April 26, 2019, Commissioner Dunn issued a proposed set of rules with regards to the Energy Modernization Plan. APS cannot predict the outcome of this matter.

29

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 Integrated Resource Plan from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request.

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 $46 million as of March 31, 2019 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

 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

30

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. Oral argument for this proceeding is scheduled for May 15, 2019. APS cannot predict the outcome of the proceeding.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS filed the SCR Adjustment request in April 2018.  Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment.  The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers.  Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019.  The hearing for this matter occurred in September 2018.  At the hearing, APS accepted ACC Staff's recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018.  The ACC has not issued a decision on this matter.  APS anticipates a decision later in 2019, however we cannot predict the outcome of the decision. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table 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 ($85 million as of March 31, 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 2026.

On March 20, 2019, APS announced that it has begun evaluating the feasibility and cost of converting a unit at the Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS will report the result of its evaluation by May 20, 2019. If converting a unit is more cost effective than alternatives, APS will seek ACC approval before moving forward with the Cholla conversion project. APS cannot predict the outcome of this matter.

31

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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

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 ($85 million as of March 31, 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.    

32

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities 

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

	Amortization Through	March 31, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	723,307	$	—	$	733,351
Retired power plant costs	2033	28,182		160,167		28,182		167,164
Income taxes — allowance for funds used during construction ("AFUDC") equity	2049	6,457		151,541		6,457		151,467
Deferred fuel and purchased power — mark-to-market (Note 7)	2023	29,340		14,360		31,728		23,768
Deferred fuel and purchased power (b) (c)	2020	7,583		—		37,164		—
Four Corners cost deferral	2024	8,077		38,209		8,077		40,228
Income taxes — investment tax credit basis adjustment	2047	1,079		25,475		1,079		25,522
Lost fixed cost recovery (b)	2020	29,698		—		32,435		—
Palo Verde VIEs (Note 6)	2046	—		20,170		—		20,015
Deferred compensation	2036	—		37,581		—		36,523
Deferred property taxes	2027	8,569		64,214		8,569		66,356
Loss on reacquired debt	2038	1,637		13,259		1,637		13,668
Tax expense of Medicare subsidy	2024	1,235		6,122		1,235		6,176
TCA balancing account (b)	2020	306		—		3,860		772
AG-1 deferral	2022	2,654		5,155		2,654		5,819
Mead-Phoenix transmission line CIAC	2050	332		9,961		332		10,044
Coal reclamation	2026	1,546		17,392		1,546		15,607
SCR deferral	N/A	—		30,581		—		23,276
Tax expense adjuster mechanism (c)	2019	5,451		—		—		—
Other	Various	3,079		4,013		1,947		3,185
Total regulatory assets (d)		$	135,225	$	1,321,507	$	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."

33

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Amortization Through	March 31, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act	(a)	$	91,401	$	1,178,216	$	—	$	1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act	2058	6,302		243,418		6,302		243,691
Asset retirement obligations	2057	—		337,844		—		278,585
Removal costs	(b)	50,701		156,578		39,866		177,533
Other postretirement benefits	(c)	37,864		116,478		37,864		125,903
Income taxes — deferred investment tax credit	2047	2,164		51,027		2,164		51,120
Income taxes — change in rates	2048	2,764		69,954		2,769		70,069
Spent nuclear fuel	2027	7,190		54,866		6,503		57,002
Renewable energy standard (a)	2020	47,943		—		44,966		20
Demand side management (a)	2020	1,581		24,146		14,604		4,123
Sundance maintenance	2030	6,657		11,637		1,278		17,228
Deferred gains on utility property	2022	3,923		5,975		4,423		6,581
Four Corners coal reclamation	2038	1,858		17,690		1,858		17,871
Tax expense adjustor mechanism (a)	2020	14		—		3,237		—
Other	Various	42		4,253		42		3,541
Total regulatory liabilities		$	260,404	$	2,272,082	$	165,876	$	2,325,976

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

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

(c) 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.

34

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

Contributions

We have made voluntary contributions of $90 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 months ended March 31, 2019 and 2018 of $5 million, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

35

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	March 31, 2019		December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	104,808	$	105,775
Equity — Noncontrolling interests	130,663		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.

36

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 March 31, 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	March 31, 2019	December 31, 2018
Power	GWh	1,146	250
Gas	Billion cubic feet	233	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 months ended March 31, 2019 and 2018 (dollars in thousands):

 

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

(a) During the three months ended March 31, 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 $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.

37

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

 

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

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

Derivative Instruments in the Condensed Consolidated Balance Sheets

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

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

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, 2019 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.

38

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,658		$	(2,857	)	$	801		$	(38	)	$	763
Investments and other assets	1,016			(881		)	135			—			135
Total assets	4,674			(3,738		)	936			(38		)	898
Current liabilities	(34,487		)	2,857			(31,630		)	(1,659		)	(33,289		)
Deferred credits and other	(15,725		)	881			(14,844		)	—			(14,844		)
Total liabilities	(50,212		)	3,738			(46,474		)	(1,659		)	(48,133		)
Total	$	(45,538	)	$	—		$	(45,538	)	$	(1,697	)	$	(47,235	)

(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 $1,659 and cash margin provided to counterparties of ($38).

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.

39

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of March 31, 2019, 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 March 31, 2019 (dollars in thousands):

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

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

We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $102 million if our debt credit ratings were to fall below investment grade.

40

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).

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $14.1 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.6 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

41

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 $24.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $71.2 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

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

Other than the item described above, there have been no material changes, as of March 31, 2019, outside the normal course of business in contractual obligations from the information provided in our 2018 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

42

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 Coal Supply Agreement - 4CA Matter" below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

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

43

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 Note 4 for 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

44

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

future action a number of other proposed changes contemplated in a March 1, 2018 proposal. For the final rule issued on July 17, 2018, 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.

45

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. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. 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 recently 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 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. On June 2, 2014, EPA issued two proposed rules to regulate greenhouse gas ("GHG") emissions from modified and reconstructed EGUs pursuant to Section 111(b) of the Clean Air Act and existing fossil fuel-fired power plants pursuant to Clean Air Act Section 111(d). On August 3, 2015, EPA finalized carbon pollution standards for EGUs, the "Clean Power Plan". On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan and proposed replacement regulations on August 21, 2018. In addition, judicial challenges to the Clean Power Plan are pending before the D.C. Circuit, though that litigation is currently in abeyance while EPA develops regulatory action to potentially repeal and replace that regulation.

EPA's pending proposal to regulate carbon emissions from EGUs replaces the Clean Power Plan with standards that are based entirely upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the Clean Power Plan, EPA's proposed "Affordable Clean Energy Rule" would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. In addition, to address the New Source Review ("NSR") implications of power plant upgrades potentially necessary to achieve compliance with the proposed Affordable Clean Energy Rule standards, EPA also proposed to revise EPA's NSR regulations to more readily authorize the implementation of EGU efficiency upgrades.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to approve the EPA's recently proposed Affordable Clean Energy Rule. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal, which is still pending.

46

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Federal Agency Environmental Lawsuit Related to Four Corners

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

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. Oral argument for this appeal occurred on March 7, 2019. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court 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. EPA indicated that, depending on the extent of public comments it receives concerning the permit proposal, it anticipates taking final action on a new NPDES permit by August 2019. At this time we cannot predict the outcome of EPA's reconsideration of the NPDES permit and whether reconsideration will have a material impact on our financial position, results of operations or cash flows.

47

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Four Corners - 4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. Concurrent with the settlement of the 2016 Coal Supply Agreement matter described above, NTEC and 4CA agreed to allow for the purchase by NTEC of the 7% interest, consistent with the option. On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement providing for the sale to NTEC of 4CA's 7% interest in Four Corners. Completion of the sale was subject to the receipt of approval by FERC, which was received on July 2, 2018, and the sale transaction closed on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. 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 March 31, 2019, standby letters of credit totaled $0.2 million and will expire in 2019. As of March 31, 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.

48

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at March 31, 2019. 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 Coal Supply Agreement - 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.

9. Other Income and Other Expense

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

	Three Months Ended   March 31,
	2019			2018
Other income:
Interest income	$	2,302		$	1,891
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Miscellaneous	23			2
Total other income	$	7,169		$	3,985
Other expense:
Non-operating costs	$	(2,704	)	$	(1,646	)
Investment losses — net	(238		)	(176		)
Miscellaneous	(1,416		)	(1,407		)
Total other expense	$	(4,358	)	$	(3,229	)

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

	Three Months Ended   March 31,
	2019			2018
Other income:
Interest income	$	1,550		$	1,678
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Miscellaneous	22			2
Total other income	$	6,416		$	3,772
Other expense:
Non-operating costs	$	(2,467	)	$	(1,539	)
Miscellaneous	(1,411		)	(1,406		)
Total other expense	$	(3,878	)	$	(2,945	)

49

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10. Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three months ended March 31, 2019 and 2018 (in thousands, except per share amounts):

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

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.  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.

50

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

51

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Investments Held in Nuclear Decommissioning Trust and Other Special Use Funds

The nuclear decommissioning trust and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union medical trust. 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.

52

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

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

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at March 31, 2019
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	3,598		$	1,076		$	(3,776	)	(a)	$	898
Nuclear decommissioning trust:
Equity securities	7,547		—			—			2,630			(b)	10,177
U.S. commingled equity funds	—		—			—			451,229			(c)	451,229
U.S. Treasury debt	155,231		—			—			—				155,231
Corporate debt	—		108,509			—			—				108,509
Mortgage-backed debt securities	—		113,002			—			—				113,002
Municipal bonds	—		70,375			—			—				70,375
Other fixed income	—		10,786			—			—				10,786
Subtotal nuclear decommissioning trust	162,778		302,672			—			453,859				919,309
Other special use funds:
Equity securities	11,471		—			—			1,563			(b)	13,034
U.S. Treasury debt	208,945		—			—			—				208,945
Municipal bonds	—		16,228			—			—				16,228
Subtotal other special use funds	220,416		16,228			—			1,563				238,207
Total Assets	$	383,194	$	322,498		$	1,076		$	451,646			$	1,158,414
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(43,524	)	$	(6,688	)	$	2,079		(a)	$	(48,133	)

(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.

53

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 (a) (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 debt 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.

54

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 March 31, 2019 and December 31, 2018:

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

(a) Includes swaps and physical and financial contracts.

	December 31, 2018 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	—	$	2,456	Discounted cash flows	Electricity forward price (per MWh)	$17.88 - $37.03	$	26.10
Natural Gas:
Forward Contracts (a)	2		5,760		Discounted cash flows	Natural gas forward price (per MMBtu)	$1.79 - $2.92	$	2.48
Total	$	2	$	8,216

(a) Includes swaps and physical and financial contracts.

55

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Three Months Ended   March 31,
Commodity Contracts	2019			2018
Net derivative balance at beginning of period	$	(8,214	)	$	(18,256	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(1,579		)	(2,322		)
Settlements	518			782
Transfers into Level 3 from Level 2	(2		)	(2,445		)
Transfers from Level 3 into Level 2	3,665			2,487
Net derivative balance at end of period	$	(5,612	)	$	(19,754	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

Financial Instruments Not Carried at Fair Value

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 3 for our long-term debt fair values. The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $57 million as of March 31, 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 Trusts and Other Special Use Funds

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Condensed Consolidated Balance Sheets. See Note 11 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts - To fund the future costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning

56

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 Accounts - 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 period and in future periods. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including other-than-temporary impairments) 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 March 31, 2019 and December 31, 2018 (dollars in thousands):  

	March 31, 2019
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
Equity securities	$	458,776	$	11,471	$	470,247		$	273,817	$	(4	)
Available for sale-fixed income securities	457,903		225,173		683,076		(a)	15,306		(2,250		)
Other	2,630		1,563		4,193		(b)	—		—
Total	$	919,309	$	238,207	$	1,157,516		$	289,123	$	(2,254	)

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

(b) Represents net pending securities sales and purchases.

57

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		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 months ended March 31, 2019 and 2018 (dollars in thousands):

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

(a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds.

58

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

13.    New Accounting Standards

Standards Adopted in 2019

ASU 2016-02, Leases

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

Standards Pending Adoption

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

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

59

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. We are currently evaluating this new accounting standard and the impacts it may have on our 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 months ended March 31, 2019 and 2018 (dollars in thousands):

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2018	$	(45,997	)		$	(1,711	)		$	(47,708	)
Amounts reclassified from accumulated other comprehensive loss	879			(a)	328			(b)	1,207
Balance March 31, 2019	$	(45,118	)		$	(1,383	)		$	(46,501	)
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	900			(a)	409			(b)	1,309
Reclassification of income tax effect related to tax reform	(7,954		)	(c)	(598		)	(c)	(8,552		)
Balance March 31, 2018	$	(49,494	)		$	(2,847	)		$	(52,341	)

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

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

60

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2018	$	(25,396	)		$	(1,711	)		$	(27,107	)
Amounts reclassified from accumulated other comprehensive loss	752			(a)	328			(b)	1,080
Balance March 31, 2019	$	(24,644	)		$	(1,383	)		$	(26,027	)
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	857			(a)	409			(b)	1,266
Reclassification of income tax effect related to tax reform	(4,440		)	(c)	(598		)	(c)	(5,038		)
Balance March 31, 2018	$	(28,004	)		$	(2,847	)		$	(30,851	)

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

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

15.  Income Taxes

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

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company's proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve month period. As a result, the Company began amortization in March 2019. 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.

61

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 (see Note 6).  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.

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, we are no longer subject to state income tax examinations by tax authorities for years before 2014.

62

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

16.  Leases

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

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

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

The following table provides information related to our lease costs for the three months ended March 31, 2019 (dollars in thousands):

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

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). 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. Short-term lease cost is immaterial.

63

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

	March 31, 2019
Weighted average remaining lease term	8 years
Weighted average discount rate	3.86		%
	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	3,087

64

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

65

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 August 3, 2015, EPA finalized a rule to limit carbon dioxide emissions from existing power plants (the "Clean Power Plan"), which the EPA later proposed repealing. EPA is considering a proposed replacement to the Clean Power Plan, which was published on August 21, 2018. This new proposal, the "Affordable Clean Energy Rule," is more narrow than its predecessor regulation, and is based entirely upon heat-rate improvements at steam-electric power plants. APS continually analyzes its long-range capital management plans to assess the potential effects of such proposals, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to continue participation in such plants.

66

Cholla

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

On March 20, 2019, APS announced that it has begun evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS will report the result of its evaluation by May 20, 2019. If converting a unit is more cost effective than alternatives, APS will seek ACC approval before moving forward with the Cholla conversion project. APS cannot predict the outcome of this matter.

Four Corners

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

NTEC had an option to purchase the 4CA 7% interest and ultimately purchased the interest on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC's 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West's guarantee is secured by a portion of APS's payments to be owed to NTEC under the 2016 Coal Supply Agreement.

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

67

$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.  

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. Oral argument for this appeal occurred on March 7, 2019. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court 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. EPA indicated that, depending on the extent of public comments it receives concerning the permit proposal, it anticipates taking final action on a new NPDES permit by August 2019. At this time, we cannot predict the outcome of EPA's reconsideration of the NPDES permit and whether reconsideration will have a material impact on our financial position, results of operations or cash flows.

Navajo Plant

The co-owners 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)

68

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.  In total, this increases the capacity of the site by 290 MW to 620 MW, with completion targeted by the middle of 2019. (See Note 4 for details of the rate recovery in our 2017 Rate Case Decision.)

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 March 31, 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.

69

	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar	238	—
Purchased Power Agreements:
Solar	310	—
Solar + Energy Storage	—	50
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	629	50
Total Distributed Energy: Solar (a)	878	30	(b)
Total Renewable Portfolio	1,745	80

(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. 

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. 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 anticipate such facilities could be in service by mid-2020. Additionally, in February 2019, APS signed two 20-year power purchase agreements for energy storage totaling 150 MW. Service under these power purchase agreements are scheduled to begin in 2021, pending approval from the ACC to allow for recovery of these agreements through the PSA.  We plan to install at least an additional 660 MW of APS-owned solar plus battery storage and stand-alone battery storage systems by the summer of 2025, with the first 260 MW being procured in 2019 (60 MW on additional AZ Sun sites and 100 MW of solar plus 100 MW of battery storage).

70

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.

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. Post-hearing briefing was concluded on December 14, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On April 22, 2019, the Administrative Law Judge issued a proposed amendment to the Recommended Opinion and Order which proposes that APS credit back to customers the $5 million DSMAC funds used by APS to educate ratepayers on the new rates and that APS ratepayers will be held harmless from expenditures made by APS for targeted outreach and education in any future rate case. APS cannot predict the outcome of this matter.

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 January 9, 2019, the ACC Commissioners voted to open a docket for this matter.  On April 23, 2019, the ACC Staff indicated that they may need some additional time beyond May 3, 2019 to file the requested report. APS does not believe that the rate review will have a material impact on our current financial position, results of operations or cash flows.  However, depending

71

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

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

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS filed the SCR Adjustment request in April 2018. Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the rate adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC Staff's recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018.  The ACC has not issued a decision on this matter.  APS anticipates a decision later in 2019, however we cannot predict the outcome of the decision. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table in Note 4).

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

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

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 13, 2019, effective the first billing cycle in April 2019. The impact of TEAM Phase II is expected to be

72

earnings neutral as both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern.

On April 10, 2019, APS filed a third request with the ACC that addresses the amortization of depreciation related excess deferred taxes over a 28.5 year period (“TEAM Phase III”).  Over the first 36 months, TEAM Phase III is expected to return $34.5 million to customers annually, and APS has proposed this refund begin July 1, 2019.  The Company is currently in the process of seeking IRS guidance affirming the amortization method and period applicable to these depreciation related excess deferred taxes. The ACC has not yet approved TEAM Phase III.

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

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

73

February 13, 2019, Commissioner Burns filed a notice of appeal. APS and Pinnacle West cannot predict the outcome of this matter.

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

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

In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals.  The rulemaking will consider possible modifications to existing ACC rules, such as the Renewable Energy Standard, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On April 26, 2019, Commissioner Dunn issued a proposed set of rules with regards to the Energy Modernization Plan. 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 Integrated Resource Plan from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request.

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

74

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

Financial Strength and Flexibility 

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

Other Subsidiaries

Bright Canyon Energy. 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

75

growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.  These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Actual and Projected Customer and Sales Growth.  Retail customers in APS’s service territory increased 1.9% for the three months ended March 31, 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 1.0% for the three months ended March 31, 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 $20 million.  However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 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

76

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. 

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

Property Taxes.  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. 

Income Taxes.  Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC.  In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Act was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (See Note 15 for details of the impacts on the Company as of March 31, 2019.) 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.)

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

RESULTS OF OPERATIONS

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

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

Our consolidated net income attributable to common shareholders for the three months ended March 31, 2019 was $18 million, compared with consolidated net income attributable to common shareholders of $3 million for the prior-year period.  The results reflect an increase of approximately $13 million for the regulated electricity segment primarily due to the effects of weather, the change in residential rate design and seasonal rates and lower fossil planned outages, partially offset by lower pension and other postretirement non-service credits and higher depreciation and amortization.

77

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

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

78

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

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

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

• A decrease of $8 million in fossil generation primarily due to lower planned outages; and

• A decrease of $7 million related to costs for renewable energy and similar regulatory programs, which is partially offset by operating revenues and purchased power.

Depreciation and amortization.  Depreciation and amortization expenses were $5 million higher for the three months ended March 31, 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 $8 million lower for the three months ended March 31, 2019 compared to the prior-year period primarily due to lower market returns.

79

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Our primary sources of cash are dividends from APS and external debt and equity issuances.  An ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At March 31, 2019, APS’s common equity ratio, as defined, was 54%.  Its total shareholder equity was approximately $5.7 billion, and total capitalization was approximately $10.6 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).

80

Summary of Cash Flows

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

Pinnacle West Consolidated

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

Arizona Public Service Company

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

Operating Cash Flows

Three-month period ended March 31, 2019 compared with three-month period ended March 31, 2018.  Pinnacle West’s consolidated net cash provided by operating activities was $173 million in 2019 and $167 million in 2018, an increase of $6 million in net cash provided by operating activities.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries.  The requirements of the Employee Retirement Income Security Act of 1974 ("ERISA") require us to contribute a minimum amount to the qualified plan.  We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount.  The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations.  Under ERISA, the qualified pension plan was 110% 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 $90 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.

81

Investing Cash Flows

Three-month period ended March 31, 2019 compared with three-month period ended March 31, 2018.  Pinnacle West’s consolidated net cash used for investing activities was $254 million in 2019, compared to $361 million in 2018, a decrease of $107 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)	16		18		3
New Resources (b)	90		182		291
Environmental	31		41		71
New Gas Generation	16		—		—
Other Generation	119		117		105
Distribution	500		455		546
Transmission	199		171		197
Other (c)	125		150		128
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.

82

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

Financing Cash Flows and Liquidity

Three-month period ended March 31, 2019 compared with three-month period ended March 31, 2018.  Pinnacle West’s consolidated net cash provided by financing activities was $81 million in 2019, compared to $196 million of net cash provided in 2018, a decrease of $115 million in net cash provided.  The decrease in net cash provided by financing activities includes a net decrease in short term borrowings of $107 million and higher long-term debt repayments of $500 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 April 17, 2019, the Pinnacle West Board of Directors declared a dividend of $0.7375 per share of common stock, payable on June 3, 2019 to shareholders of record on May 1, 2019.

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

On 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.

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

At March 31, 2019, Pinnacle West had a $200 million facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2019, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $38 million of commercial paper borrowings.

83

At March 31, 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 March 31, 2019, APS had $158 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 APS’s separate outstanding letters of credit and surety bonds.

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

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.  Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At March 31, 2019, the ratio was approximately 51% for Pinnacle West and 46% 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).

84

Credit Ratings

The ratings of securities of Pinnacle West and APS as of April 24, 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	Stable
APS
Corporate credit rating	A2	A-	A-
Senior unsecured	A2	A-	A
Commercial paper	P-1	A-2	F2
Outlook	Stable	Stable	Stable

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

Other than the item described above, there have been no material changes, as of March 31, 2019, outside the normal course of business in contractual obligations from the information provided in our 2018 Form 10-K. See Note 3 for discussion regarding changes in our long-term debt obligations.

85

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). We are currently evaluating the impacts of the pending adoption of the following new accounting standards effective for us on January 1, 2020:

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

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

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.

86

The following table shows the net pretax changes in mark-to-market of our derivative positions for the three months ended March 31, 2019 and 2018 (dollars in millions):

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

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at March 31, 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	$	(23	)	$	(8	)	$	(6	)	$	(3	)	$	—	$	(40	)
Prices based on unobservable inputs	(4		)	(2		)	—			—			—		(6		)
Total by maturity	$	(27	)	$	(10	)	$	(6	)	$	(3	)	$	—	$	(46	)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2019 and December 31, 2018 (dollars in millions):

	March 31, 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	$	5	$	(5	)	$	1	$	(1	)
Natural gas	45		(45		)	44		(44		)
Total	$	50	$	(50	)	$	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.

87

Credit Risk

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

Item 3.        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4.         CONTROLS AND PROCEDURES

(a)                                 Disclosure Controls and Procedures

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

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2019.  Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of APS’s disclosure controls and procedures as of March 31, 2019.  Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b)                                 Changes in Internal Control Over Financial Reporting

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

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended March 31, 2019 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

88

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.

89

Item 6.                 EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
10.1	Pinnacle West APS	Term Loan Agreement dated as of February 26, 2019 among APS, as Borrower,  SunTrust Bank, as Agent, SunTrust Bank, TD Bank, N.A., U.S. Bank National Association and The Bank of Nova Scotia, as Co-Syndication Agents and such institutions compromising the lenders party thereto
10.2	Pinnacle West	Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.3	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
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

90

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

________________________________

*Furnished herewith as an Exhibit.

91

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.

92

SIGNATURES

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

		PINNACLE WEST CAPITAL CORPORATION
		(Registrant)
Dated:	May 1, 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:	May 1, 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)

93

EX-10.1

U.S. $200,000,000

TERM LOAN AGREEMENT

Dated as of February 26, 2019

among

ARIZONA PUBLIC SERVICE COMPANY,

asBorrower,

THE LENDERS PARTY HERETO,

SUNTRUST BANK,

asAgent,

SUNTRUST BANK,

TD BANK, N.A.,

U.S. BANK NATIONAL ASSOCIATION,

and

THE BANK OF NOVA SCOTIA,

asCo-SyndicationAgents,

_____________________________________________________________________

SUNTRUST ROBINSON HUMPHREY, INC.,

and

TD SECURITIES (USA) LLC,

and

U.S. BANK NATIONAL ASSOCIATION,

and

THE BANK OF NOVA SCOTIA

asJointLeadArrangersandasJointBookrunners

1

TABLE OF CONTENTS

ARTICLE I DEFINITIONS AND ACCOUNTING TERMS 1

Section 1.01 Certain Defined Terms    1

Section 1.02 Other Interpretive Provisions    18

Section 1.03 Accounting Terms    19

Section 1.04 Rounding    20

Section 1.05 Times of Day    20

ARTICLE II AMOUNTS AND TERMS OF THE LOANS 20

Section 2.01 The Loans    20

Section 2.02 Making the Loans    20

Section 2.03 Fees    22

Section 2.04 Repayment of Loans    22

Section 2.05 Interest on Loans    22

Section 2.06 Interest Rate Determination    23

Section 2.07 Optional Conversion of Loans    24

Section 2.08 Prepayments of Loans    25

Section 2.09 Increased Costs    25

Section 2.10 Illegality    27

Section 2.11 Payments and Computations    27

Section 2.12 Taxes    28

Section 2.13 Sharing of Payments, Etc    32

Section 2.14 Evidence of Debt    33

Section 2.15 Use of Proceeds    34

Section 2.16 Affected Lenders    34

Section 2.17 Replacement of Lenders    34

ARTICLE III CONDITIONS PRECEDENT 35

Section 3.01 Conditions Precedent to Effectiveness    35

Section 3.02 Determinations Under Section 3.01    37

ARTICLE IV REPRESENTATIONS AND WARRANTIES 37

Section 4.01 Representations and Warranties of the Borrower    37

ARTICLE V COVENANTS OF THE BORROWER 41

Section 5.01 Affirmative Covenants    41

Section 5.02 Negative Covenants    45

Section 5.03 Financial Covenant    47

ARTICLE VI EVENTS OF DEFAULT 47

i

Section 6.01 Events of Default    47

ARTICLE VII THE AGENT 49

Section 7.01 Appointment and Authority    49

Section 7.02 Rights as a Lender    50

Section 7.03 Exculpatory Provisions    50

Section 7.04 Reliance by Agent    51

Section 7.05 Delegation of Duties    51

Section 7.06 Resignation of Agent    51

Section 7.07 Non-Reliance on Agent and Other Lenders    52

Section 7.08 No Other Duties, Etc    52

Section 7.09 Certain ERISA Matters.    52

ARTICLE VIII MISCELLANEOUS 54

Section 8.01 Amendments, Etc    54

Section 8.02 Notices, Etc.    55

Section 8.03 No Waiver; Cumulative Remedies; Enforcement    57

Section 8.04 Costs and Expenses; Indemnity; Damage Waiver    58

Section 8.05 Right of Set-off    59

Section 8.06 Effectiveness; Binding Effect    60

Section 8.07 Successors and Assigns    60

Section 8.08 Confidentiality    64

Section 8.09 Governing Law    64

Section 8.10 Counterparts; Integration    64

Section 8.11 Jurisdiction, Etc.    64

Section 8.12 Payments Set Aside    65

Section 8.13 Patriot Act and Beneficial Ownership Regulation    65

Section 8.14 Waiver of Jury Trial    65

Section 8.15 No Advisory or Fiduciary Responsibility    65

Section 8.16 Survival of Representations and Warranties    66

Section 8.17 Severability    66

Section 8.18 Acknowledgement and Consent to Bail-In of EEA Financial Institutions    67

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

Exhibit E        Form of Prepayment Notice

iii

TERM LOAN AGREEMENT
Dated as of February 26, 2019

ARIZONA PUBLIC SERVICE COMPANY, 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), SUNTRUST BANK, as Agent for the Lenders, and SUNTRUST BANK, TD BANK, N.A., U.S. BANK NATIONAL ASSOCIATION and THE BANK OF NOVA SCOTIA, as Co-Syndication Agents, agree as follows:

The Borrower has requested that the Lenders provide a $200,000,000 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:

“2018 Order” means Decision No. 76973, dated November 27, 2018, of the Arizona Corporation Commission.

“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 SunTrust Bank (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 Term Loan Agreement, dated as of February 26, 2019, among the Borrower, the Lenders named herein and from time to time party hereto 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.

2

“Applicable Rate” means (i) if a Base Rate Loan, 0.000% per annum and (ii) if a Eurodollar Rate Loan, 0.500% per annum.

“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.

“Arrangers” means each of TD Securities (USA) LLC, U.S. Bank National Association, SunTrust Robinson Humphrey, Inc., and The Bank of Nova Scotia, 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.

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

3

“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 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 City, 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 $200,000,000.

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

4

“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 the Borrower, “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.

“Co-Syndication Agent” means each of TD Bank, N.A., U.S. Bank National Association, SunTrust Bank, and The Bank of Nova Scotia, together with their successors and assigns.

“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,

5

(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;

“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

6

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 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

7

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 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).

“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 February 26, 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 the Borrower from Southern California Edison Company (“SCE”) of SCE’s interests in Units 4 and 5 of the Four Corners Power Plant near

8

Farmington, New Mexico, pursuant to the Purchase and Sale Agreement, dated as of November 8, 2010, by and between SCE and the Borrower.

“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

9

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 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;

10

(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 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

11

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.

“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 at any time, a 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 August 26, 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).

12

“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.

“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.

“Permitted Lien” of the Borrower or any Material Subsidiary means any of the following:

(i)Liens for taxes, assessments or other governmental charges or levies not at the time delinquent or thereafter payable without penalty or being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been made;

(ii)Liens imposed by or arising by operation of law, such as Liens of carriers, warehousemen, mechanics, materialmen and landlords incurred in the ordinary course of business, including, without limitation, landlord’s liens arising under Arizona Law under leases entered into by the Borrower in the 1986 sale and leaseback transactions with respect to PVNGS Unit 2 and securing the payment of rent under such leases, in each case, for sums not overdue for a period of more than 30 days or being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been made;

(iii)Liens incurred in the ordinary course of business in connection with worker’s compensation, unemployment insurance or other forms of governmental insurance or benefits or other similar statutory obligations;

(iv)Liens to secure obligations on surety or appeal bonds;

(v)Liens on cash deposits in the nature of a right of setoff, banker’s lien, counterclaim or netting of cash amounts owed arising in the ordinary course of business on deposit accounts, commodity accounts or securities accounts;

(vi)easements, restrictions, reservations, licenses, covenants, and other defects of title that are not, in the aggregate, materially adverse to the use of such property for the purpose for which it is used;

(vii)Liens securing claims against or other obligations of any Person other than the Borrower or any Subsidiary of the Borrower neither assumed nor guaranteed by the Borrower or any Subsidiary of the Borrower nor on which the Borrower or any Subsidiary of the Borrower customarily pays interest, existing upon real estate or rights in or relating

13

to real estate acquired by the Borrower or any Subsidiary of the Borrower for use in the operation of the business of the Borrower or any Subsidiary of the Borrower, including, without limitation, for the generation, transmission or distribution of electric energy, transportation, telephonic, telegraphic, radio, wireless or other electronic communication or any other purpose;

(viii)rights reserved to or vested in and Liens on assets arising out of obligations or duties to any municipality or public authority with respect to any right, power, franchise, grant, license or permit, or by any provision of Law;

(ix)rights reserved to or vested in others to take or receive any part of the power pursuant to firm power commitment contracts, purchased power contracts, tolling agreements and similar agreements, coal, gas, oil or other minerals, timber or other products generated, developed, manufactured or produced by, or grown on, or acquired with, any property of the Borrower;

(x)rights reserved to or vested in any municipality or public authority to control or regulate any property of the Borrower, or to use such property in a manner that does not materially impair the use of such property for the purposes for which it is held by the Borrower;

(xi)security interests granted in favor of the lessors in the Borrower’s Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 (such agreement, as amended or otherwise modified from time to time, being the “Unit 2 Trust Agreement”) entered into in connection with the PVNGS Unit 2 sale leaseback transaction to secure the Borrower’s obligations in respect of the decommissioning of PVNGS Unit 2 or related facilities;

(xii)Liens that may exist with respect to the Unit 2 Trust Agreement (other than as described in paragraph (xi) above) or with respect to either of the Borrower’s Decommissioning Trust Agreement (PVNGS Unit 1) or Decommissioning Trust Agreement (PVNGS Unit 3), each dated as of July 1, 1991, as amended or otherwise modified from time to time, relating to the Borrower’s obligation to set aside funds for the decommissioning and retirement from service of such Units;

(xiii)pledges of pollution control bonds and related rights to secure the Borrower’s reimbursement obligations in respect of letters of credit, bond insurance, and other credit or liquidity enhancements supporting pollution control bond transactions, provided that such pollution control bonds are not secured by any other assets of the Borrower or any Material Subsidiary;

(xiv)rights and interests of Persons other than the Borrower or any Material Subsidiary (including, without limitation, acquisition rights), related obligations of the Borrower or any Material Subsidiary and restrictions on it or its property arising out of contracts, agreements and other instruments to which the Borrower or any Material Subsidiary is a party that relate to the common ownership or joint use of property or other

14

use of property for the benefit of one or more third parties or that allow a third party to purchase property of the Borrower or any Material Subsidiary and all Liens on the interests of Persons other than the Borrower or any Material Subsidiary in such property;

(xv)transfers of operational or other control of facilities to a regional transmission organization or other similar body and Liens on such facilities to cover expenses, fees and other costs of such an organization or body;

(xvi)Liens established on specified bank accounts of the Borrower to secure the Borrower’s reimbursement obligations in respect of letters of credit supporting commercial paper issued by the Borrower and similar arrangements for collateral security with respect to refinancings or replacements of the same;

(xvii)rights of transmission users or any regional transmission organizations or similar entities in transmission facilities;

(xviii)Liens on property of the Borrower sold in a transaction permitted by Section 5.02(a) to another Person pursuant to a conditional sales agreement where the Borrower retains title;

(xix)Liens created under this Agreement;

(xx)Liens on cash or cash equivalents not to exceed $200,000,000 (A) deposited in margin accounts with or on behalf of futures contract brokers or paid over to other contract counterparties or (B) pledged or deposited as collateral to a contract counterparty to secure obligations with respect to (1) contracts (other than for Indebtedness) for commercial and trading activities in the ordinary course of business for the purchase, transmission, distribution, sale, storage, lease or hedge of any energy or energy related commodity or (2) Hedge Agreements;

(xxi)Liens granted on cash or cash equivalents to defease Indebtedness of the Borrower or any of its Subsidiaries;

(xxii)Liens granted on cash or cash equivalents constituting proceeds from any sale or disposition of assets that is not prohibited by Section 5.02(c) deposited in escrow accounts or otherwise withheld or set aside to secure obligations of the Borrower or any Subsidiary providing for indemnification, adjustment of purchase price or any similar obligations, in each case, in an amount not to exceed the amount of gross proceeds received by the Borrower or any Subsidiary in connection with such sale or disposition;

(xxiii)Liens, deposits and similar arrangements to secure the performance of bids, tenders or contracts (other than contracts for borrowed money), public or statutory obligations, performance bonds and other obligations of a like nature incurred in the ordinary course of business by the Borrower or any of its Subsidiaries;

15

(xxiv)rights of lessees arising under leases entered into by the Borrower or any of its Subsidiaries as lessor, in the ordinary course of business;

(xxv)any Liens on or reservations with respect to governmental and other licenses, permits, franchises, consents and allowances;

(xxvi)Liens on property which is the subject of a Capital Lease Obligation designating the Borrower or any of its Subsidiaries as lessee and all right, title and interest of the Borrower or any of its Subsidiaries in and to such property and in, to and under such lease agreement, whether or not such lease agreement is intended as a security;

(xxvii)licenses of intellectual property entered into in the ordinary course of business;

(xxviii) Liens solely on any cash earnest money deposits made by the Borrower or any of its Subsidiaries in connection with any letter of intent or purchase agreement permitted hereunder;

(xxix) deposits or funds established for the removal from service of operating facilities and coal mines and related facilities or other similar facilities used in connection therewith; and

(xxx)Liens on cash deposits used to secure letters of credit under defaulting lender provisions in credit or reimbursement facilities;

provided, however, that no Lien in favor of the PBGC shall, in any event, be a Permitted Lien.

“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” means the rate of interest per annum publicly announced from time to time by SunTrust Bank as its prime rate in effect at its principal office in Atlanta, Georgia; each change

16

in the Prime Rate shall be effective from and including the date such change is publicly announced as being effective.

“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).

“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.

“PWCC” means Pinnacle West Capital Corporation, an Arizona corporation.

“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); provided that at all times when two or more Lenders (excluding Affected Lenders) are party to this Agreement, the term “Required Lenders” shall in no event mean fewer than two Lenders.

17

“Sale Leaseback Obligation Bonds” means any bonds issued by or on behalf of the Borrower in connection with a sale/leaseback transaction and any refinancing or refunding of such obligations.

“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 Form 10-K Report for the year ended December 31, 2018.

“Subsequent Order” means any decision, order or ruling of the Arizona Corporation Commission issued after the Effective Date relating to the incurrence or maintenance of Indebtedness by the Borrower and that amends, supersedes or otherwise modifies the 2018 Order or any successor decision, order or ruling.

“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.

“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, the Borrower 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 the Borrower’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

“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

18

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 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

19

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 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

20

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 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 $1,000,000 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 Section 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

21

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.

Section 2.03Fees. The Borrower shall pay to the Agent for its own account 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

22

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 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

23

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.

(i)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 (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, then the Agent and the Borrower shall endeavor to establish an alternate rate of interest to the Eurodollar Rate that gives due consideration to the then prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time, 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. Notwithstanding anything to the contrary in Section 8.01, such amendment 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. 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.

(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.

(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

24

(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 Section 2.06 and Section 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, which notice shall be in writing or by facsimile in substantially the form of Exhibit E hereto and shall specify 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 $1,000,000, (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, including the 2018 Order and/or any Subsequent Order, or applicable resolutions of the Board of Directors of the Borrower.

25

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

26

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 Sections 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

27

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.

28

(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

29

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 or the 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,

30

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.

31

(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

32

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 Sections 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

33

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 and for other general corporate purposes of the Borrower and in accordance with Section 4.01(p), subject to such restrictions that are imposed in the 2018 Order and/or any Subsequent Order.

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

34

Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject 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

35

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, counsel for the Agent, in form and substance reasonably acceptable to the Lenders.

(x)A written certificate of an Authorized Officer certifying (i) all required regulatory authorizations including the 2018 Order and/or any Subsequent Order in respect of the Initial Borrowing have been obtained, are in full force and effect and, before and after

36

giving effect to the Initial Borrowing on the Effective Date and to the application of the proceeds therefrom, the Borrower is in compliance with the provisions of the applicable order; and (ii) before and after giving effect to the Initial Borrowing on the Effective Date 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 (a) applicable resolutions of the Board of Directors of the Borrower, (b) applicable Laws of any Governmental Authority, or (c) the 2018 Order or any Subsequent Order, whichever is in force and effect at such time.

(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 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.

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 Section 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; (i) 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; (i) 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

37

Lender in its sole discretion) and except that (A) the Borrower 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 the Borrower 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 franchises, certificates, licenses and permits may not be specific as to their geographical scope); and (i) 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, (i) contravene any Law (including without limitation the 2018 Order and/or any Subsequent Order), decree, writ, injunction or determination of any Governmental Authority, in each case applicable to or binding upon the Borrower or any of its properties, (i) contravene any contractual restriction binding on or affecting the Borrower or (i) 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, except for the 2018 Order or any Subsequent Order, which has been duly obtained and is in full force and effect, and any notices or compliance filings required therein.

(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, 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, 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 (i) except as disclosed to the Agent in the SEC Reports or by means of a letter from

38

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.

(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 (i) 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 (i) 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 Section 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

39

Subsidiaries of the Borrower and, as of the Effective Date, no such Subsidiary of the Borrower is a Material Subsidiary.

(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).

(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; (i) 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; (i) 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 (i) 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.,

40

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 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 Certificate, as of the Effective Date, the information included in the Beneficial Ownership Certification is true and correct in all respects.

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

41

ARTICLE VCOVENANTS OF THE BORROWER

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 the 2018 Order, any Subsequent Order, Arizona Revised Statutes, Section 40-302 and all similar or comparable 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 will use its commercially reasonable efforts to preserve and maintain such franchises reasonably necessary in the normal conduct of its business, except that (i) the Borrower 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

42

time communities served by the Borrower 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, 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 March 31, 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

43

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 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)promptly after (A) any amendment or modification of the 2018 Order, (B) any amendment or modification of Arizona Revised Statutes, Section 40-302, or the promulgation, amendment or modification of any successor or similar statute, or (C) the promulgation, amendment or modification of any Subsequent Order by the Arizona

44

Corporation Commission or any successor thereto, in any case if such amendment, modification or promulgation could affect the validity or enforceability of the Indebtedness of the Borrower pursuant to this Agreement, a copy thereof;

(vii)[intentionally omitted];

(viii)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 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;

(ix)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

(x)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; or (b) 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 parent’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 the same general type of business conducted on the date hereof.

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

(a)Liens, Etc. Create or suffer to exist, or permit any of its Material Subsidiaries to create or suffer to exist, any Lien on or with respect to any of its properties, whether now owned or hereafter acquired, or assign, or permit any of its Material Subsidiaries to assign, any right to receive income, other than:

(i)Permitted Liens;

45

(ii)Liens upon or in, or conditional sales agreements or other title retention agreements with respect to, any real or personal property acquired or held by the Borrower or any Subsidiary in the ordinary course of business to secure the purchase price of such property, or the construction of or improvements to such property, or to secure Indebtedness incurred solely for the purpose of financing the acquisition, construction or improvement of such property to be subject to such Liens (including any Liens placed on such property within 180 days after the latest of the acquisition, completion of construction or improvement of such property), or Liens existing on such property at the time of its acquisition (other than any such Liens created in contemplation of such acquisition that were not incurred to finance the acquisition of such property) or extensions, renewals, refundings or replacements of any of the foregoing for the same or a lesser amount, provided, however, that no such Lien shall extend to or cover any properties of any character other than the property being acquired, constructed or improved and proceeds, improvements and replacements thereof and no such extension, renewal, refunding or replacement shall extend to or cover any properties not theretofore subject to the Lien being extended, renewed, refunded or replaced;

(iii)assignments of the right to receive income, and Liens on property, of a Person existing at the time such Person is merged into or consolidated with the Borrower or any Subsidiary of the Borrower or becomes a Subsidiary of the Borrower;

(iv)Liens with respect to the leases and related documents entered into by the Borrower in connection with PVNGS Unit 2 and Liens with respect to the leased interests and related rights if the Borrower reacquires ownership in any of those interests or acquires any of the equity or owner participants’ interests in the trusts that hold title to such leased interests, whether or not it also directly assumes any Sale Leaseback Obligation Bonds, and Liens on the Borrower’s interests in the trusts that hold title to such leased interests and related rights in the event that the Borrower acquires any of the equity or owner participants’ interests in such trusts pursuant to a “special transfer” under the Borrower’s existing PVNGS Unit 2 sale and leaseback transactions and any Liens resulting or deemed to have resulted if the PVNGS Unit 2 leases are required to be accounted for as capital leases in accordance with GAAP;

(v)other assignments of the right to receive income and Liens securing Indebtedness or claims in an aggregate principal amount not to exceed 20% of the Borrower’s total assets as stated on the most recent balance sheet of the Borrower provided pursuant to Section 4.01(e)(i) or Section 5.01(h)(ii) hereof at any time outstanding; and

(vi)the replacement, extension or renewal of any Lien permitted by clause (iii) or (iv) above upon or in the same property theretofore subject thereto or the replacement, extension or renewal (without increase in the amount or change in any direct or contingent obligor) of the Indebtedness secured thereby.

(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)

46

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) 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 the Borrower 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 the Borrower’s interests in such Units 1, 2 and 3, or (B) disposition of all or any portion of any Subsidiary’s (other than the Borrower) 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).

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

47

(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 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

48

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 PWCC entitled to vote for members of the board of directors of PWCC; (ii) during any period of 24 consecutive months, a majority of the members of the board of directors of PWCC 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 (iii) PWCC shall cease for any reason to own, directly or indirectly, 80% of the Voting Stock of the Borrower; 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 by the Borrower, and (ii) exercise all rights and remedies available to it under this Agreement, the other Loan Documents and applicable Law.

49

ARTICLE VIITHE AGENT

Section 7.01Appointment and Authority. Each of the Lenders hereby irrevocably appoints SunTrust Bank 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 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

50

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, 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

51

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, Co-Syndication Agents 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,

52

(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,

53

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

54

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

55

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

56

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

57

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, each Co-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

58

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), Section 2.08 or Section 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,

59

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 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,

60

shall be construed to confer upon any Person (other than the parties hereto, their respective successors 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 written 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.

61

(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 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,

62

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 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 Section 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.

63

(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 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.

64

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 the Borough of Manhattan 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

65

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 the 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.

66

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]

67

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.

ARIZONA PUBLIC SERVICE COMPANY

By: /s/ Lee R. Nickloy

Name:    Lee R. Nickloy

Title:    Vice President and Treasurer

Signature Page to Arizona Public Service Company Term Loan Agreement

ADMINISTRATIVE AGENT:	SUNTRUST BANK, as Agent and a Lender
	By: /s/ Arize Agumadu
	Name:    Arize Agumadu
	Title:    Vice President

Arizona Public Service Company Term Loan Agreement

LENDERS:	TD BANK, N.A., as a Lender
	By: /s/ Vijay Prasad
	Name:    Vijay Prasad
	Title:    Senior Vice President

Signature Page to Arizona Public Service Company Term Loan Agreement

U.S. BANK NATIONAL ASSOCIATION, as a Lender

By: /s/ Michael E. Temnick

Name:    Michael E. Temnick

Title:    Vice President

Signature Page to Arizona Public Service Company Term Loan Agreement

THE BANK OF NOVA SCOTIA, as a Lender

By: /s/ David Dewar

Name:    David Dewar

Title:    Director

Signature Page to Arizona Public Service Company Term Loan Agreement

SCHEDULE 1.01

COMMITMENTS AND RATABLE SHARES

Lender	Commitment	Ratable Share
SunTrust Bank	$50,000,000	25.00%
TD Bank, N.A.	$50,000,000	25.00%
U.S. Bank National Association	$50,000,000	25.00%
The Bank of Nova Scotia	$50,000,000	25.00%
TOTAL	$200,000,000	100%

SCHEDULE 4.01(j)

SUBSIDIARIES

1. Bixco, Inc.

2. Axiom Power Solutions, Inc.

3. PWE Newco, Inc.

SCHEDULE 4.01(k)

EXISTING INDEBTEDNESS

None.

SCHEDULE 8.02

CERTAIN ADDRESSES FOR NOTICES

BORROWER:

Arizona Public Service Company

400 North 5th Street

Mail Station 9040

Phoenix, AZ 85004

Attention:     Treasurer

Telephone:    (602) 250-3300

Telecopier:    (602) 250-3902

Electronic    lee.nickloy@pinnaclewest.com

AGENT:

Notices relating to Borrowing requests or Interest Election Requests:

SunTrust Bank

303 Peachtree Street, N.E.

Atlanta, Georgia 30308

Facsimile: 404-221-2001

Telephone: 404-813-9293

Attention: Agency Services

Electronic: agency.services@suntrust.com

Notices other than with respect to Borrowing requests or Interest Election Requests:

SunTrust Bank
3333 Peachtree Road NE

Atlanta, Georgia 30326
Telephone:      404-926-5566
Attention: Brian Guffin
Electronic:      Brian.Guffin@SunTrust.com

With a copy to Administration Team:

SunTrust Bank

303 Peachtree Street, N.E.

Atlanta, Georgia 30308

Facsimile: 404-221-2001

Telephone: 404-813-9293

Attention: Agency Services

Electronic: agency.services@suntrust.com

A-1

EXHIBIT A — FORM OF

PROMISSORY NOTE

$________ February 26, 2019

FOR VALUE RECEIVED, the undersigned, ARIZONA PUBLIC SERVICE COMPANY, 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 Term Loan Agreement dated as of February 26, 2019 among the Borrower, the Lender and certain other lenders party thereto, SunTrust Bank, 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.

A-3

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

ARIZONA PUBLIC SERVICE COMPANY

By:_________________________________
Name:
Title:

A-2

LOANS AND PAYMENTS OF PRINCIPAL

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

A-3

EXHIBIT B — FORM OF NOTICE OF INITIAL

BORROWING

SunTrust Bank, as Agent

for the Lenders party

to the Term Loan Agreement

referred to below

Attention: Agency Services

February ____, 2019

Ladies and Gentlemen:

The undersigned, Arizona Public Service Company, an Arizona corporation (the “Borrower”), refers to the [execution version][draft dated 2/[__]/19] of the Term Loan Agreement (document ID number: ACTIVE 239570669 v.[__]) (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, SunTrust Bank, 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 February 26, 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 $200,000,000.

[(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;

(C)    all required regulatory authorizations including the 2018 Order and/or any Subsequent Order in respect of the Initial Borrowing have been obtained and are in full force and effect and, before and after giving effect to the Initial Borrowing and to the application of the

B-1

proceeds therefrom, the Borrower is in compliance with the provisions of the applicable order; and

(D)    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, (ii) applicable Laws of any Governmental Authority or (iii) the 2018 Order or any Subsequent Order, whichever is in force and effect at such time.

[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 February 26, 2019, (b) to fulfill the applicable conditions set forth in Article III of the Term Loan Agreement on February 26, 2019 or (c) to otherwise borrow the Eurodollar Rate Loans requested by the Borrower in this Notice of Initial Borrowing on February 26, 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,

ARIZONA PUBLIC SERVICE COMPANY

By:    ______________________________

Name:

Title:

B-2

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.

C-1

1. Assignor: ________________________________

2. Assignee: ________________________________

[and is an Affiliate of [identify Lender]]

3. Borrower: Arizona Public Service Company

4. Agent: SunTrust Bank, as the agent under the Term Loan Agreement

5. Term Loan Agreement: Term Loan Agreement dated as of February 26, 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:

C-2

[Consented to and] Accepted:

SUNTRUST BANK, as Agent

By: ______________________

Name:

Title:

C-3

[Consented to:]

ARIZONA PUBLIC SERVICE COMPANY

By: _______________________

Name:

Title:

C-4

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.

C-5

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.

C-6

EXHIBIT D – FORM OF

INTEREST ELECTION REQUEST

[Date]

SunTrust Bank, as Agent for the Lenders party to the

Term Loan Agreement referred to below

303 Peachtree Street, N.E.

Atlanta, Georgia 30308

Facsimile No.: 404-221-2001

Email: agency.services@suntrust.com

Attention: Agency Services

Ladies and Gentlemen:

The undersigned, Arizona Public Service Company, an Arizona corporation (the “Borrower”), refers to the Term Loan Agreement, dated as of February 26, 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, SunTrust Bank, 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).]

D-1

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,

ARIZONA PUBLIC SERVICE COMPANY

By:    __________________________________

Name:

Title:

D-2

EXHIBIT E – PREPAYMENT NOTICE

[____________], 20[__]

SunTrust Bank, as Agent

303 Peachtree Street, N.E.

Atlanta, Georgia 30308

Facsimile No.: 404-221-2001

Email: agency.services@suntrust.com

Attention: Agency Services

with a copy to:

SunTrust Bank, as Agent

3333 Peachtree Road NE

Atlanta, Georgia 30326

Email: Brian.Guffin@SunTrust.com

Attention: Brian Guffin

Ladies and Gentlemen:

Pursuant to Section 2.08(a) of that certain Term Loan Credit Agreement, dated as of February 26, 2019, by and among Arizona Public Service Company (the “Company”), the lenders party thereto, and SunTrust Bank, as agent (as amended, restated, supplemented or otherwise modified prior to the date hereof, the “Term Loan Agreement”), we hereby notify you that on [_______________], 20[__] we intend to repay [an aggregate principal amount of [Eurodollar Rate][Base Rate] Loans equal to $[____________][, constituting Eurodollar Rate Loans having an Interest Period ending on [_________________], 20[__]][all outstanding Loans under the Term Loan Agreement in full]. Such prepayments shall be accompanied by accrued and unpaid interest to the extent required by Section 2.08 of the Term Loan Agreement and any funding indemnification amounts required by Section 8.04(e) of the Term Loan Agreement.

ARIZONA PUBLIC SERVICE COMPANY
By ______________________________
	Name:
	Title:

EX-10.2

RESTRICTED STOCK UNIT AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of ____________________ (the "Date of Grant"), by and between Pinnacle West Capital Corporation (the "Company"), and ____________________ ("Employee").

BACKGROUND

A. The Board of Directors of the Company (the “Board of Directors”) has adopted, and the shareholders of the Company have approved, the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “Plan”), pursuant to which Restricted Stock Units and Dividend Equivalents may be granted to employees of the Company and its subsidiaries.

B. The Company desires to grant to Employee Restricted Stock Units and Dividend Equivalents under the terms of the Plan.

C. Pursuant to the Plan, the Company and Employee agree as follows:

AGREEMENT

1. Grant of Award. Pursuant to action of the Committee which was taken on the Date of Grant, the Company grants to Employee ___________ ( ) Restricted Stock Units and related Dividend Equivalents.

2. Award Subject to Plan. This Restricted Stock Unit Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement. In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.

3. Vesting of Restricted Stock Units.

(a) Regular Vesting. The Restricted Stock Units granted pursuant to Section 1 will vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement on the following dates (each a “Vesting Date”) and as otherwise set forth in this Section 3:

i. ____ Restricted Stock Units will vest on _______________;

ii. ____ Restricted Stock Units will vest on _______________;

iii. ____ Restricted Stock Units will vest on _______________; and

iv. The remaining ____ Restricted Stock Units will vest on _______________.

(b) Normal or Early Retirement, Death or Disability.

i. Provided that Employee either qualifies for “Early Retirement” or “Normal Retirement”, as defined in the Pinnacle West Capital Corporation

Retirement Plan (the “Retirement Plan”), or is a Late Career Recipient (as defined below), the Restricted Stock Units will fully vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement upon Employee’s death or Disability.

ii. The Restricted Stock Units will fully vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement upon Employee’s Termination of Employment which constitutes an Early Retirement or a Normal Retirement.

(c) Late Career Recipient. If, at the time of Employee’s death, Disability or retirement, Employee has reached sixty (60) years of age and has been credited with at least five (5) Years of Service, as defined under the Retirement Plan, and does not otherwise meet the criteria for Early Retirement or Normal Retirement under the Retirement Plan, Employee shall be treated for purposes of this Agreement as a “Late Career Recipient.” Upon the date of a Late Career Recipient’s retirement (the “Effective Date”), a portion of Employee’s unvested Restricted Stock Units that would have vested on the next Vesting Date will vest on a straight pro-rata basis based on the number of days elapsed between the last Vesting Date (or, if a Vesting Date has not yet occurred, the Date of Grant) and the Effective Date. Payment will be made on the next Vesting Date following the Effective Date in accordance with Section 4(a). No fractional Stock shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

(d) Termination Without Cause. In the event Employee’s employment is terminated by the Company without cause, the Chief Executive Officer of the Company (the “CEO”) may determine in his discretion if, to what extent, and when, any unvested portion of the Restricted Stock Units granted pursuant to this Award should vest; provided, however, that (i) any vesting of unvested Restricted Stock Units pursuant to this Section 3(d)shall be approved by the Chair of the Committee, and (ii) nothing herein shall obligate the CEO to exercise his discretion to cause any unvested Restricted Stock Units to vest.

(e) Termination For Cause. Notwithstanding any other provision in this Section 3, in the event Employee’s employment is terminated for Cause, then regardless of Employee’s retirement, Early Retirement, Normal Retirement, death or Disability, Employee shall forfeit the right to receive any cash payment or Stock hereunder that Employee would otherwise be entitled to receive following his or her date of termination. For purposes only of this Section 3(e), “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the CEO reflects adversely on the business or reputation of the Company or any of its subsidiaries or negatively affects any of the Company’s or any of its subsidiaries’ employees or customers.

(f) Disability. “Disability” has the meaning set forth for such term in the Retirement Plan.

4. Payment.

(a) Time and Form of Payment. When a Restricted Stock Unit vests in accordance with Section 3 above, Employee (or his or her estate) shall receive in exchange

2

for each Restricted Stock Unit one unrestricted fully transferrable share of Stock. Employee may elect, pursuant to Section 4(b), to receive payment for the Restricted Stock Units payable on any Vesting Date in the form of (i) fully transferrable shares of Stock, (ii) 50% cash and 50% in fully transferrable shares of Stock or (iii) 100% cash. Except as provided in Section 3(d)above following a Termination of Employment without cause, if a Restricted Stock Unit vests prior to the applicable Vesting Date due to Employee’s status as a Late Career Recipient or Employee’s Early Retirement or Normal Retirement, the payment will be made within 30 days of the Vesting Date applicable to such Restricted Stock Unit. Any cash payment will be based on the Fair Market Value of one share of Stock determined as of the applicable Vesting Date. The payment for a Restricted Stock Unit that vests prior to the applicable Vesting Date due to the death or Disability of Employee, shall be made no later than March 15 of the year following the year in which Employee dies or becomes Disabled. If Employee dies after acquiring a vested interest in the Restricted Stock Units but before receiving payment for the Restricted Stock Units, the payment will be made to Employee’s designated beneficiary in accordance with the elections previously made by Employee.

(b) Election of Form of Payment. No later than ___________, Employee must elect to receive payment for Employee’s vested Restricted Stock Units and Dividend Equivalents in (i) fully transferable shares of Stock, (ii) 50% in cash and 50% in fully transferrable shares of Stock or (iii) 100% in cash by completing and returning to the Company the election form attached to this Agreement. In the absence of a timely election by Employee, Employee will receive payment for the vested Restricted Stock Units and Dividend Equivalents in fully transferable shares of Stock.

(c) Dividend Equivalents. In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of payment pursuant to Section 3 or Section 4(a), the Company also will deliver to Employee a payment equal to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Restricted Stock Units relate from the Date of Grant to the applicable Vesting Date, plus interest on such amount at the rate of 5percent compounded quarterly. Pursuant to the election filed by the Employee pursuant to Section 4(b), payment for the Dividend Equivalents and interest will be made in (i) fully transferrable shares of Stock, (ii) 50% in cash and 50% in fully transferrable shares of Stock or (iii) 100% in cash. The number of shares of Stock distributed to Employee will be determined by dividing the amount of the Dividend Equivalents and interest by the Fair Market Value of one share of Stock as of the applicable Vesting Date. No fractional Stock shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

(d) Impact on Retirement Plans. The value of the shares of Stock distributed upon payment for the Restricted Stock Units and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.

5. Termination of Award. Except as otherwise provided in Section 3 above or in Article 15 of the Plan, in the event of the termination of Employee’s employment with the Company or any of its subsidiaries, whether due to voluntary or involuntary termination, retirement, death, Disability or otherwise, Employee’s right to vest in any additional Restricted Stock

3

Units or Dividend Equivalents under the Plan or this Award Agreement, if any, will terminate. Any unvested Restricted Stock Units and the related Dividend Equivalents will be forfeited effective as of the date that Employee terminates active employment with the Company or any of its subsidiaries.

6. Section 409A Compliance. If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A. If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception. In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement other than the election described in Section 4(b).

7. Tax Withholding. Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award. Employee shall pay any and all Taxes due in connection with a payout of Stock or cash hereunder by having the Company withhold cash or shares of Stock from such payout.

8. Continued Employment. Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its subsidiaries to terminate Employee’s employment or services at any time. In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its subsidiaries.

9. Confidentiality. During Employee’s employment and after termination thereof for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.

Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership. For purposes of this Section 9, the term “Confidential Information”

4

shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.

10. Restrictive Covenants.

(a) Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability),  Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is or intends to be engaged in the business activity of supplying electricity in any area of Arizona for which the Company or its Affiliates is authorized to supply electricity.

(b) Employee Non-Solicitation. Employee agrees that for a period of 12 months following Employee’s Termination of Employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of the Company and its Affiliates with their employees.

(c) [No Pledging or Hedging.Employee agrees that during his or her term of employment and for a period of 90 days thereafter, Employee will not pledge, margin, hypothecate, hedge, or otherwise grant an economic interest in any shares of Company stock received by Employee pursuant to this Award (net of shares sold or surrendered to meet tax withholding or exercise requirements).  This restriction shall extend to the purchase or creation of any short sales, zero-cost collars, forward sales contracts, puts, calls, options or other derivative securities in respect of any shares of Company stock.]

(d) Remedies. If Employee fails to comply with Sections 9, 10(a), [or] 10(b) [or] [10(c)] in a material respect, the Company may (i) cause any of Employee’s unvested Restricted Stock Units and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Restricted Stock Units or Dividend Equivalents, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.

11. Cooperation with Government Agencies. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically permitted by law, because Employee is providing information to government investigatory or enforcement agencies, such as the Nuclear Regulatory Commission, Department of Labor, Equal Employment Opportunity Commission (or its state equivalent), National Labor Relations Board, the Occupational Safety and Health

5

Administration (or its state equivalent) or the Securities and Exchange Commission. This Award Agreement also does not limit Employee’s ability to communicate with any government agency regarding matters within the agency’s jurisdiction or otherwise participate in any investigation or proceedings that may be conducted by such agency, including providing documents or other information without notice to the Company. Nothing in this Award Agreement shall prevent Employee from the disclosure of Confidential Information or trade secrets that: (i) is made: (a) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (b) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is permitted to be made, and is made, under seal. In the event that Employee files a lawsuit alleging retaliation by Company for reporting a suspected violation of law, Employee may disclose Confidential Information or trade secrets related to the suspected violation of law or alleged retaliation to Employee’s attorney and use the Confidential Information or trade secrets in the court proceeding if Employee or Employee’s attorney: (i) files any document containing Confidential Information or trade secrets, under seal if permitted; and (ii) does not disclose the Confidential Information or trade secrets, except pursuant to or in accordance with a court order. The Company provides this notice in compliance with federal law, including the Defend Trade Secrets Act of 2016.

12. Non‑Transferability. Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.

13. Definitions: Copy of Plan and Plan Prospectus. To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan. By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan prospectus.

14. Amendment. Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee. The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify for favorable tax treatment either for the Company or Employee or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority. Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan

6

IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.

PINNACLE WEST CAPITAL CORPORATION

By: _______________________

Its: _______________________

Date: _____________________

EMPLOYEE

By: _____________________

Date: __________________________

7

Pinnacle West Capital Corporation

RESTRICTED STOCK UNIT AWARD
ELECTION FORM

(applies to Award Agreement dated __/__/____)

INFORMATION ABOUT YOU
Last		First			Middle Initial			Employee ID#
	In accordance with the terms of the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan and pursuant to Section 4(b) of the Award Agreement, I hereby elect to receive payment for the Restricted Stock Units and Dividend Equivalents that vest on the dates set forth below in the following form (place an “X” in the “100% Stock” column, in the “50% Cash/50% Stock” column or in the “100% Cash” column for each of the years and types of Awards set forth below):
			Restricted Stock Units and Dividend Equivalents
	Vesting Date		100% Stock	50% Cash/ 50% Stock			100% Cash
	__/__/_____		¨ ¨ ¨ ¨	¨ ¨ ¨ ¨			¨ ¨ ¨ ¨
	__/__/_____
	__/__/_____
	__/__/_____
	__________________________________________ PARTICIPANT NAME (PLEASE PRINT) __________________________________________ PARTICIPANT SIGNATURE					______________________ DATE

IMPORTANT NOTE:    Please complete and return this Election Form to ________ at _______ by _____________

8

EX-10.3

PERFORMANCE SHARE AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of _________________ (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and _________________ (“Employee”).

BACKGROUND

A. The Board of Directors of the Company (the “Board of Directors”) has adopted, and the Company’s shareholders have approved, the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “Plan”), pursuant to which Performance Share Awards and Dividend Equivalent Awards may be granted to employees of the Company and its subsidiaries.

B. The Company desires to grant to Employee Performance Shares and Dividend Equivalents under the terms of the Plan.

C. Pursuant to the Plan, the Company and Employee agree as follows:

AGREEMENT

1. Grant of Award. Pursuant to action of the Committee, which was taken on the Date of Grant, the Company grants to Employee ____________ (____) Performance Shares and related Dividend Equivalents. The Performance Shares granted under this Section 1 are referred to in this Award Agreement as the “Base Grant.”

2. Award Subject to Plan. This Performance Share Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement. In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.

3. Performance Period. The Performance Period for this Award begins January 1, _____, and ends December 31, _____.

4. Payment and Vesting.

(a) Performance Shares Payable In Stock. As soon as practicable in the fiscal year immediately following the end of the Performance Period, the Company will determine (i) the Company’s Total Shareholder Return (as defined herein) as compared to the Total Shareholder Return of the companies in the S&P 1500 Super Composite Electric Utility Index (the “Growth Index”) over the Performance Period and (ii) the Company’s Average Performance with respect to the Performance Metrics (as defined herein). The Company then will deliver to Employee one (1) share of the Company’s Stock for each then-outstanding Performance Share under this Award Agreement, subject to adjustment pursuant to Section 5 below. The Company anticipates that the Stock payout, if any, related to the Company’s Total Shareholder Return will be made by _________. The Company anticipates that the Stock payout, if any, related to the Performance Metrics will be made by __________ and in no event will such Stock payout be made later than ___________.

(b) Normal or Early Retirement, Death or Disability; Late Career Recipient.

(i) Provided that Employee either qualifies for “Early Retirement” or “Normal Retirement” under the Pinnacle West Capital Corporation Retirement Plan (the “Retirement Plan”), or is a Late Career Recipient (as defined below), in the case of Employee’s death or Disability,

1

Employee shall be deemed to have been employed by the Company through the end of the Performance Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).

(ii) In the case of Employee’s Termination of Employment during the Performance Period which constitutes an Early Retirement or a Normal Retirement under the Retirement Plan, Employee shall be deemed to have been employed by the Company through the end of the Performance Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).

(iii)If, at the time of Employee’s death, Disability or retirement Employee has reached sixty (60) years of age and has been credited with at least five (5) Years of Service, as defined under the Retirement Plan, and does not otherwise meet the criteria for Early Retirement or Normal Retirement under the Retirement Plan, Employee shall be treated for purposes of this Agreement as a “Late Career Recipient”. Upon a Late Career Recipient’s retirement during the Performance Period, Employee will receive a straight prorated payout of the number of Performance Shares calculated in accordance with Section 5 based on the number of days Employee was employed during the Performance Period. Upon a Late Career Recipient’s retirement following the end of the Performance Period, Employee will receive a payout of the number of Performance Shares calculated in accordance with Section 5. No fractional Stock shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock. Employee will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).

(c) Termination Without Cause. In the event Employee’s employment is terminated by the Company without cause, the Chief Executive Officer (“CEO”) of the Company may determine in his discretion if, to what extent, and when any unvested portion of the Performance Shares granted under this Agreement should vest; provided, however, that (i) any vesting of unvested Performance Shares granted under this Agreement pursuant to this Section 4(c)shall be approved by the Committee, and (ii) nothing herein shall obligate the CEO to exercise his discretion to cause any unvested Performance Shares to vest.

(d) Termination For Cause. Notwithstanding any other provision in this Section 4, in the event Employee is terminated for Cause, then regardless of Employee’s retirement, Early Retirement, Normal Retirement, death or Disability, Employee shall forfeit the right to receive any Stock hereunder that Employee would otherwise be entitled to receive following his or her date of termination. For purposes only of this Section 4(d), “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the CEO reflects adversely on the business or reputation of the Company or any of its subsidiaries or negatively affects any of the Company’s or any of its subsidiaries’ employees or customers.

(e) Disability. “Disability” has the meaning set forth for such term in the Retirement Plan.

(f) Dividend Equivalents. In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of Stock to Employee pursuant to this Section 4, the Company also will deliver to Employee fully transferrable shares of Stock equal in value to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Performance Shares relate from the Date of Grant to the date of the Stock payout, plus interest on such amount at the rate of 5 percent compounded quarterly, as determined pursuant to the Plan. The number of shares of Stock distributed to Employee will be determined by dividing the amount of the Dividend Equivalents and interest by the Fair Market Value of one share of Stock as of the applicable date of the Stock payout. No fractional Stock shall be issued. If the Stock payout results in

2

a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

(g) Impact on Retirement Plans. The value of the shares of Stock distributed upon payment for the Performance Shares and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.

5. Performance Criteria and Adjustments. Fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(a) and fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(b). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Award Agreement greater than 2.0 times the Base Grant.

(a) Adjustment of Base Grant for Total Shareholder Return. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Total Shareholder Return” as compared to the Total Shareholder Return of the companies in the Growth Index during the Performance Period, as follows:

If the Company’s Total Shareholder Return Over The Performance Period As Compared to the Total Shareholder Return of the Companies in the Growth Index is:	The Number of Performance Shares will be:
90th Percentile or greater	1.0 X Base Grant
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

If intermediate percentiles are achieved, the number of Performance Shares awarded will be prorated (partial shares will be rounded down to the nearest whole share when applicable). For example, if the Company’s Total Shareholder Return during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to 0.60 (0.5 X 60/50) multiplied by the Base Grant. In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection 5(a) greater than 1.0 times the Base Grant.

(b) Adjustment of Base Grant for Performance Metrics. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Average Performance” with respect to the “Performance Metrics,” as follows:

If the Company’s Average Performance is:	The Number of Performance Shares will be:
90th Percentile or greater	1.0 X Base Grant
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

3

If intermediate percentiles are achieved, the number of Performance Shares awarded pursuant to this Subsection 5(b) will be prorated (partial shares will be rounded down to the nearest whole share when applicable). For example, if the Company’s Average Performance during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to .60 (0.5 X 60/50) multiplied by the Base Grant. In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection (b) greater than 1.0 times the Base Grant.

6. Definitions.

(a) Performance Metrics. The “Performance Metrics” for the Performance Period are: (i) the System Average Interruption Frequency Index (Major Events Excluded) (“SAIFI”); (ii) Arizona Public Service Company’s customer to employee improvement ratio; (iii) the OSHA rate (All Incident Injury Rate); (iv) nuclear capacity factor; and (v) coal capacity factor.

(1) With respect to the Performance Metric described in clause (i) of this Subsection 6(a), the Edison Electric Institute (“EEI”) will provide data on an annual basis regarding the SAIFI result of the participating companies; the Company will calculate its SAIFI result for the year in question and determine its percentile ranking based on the information provided by EEI.

(2) With respect to the Performance Metric described in clause (ii) of this Subsection 6(a), S&P Global Market Intelligence (“Market Intelligence”), an independent third party data system, will provide data on an annual basis regarding the customer and employee counts; the Company will use its customer and employee counts for the year in question and determine its percentile ranking based on the information provided by Market Intelligence. Only those companies whose customers and employees were included in the data provided by Market Intelligence in each of the years of the Performance Period will be considered.

(3) With respect to the Performance Metric described in clause (iii) of this Subsection 6(a), EEI will provide data on an annual basis regarding the OSHA rate of the participating companies; the Company will calculate its OSHA rate for the year in question and determine its percentile ranking based on the information provided by EEI.

(4) With respect to the Performance Metric described in clause (iv) of this Subsection 6(a), Market Intelligence will provide data on an annual basis regarding the nuclear capacity factors of the participating nuclear plants; the Company will calculate its nuclear capacity factor for the year in question and determine its percentile ranking based on the information provided by Market Intelligence. Only those plants that were included in the data provided by Market Intelligence in each of the years of the Performance Period will be considered.

(5) With respect to the Performance Metric described in clause (v) of this Subsection 6(a), Market Intelligence will provide data on an annual basis regarding the coal capacity factors of the participating coal plants; the Company will calculate its coal capacity factor for the year in question and determine its percentile ranking based on the information provided by Market Intelligence. Only those plants that were included in the data provided by Market Intelligence in each of the years of the Performance Period will be considered.

(6) The Company’s percentile ranking during the Performance Period for each Performance Metric will be the average of the Company’s percentile ranking for each Performance Metric during each of the three years of the Performance Period (each,

4

an “Average Performance Metric”); provided, however, that if the third year of a Performance Metric is not calculable by December 15 of the following year, the Performance Metric shall consist of the three most recent years for which such Performance Metric is calculable. The Company’s “Average Performance,” for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b) above will be the average of the Average Performance Metrics. If only quartile, rather than percentile, rankings are available for a particular Performance Metric, the Average Performance Metric for any such Performance Metric shall be expressed as a percentile. For example, if the Performance Metric was in the top quartile for two Performance Periods and in the lowest quartile in the other Performance Period, the average of these quartiles would be 3 (the average of 4, 4, and 1) and the Average Performance Metric would be the 75^th percentile (3 /4). The calculations in this Subsection 6(a)(6) will be verified by the Company’s internal auditors.

(7) If either EEI or Market Intelligence discontinues providing the data specified above, the Committee shall select a data source that, in the Committee’s judgment, will provide data most comparable to the data provided by EEI or Market Intelligence, as the case may be.

(b) Total Shareholder Return. “Total Shareholder Return” for the Performance Period is the measure of a company’s stock price appreciation plus any dividends paid during the Performance Period. Only those companies that were included in the Growth Index in each of the years of the Performance Period will be considered. Total Shareholder Return for the Company and the companies in the Growth Index will be determined using the Daily Comparative Return as calculated by Bloomberg (or other independent third party data system). If the Growth Index is discontinued, the Committee shall select the most comparable index then in use for the sector comparison. In addition, if the sector comparison is no longer representative of the Company’s industry or business, the Committee shall replace the Growth Index with the most representative index then in use. Once the Total Shareholder Returns of the Company and all relevant companies in the Growth Index have been determined, the member companies will be ranked from greatest to least. Percentiles will be calculated (interpolated from 0% to 100%) based on a company’s relative ranking. Percentiles will be carried out to one (1) decimal place. If the Company is not in the Growth Index, then its percentile will be interpolated between the companies listed in the relative ranking. These calculations will be verified by the Company’s internal auditors.

7. Termination of Award. This Award Agreement will terminate and be of no further force or effect on the date that Employee is no longer employed by the Company or any of its subsidiaries, whether due to voluntary or involuntary termination, death, retirement, Disability, or otherwise, except as specifically set forth in Section 4 above or in Article 15 of the Plan. Employee will, however, be entitled to receive any Stock and Dividend Equivalents payable under Section 4 of this Award Agreement if Employee’s employment terminates after the end of the Performance Period but before Employee’s receipt of such Stock and Dividend Equivalents.

5

8. Section 409A Compliance. If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A. If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception. In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement.

9. Tax Withholding. Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award. Employee shall pay any and all Taxes due in connection with a payout of Stock hereunder by having the Company withhold shares of Stock from such payout.

10. Continued Employment. Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its subsidiaries to terminate Employee’s employment or services at any time. In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its subsidiaries.

11. Confidentiality. During Employee’s employment and after termination thereof, for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.

Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership. For purposes of this Section 11, the term “Confidential Information” shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.

12. Restrictive Covenants.

(a) Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability),  Employee shall not, without the prior written consent of the Company’s General Counsel,

6

participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is or intends to be engaged in the business activity of supplying electricity in any area of Arizona for which the Company or its Affiliates is authorized to supply electricity. 

(b) Employee Non-Solicitation. Employee agrees that for a period of 12 months following Employee’s Termination of Employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of the Company and its Affiliates with their employees.

(c) [No Pledging or Hedging. Employee agrees that during his or her term of employment, Employee will not pledge, margin, hypothecate, hedge, or otherwise grant an economic interest in any shares of Company stock received by Employee pursuant to this Award (net of shares sold or surrendered to meet tax withholding or exercise requirements). This restriction shall extend to the purchase or creation of any short sales, zero-cost collars, forward sales contracts, puts, calls, options or other derivative securities in respect of any shares of Company stock.]

(d) Remedies. If Employee fails to comply with Sections 11, 12(a), [or] 12(b), [or 12(c)] in a material respect, the Company may (i) cause any of Employee’s unvested Performance Shares and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Performance Shares or Dividend Equivalents, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.

13. Cooperation with Government Agencies. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically permitted by law, because Employee is providing information to government investigatory or enforcement agencies, such as the Nuclear Regulatory Commission, Department of Labor, Equal Employment Opportunity Commission (or its state equivalent), National Labor Relations Board, the Occupational Safety and Health Administration (or its state equivalent) or the Securities and Exchange Commission. This Award Agreement also does not limit Employee’s ability to communicate with any government agency regarding matters within the agency’s jurisdiction or otherwise participate in any investigation or proceedings that may be conducted by such agency, including providing documents or other information without notice to the Company. Nothing in this Award Agreement shall prevent Employee from the disclosure of Confidential Information or trade secrets that: (i) is made: (a) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (b) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is permitted to be made, and is made, under seal. In the event that Employee files a lawsuit alleging retaliation by Company for reporting a suspected violation of law, Employee may disclose Confidential Information or trade secrets related to the suspected violation of law or alleged retaliation to Employee’s attorney and use the Confidential Information or trade secrets in the court proceeding if Employee or Employee’s attorney: (i) files any document containing Confidential Information or trade secrets, under seal if permitted; and (ii) does not disclose the Confidential Information or trade secrets, except pursuant to or in accordance with a court order. The Company provides this notice in compliance with federal law, including the Defend Trade Secrets Act of 2016.

7

14. Clawback. The portion of this Award, if any, that is earned based on the Company’s Total Shareholder Return will be subject to potential forfeiture or recovery to the extent called for by the Company’s Clawback Policy. The Clawback Policy may include such provisions as the Human Resources Committee of the Board of Directors determines to be necessary or appropriate either to comply with any applicable law or listing standard or in light of Company ethics or other policies and practices. Specific requirements of the Clawback Policy may be adopted and amended at such times as the Human Resources Committee of the Board of Directors determines in its discretion. By accepting this Award, Employee consents and agrees to abide by such Clawback Policy.

15. Non-Transferability. Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.

16. Definitions:Copy of Plan and Plan Prospectus. To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan. By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan prospectus.

17. Amendment. Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee. The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify for favorable tax treatment either for the Company or Employee or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority. Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan.

IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.

PINNACLE WEST CAPITAL CORPORATION

By: _______________________

Its: _______________________

Date: ______________________

EMPLOYEE

By:________________________

Date: ______________________

8

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:    May 1, 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:    May 1, 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:    May 1, 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:    May 1, 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 March 31, 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:      May 1, 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 March 31, 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:     May 1, 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 March 31, 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:      May 1, 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 March 31, 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:      May 1, 2019

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 24, 2019
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORPORATION
Entity Central Index Key	0000764622
Document Type	10-Q
Document Period End Date	Mar. 31, 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		112,277,359
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
APS
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	0000007286
Document Type	10-Q
Document Period End Date	Mar. 31, 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		71,264,947
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
OPERATING REVENUES	$ 740,530	$ 692,714
OPERATING EXPENSES
Fuel and purchased power	230,588	197,110
Operations and maintenance	245,634	265,682
Depreciation and amortization	148,707	144,825
Taxes other than income taxes	55,090	53,600
Other expenses	427	163
Total	680,446	661,380
OPERATING INCOME	60,084	31,334
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	11,188	14,079
Pension and other postretirement non-service credits - net	5,114	12,859
Other income (Note 9)	7,169	3,985
Other expense (Note 9)	(4,358)	(3,229)
Total	19,113	27,694
INTEREST EXPENSE
Interest charges	60,653	58,954
Allowance for borrowed funds used during construction	(6,665)	(6,755)
Total	53,988	52,199
INCOME BEFORE INCOME TAXES	25,209	6,829
INCOME TAXES	2,418	(1,265)
NET INCOME	22,791	8,094
Less: Net income attributable to noncontrolling interests (Note 6)	4,873	4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 17,918	$ 3,221
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	112,337	112,017
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	112,735	112,493
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.16	$ 0.03
Net income attributable to common shareholders - diluted (in dollars per share)	$ 0.16	$ 0.03
APS
OPERATING REVENUES	$ 740,530	$ 692,006
OPERATING EXPENSES
Fuel and purchased power	230,588	202,010
Operations and maintenance	240,375	254,601
Depreciation and amortization	148,685	144,112
Taxes other than income taxes	55,078	53,242
Other expenses	427	163
Total	675,153	654,128
OPERATING INCOME	65,377	37,878
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	11,188	14,079
Pension and other postretirement non-service credits - net	5,499	13,197
Other income (Note 9)	6,416	3,772
Other expense (Note 9)	(3,878)	(2,945)
Total	19,225	28,103
INTEREST EXPENSE
Interest charges	56,665	56,158
Allowance for borrowed funds used during construction	(6,665)	(6,755)
Total	50,000	49,403
INCOME BEFORE INCOME TAXES	34,602	16,578
INCOME TAXES	1,453	2,106
NET INCOME	33,149	14,472
Less: Net income attributable to noncontrolling interests (Note 6)	4,873	4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 28,276	$ 9,599

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
NET INCOME	$ 22,791	$ 8,094
Derivative instruments:
Net unrealized gain (loss), net of tax expense	0	(96)
Reclassification of net realized loss, net of tax expense	328	409
Pension and other postretirement benefits activity, net of tax benefit	879	900
Total other comprehensive income	1,207	1,213
COMPREHENSIVE INCOME	23,998	9,307
Less: Comprehensive income attributable to noncontrolling interests	4,873	4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	19,125	4,434
APS
NET INCOME	33,149	14,472
Derivative instruments:
Net unrealized gain (loss), net of tax expense	0	(96)
Reclassification of net realized loss, net of tax expense	328	409
Pension and other postretirement benefits activity, net of tax benefit	752	857
Total other comprehensive income	1,080	1,170
COMPREHENSIVE INCOME	34,229	15,642
Less: Comprehensive income attributable to noncontrolling interests	4,873	4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 29,356	$ 10,769

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Net unrealized loss, tax expense	$ 0	$ 96
Reclassification of net realized loss, tax expense (benefit)	108	82
Pension and other postretirement (benefits) activity, tax benefit (expense)	288	443
APS
Net unrealized loss, tax expense	0	96
Reclassification of net realized loss, tax expense (benefit)	108	82
Pension and other postretirement (benefits) activity, tax benefit (expense)	$ 247	$ 306

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 6,109	$ 5,766
Customer and other receivables	249,568	267,887
Accrued unbilled revenues	114,077	137,170
Allowance for doubtful accounts	(2,455)	(4,069)
Materials and supplies (at average cost)	280,857	269,065
Fossil fuel (at average cost)	26,294	25,029
Assets from risk management activities (Note 7)	763	1,113
Deferred fuel and purchased power regulatory asset (Note 4)	7,583	37,164
Other regulatory assets (Note 4)	127,642	129,738
Other current assets	65,951	56,128
Total current assets	876,389	924,991
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	919,309	851,134
Other special use funds (Notes 11 and 12)	238,207	236,101
Other assets	99,446	103,247
Total investments and other assets	1,256,962	1,190,482
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	18,763,499	18,736,628
Accumulated depreciation and amortization	(6,398,512)	(6,366,014)
Net	12,364,987	12,370,614
Construction work in progress	1,233,018	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	104,808	105,775
Intangible assets, net of accumulated amortization	267,998	262,902
Nuclear fuel, net of accumulated amortization	142,610	120,217
Total property, plant and equipment	14,113,421	14,029,570
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,507	1,342,941
Operating lease right-of-use assets (Note 16)	193,897	0
Assets for other postretirement benefits (Note 5)	52,674	46,906
Other	39,257	129,312
Total deferred debits	1,607,335	1,519,159
TOTAL ASSETS	17,854,107	17,664,202
CURRENT LIABILITIES
Accounts payable	263,656	277,336
Accrued taxes	199,949	154,819
Accrued interest	50,074	61,107
Common dividends payable	0	82,675
Short-term borrowings (Note 3)	244,050	76,400
Current maturities of long-term debt (Note 3)	250,000	500,000
Customer deposits	87,263	91,174
Liabilities from risk management activities (Note 7)	33,289	35,506
Liabilities for asset retirements	22,823	19,842
Operating lease liabilities (Note 16)	65,435	0
Regulatory liabilities (Note 4)	260,404	165,876
Other current liabilities	114,361	184,229
Total current liabilities	1,591,304	1,648,964
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,811,689	1,807,421
Regulatory liabilities (Note 4)	2,272,082	2,325,976
Liabilities for asset retirements	712,885	706,703
Liabilities for pension benefits (Note 5)	384,492	443,170
Liabilities from risk management activities (Note 7)	14,844	24,531
Customer advances	155,894	137,153
Coal mine reclamation	214,037	212,785
Deferred investment tax credit	200,052	200,405
Unrecognized tax benefits	26,042	22,517
Operating lease liabilities (Note 16)	53,704	0
Other	149,249	147,640
Total deferred credits and other	5,994,970	6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,340,322 and 112,159,896 issued at respective dates	2,644,063	2,634,265
Treasury stock at cost; 63,271 and 58,135 shares at respective dates	(5,586)	(4,825)
Total common stock	2,638,477	2,629,440
Retained earnings	2,659,086	2,641,183
Accumulated other comprehensive loss	(46,501)	(47,708)
Total shareholders’ equity	5,251,062	5,222,915
Noncontrolling interests (Note 6)	130,663	125,790
Total equity	5,381,725	5,348,705
Long-term debt less current maturities (Note 3)	4,886,108	4,638,232
TOTAL LIABILITIES AND EQUITY	17,854,107	17,664,202
APS
CURRENT ASSETS
Cash and cash equivalents	6,080	5,707
Customer and other receivables	238,270	257,654
Accrued unbilled revenues	114,077	137,170
Allowance for doubtful accounts	(2,455)	(4,069)
Materials and supplies (at average cost)	280,857	269,065
Fossil fuel (at average cost)	26,294	25,029
Assets from risk management activities (Note 7)	763	1,113
Deferred fuel and purchased power regulatory asset (Note 4)	7,583	37,164
Other regulatory assets (Note 4)	127,642	129,738
Other current assets	44,417	35,111
Total current assets	843,528	893,682
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 11 and 12)	919,309	851,134
Other special use funds (Notes 11 and 12)	238,207	236,101
Other assets	42,090	40,817
Total investments and other assets	1,199,606	1,128,052
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	18,760,012	18,733,142
Accumulated depreciation and amortization	(6,395,265)	(6,362,771)
Net	12,364,747	12,370,371
Construction work in progress	1,233,018	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	104,808	105,775
Intangible assets, net of accumulated amortization	267,842	262,746
Nuclear fuel, net of accumulated amortization	142,610	120,217
Total property, plant and equipment	14,113,025	14,029,171
DEFERRED DEBITS
Regulatory assets (Note 4)	1,321,507	1,342,941
Operating lease right-of-use assets (Note 16)	191,957	0
Assets for other postretirement benefits (Note 5)	48,961	43,212
Other	38,299	128,265
Total deferred debits	1,600,724	1,514,418
TOTAL ASSETS	17,756,883	17,565,323
CURRENT LIABILITIES
Accounts payable	257,124	266,277
Accrued taxes	230,591	176,357
Accrued interest	47,585	60,228
Common dividends payable	0	82,700
Short-term borrowings (Note 3)	157,500	0
Current maturities of long-term debt (Note 3)	250,000	500,000
Customer deposits	87,263	91,174
Liabilities from risk management activities (Note 7)	33,289	35,506
Liabilities for asset retirements	22,823	19,842
Operating lease liabilities (Note 16)	65,267	0
Regulatory liabilities (Note 4)	260,404	165,876
Other current liabilities	114,665	178,137
Total current liabilities	1,526,511	1,576,097
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,815,368	1,812,664
Regulatory liabilities (Note 4)	2,272,082	2,325,976
Liabilities for asset retirements	712,885	706,703
Liabilities for pension benefits (Note 5)	367,296	425,404
Liabilities from risk management activities (Note 7)	14,844	24,531
Customer advances	155,894	137,153
Coal mine reclamation	214,037	212,785
Deferred investment tax credit	200,052	200,405
Unrecognized tax benefits	42,084	41,861
Operating lease liabilities (Note 16)	51,805	0
Other	125,844	125,511
Total deferred credits and other	5,972,191	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	2,816,532	2,788,256
Accumulated other comprehensive loss	(26,027)	(27,107)
Total shareholders’ equity	5,690,363	5,661,007
Noncontrolling interests (Note 6)	130,663	125,790
Total equity	5,821,026	5,786,797
Long-term debt less current maturities (Note 3)	4,437,155	4,189,436
Total capitalization	10,258,181	9,976,233
TOTAL LIABILITIES AND EQUITY	$ 17,756,883	$ 17,565,323

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 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)	112,340,322	112,159,896
Treasury stock at cost, shares (in shares)	63,271	58,135

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 22,791	$ 8,094
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	167,801	163,566
Deferred fuel and purchased power	16,709	(18,950)
Deferred fuel and purchased power amortization	12,872	20,002
Allowance for equity funds used during construction	(11,188)	(14,079)
Deferred income taxes	3,620	(229)
Deferred investment tax credit	(353)	(147)
Stock compensation	12,074	10,537
Changes in current assets and liabilities:
Customer and other receivables	15,476	89,518
Accrued unbilled revenues	23,093	(6,555)
Materials, supplies and fossil fuel	(13,057)	(16,607)
Other current assets	(10,115)	(664)
Accounts payable	26,593	(25,738)
Accrued taxes	45,130	45,984
Other current liabilities	(86,250)	(12,030)
Change in other long-term assets	(65,470)	(3,765)
Change in other long-term liabilities	13,706	(72,065)
Net cash flow provided by operating activities	173,432	166,872
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(259,792)	(361,037)
Contributions in aid of construction	7,938	8,569
Allowance for borrowed funds used during construction	(6,665)	(6,755)
Proceeds from nuclear decommissioning trust sales and other special use funds	179,048	130,456
Investment in nuclear decommissioning trust and other special use funds	(179,618)	(131,027)
Other	4,576	(1,299)
Net cash flow used for investing activities	(254,513)	(361,093)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324	0
Short-term borrowing and payments — net	172,650	263,500
Short-term debt borrowings under revolving credit facility	0	36,000
Short-term debt repayments under revolving credit facility	(5,000)	(25,000)
Dividends paid on common stock	(80,897)	(75,903)
Repayment of long-term debt	(500,000)	0
Common stock equity issuance - net of purchases	(2,653)	(2,828)
Net cash flow provided by financing activities	81,424	195,769
NET INCREASE IN CASH AND CASH EQUIVALENTS	343	1,548
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,766	13,892
CASH AND CASH EQUIVALENTS AT END OF PERIOD	6,109	15,440
Supplemental disclosure of cash flow information
Income taxes, net of refunds	1	0
Interest, net of amounts capitalized	63,764	56,026
Significant non-cash investing and financing activities:
Accrued capital expenditures	95,879	86,991
APS
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	33,149	14,472
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	167,779	162,853
Deferred fuel and purchased power	16,709	(18,950)
Deferred fuel and purchased power amortization	12,872	20,002
Allowance for equity funds used during construction	(11,188)	(14,079)
Deferred income taxes	(1,205)	533
Deferred investment tax credit	(353)	(147)
Changes in current assets and liabilities:
Customer and other receivables	16,541	90,647
Accrued unbilled revenues	23,093	(6,555)
Materials, supplies and fossil fuel	(13,057)	(16,747)
Other current assets	(9,598)	(1,237)
Accounts payable	30,774	(24,592)
Accrued taxes	54,234	54,106
Other current liabilities	(81,627)	(15,771)
Change in other long-term assets	(64,516)	3,722
Change in other long-term liabilities	14,525	(70,928)
Net cash flow provided by operating activities	188,132	177,329
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(259,446)	(355,039)
Contributions in aid of construction	7,938	8,569
Allowance for borrowed funds used during construction	(6,665)	(6,755)
Proceeds from nuclear decommissioning trust sales and other special use funds	179,048	130,456
Investment in nuclear decommissioning trust and other special use funds	(179,618)	(131,027)
Other	(1,140)	(1,183)
Net cash flow used for investing activities	(259,883)	(354,979)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	497,324	0
Short-term borrowing and payments — net	157,500	255,500
Short-term debt borrowings under revolving credit facility	0	25,000
Short-term debt repayments under revolving credit facility	0	(25,000)
Dividends paid on common stock	(82,700)	(77,700)
Repayment of long-term debt	(500,000)	0
Net cash flow provided by financing activities	72,124	177,800
NET INCREASE IN CASH AND CASH EQUIVALENTS	373	150
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,707	13,851
CASH AND CASH EQUIVALENTS AT END OF PERIOD	6,080	14,001
Supplemental disclosure of cash flow information
Income taxes, net of refunds	0	0
Interest, net of amounts capitalized	61,387	54,873
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 95,879	$ 86,944

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		8,094			3,221				4,873	14,472			9,599				4,873
Other comprehensive income		1,213					1,213			1,170					1,170
Other										1							1
Dividends on common stock		(16)			(16)
Issuance of common stock (in shares)			145,793
Issuance of common stock		5,456	$ 5,456
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)				116,543
Reissuance of treasury stock for stock-based compensation and other		9,471		$ 9,470	0				1
Reclassification of income tax effects related to new tax reform		(8,552)			8,552	[2]	(8,552)	[2]		(5,038)			5,038	[2]	(5,038)	[2]
Ending balance (in shares) at Mar. 31, 2018			111,961,963	29,097							71,264,947
Balance at end 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
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		22,791			17,918				4,873	33,149			28,276				4,873
Other comprehensive income		1,207					1,207			1,080					1,080
Dividends on common stock		(15)			(15)
Issuance of common stock (in shares)			180,426
Issuance of common stock		9,798	$ 9,798
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)				70,655
Reissuance of treasury stock for stock-based compensation and other		$ 6,121		$ 6,121	0				0
Ending balance (in shares) at Mar. 31, 2019		112,340,322	112,340,322	63,271							71,264,947
Balance at end 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

[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.

XML

Consolidation and Nature of Operations

3 Months Ended

Mar. 31, 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):

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

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

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

XML

Revenue

3 Months Ended

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

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 months ended March 31, 2019 and 2018 were $721 million and $683 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three months ended March 31, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $20 million and $10 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of March 31, 2019 or December 31, 2018.

XML

Long-Term Debt and Liquidity Matters

3 Months Ended

Mar. 31, 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

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

At March 31, 2019, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2019,

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

APS

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

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

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

At March 31, 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 March 31, 2019, APS had $158 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 APS’s other outstanding letters of credit.

Debt Fair Value

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

	As of March 31, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	448,953	$	446,835	$	448,796	$	443,955
APS	4,687,155		4,942,057		4,689,436		4,789,608
Total	$	5,136,108	$	5,388,892	$	5,138,232	$	5,233,563

XML

Regulatory Matters

3 Months Ended

Mar. 31, 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 have been consolidated, and APS requested and was granted intervention. Mr. Woodward filed his opening brief on March 28, 2018.  The ACC and APS filed responsive briefs on June 21, 2018. The Arizona Court of Appeals issued a Memorandum Decision on December 11, 2018 affirming the ACC decisions challenged by Mr. Woodward.  Mr. Woodward filed a petition for review with the Arizona Supreme Court on January 9, 2019. Review by the Arizona Supreme Court is discretionary. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact on our financial position, results of operations or cash flows.

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

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 January 9, 2019, the ACC Commissioners voted to open a docket for this matter.  On April 23, 2019, the ACC Staff indicated that they may need some additional time beyond May 3, 2019 to file the requested report. APS does not believe that the rate review will have a material impact on our current financial position, results of operations or cash flows.  However, depending

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

Cost Recovery Mechanisms

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

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

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

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan including a waiver of the distributed energy requirements for the 2018 implementation year.

On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. The ACC has not yet ruled on the 2019 RES Implementation Plan.

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

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

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.

 Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2019 and 2018 (dollars in thousands):

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

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

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

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

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 is 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 reflects the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018.

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.

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

Information Requests from Arizona Corporation Commissioners

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

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

In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals.  The rulemaking will consider possible modifications to existing ACC rules, such as the Renewable Energy Standard, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On April 26, 2019, Commissioner Dunn issued a proposed set of rules with regards to the Energy Modernization Plan. 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 Integrated Resource Plan from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request.

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 $46 million as of March 31, 2019 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

 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. Oral argument for this proceeding is scheduled for May 15, 2019. APS cannot predict the outcome of the 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 anticipates a decision later in 2019, however we cannot predict the outcome of the decision. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table 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 ($85 million as of March 31, 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 2026.

On March 20, 2019, APS announced that it has begun evaluating the feasibility and cost of converting a unit at the Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS will report the result of its evaluation by May 20, 2019. If converting a unit is more cost effective than alternatives, APS will seek ACC approval before moving forward with the Cholla conversion project. APS cannot predict the outcome of this matter.

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.

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

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 ($85 million as of March 31, 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	March 31, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	723,307	$	—	$	733,351
Retired power plant costs	2033	28,182		160,167		28,182		167,164
Income taxes — allowance for funds used during construction ("AFUDC") equity	2049	6,457		151,541		6,457		151,467
Deferred fuel and purchased power — mark-to-market (Note 7)	2023	29,340		14,360		31,728		23,768
Deferred fuel and purchased power (b) (c)	2020	7,583		—		37,164		—
Four Corners cost deferral	2024	8,077		38,209		8,077		40,228
Income taxes — investment tax credit basis adjustment	2047	1,079		25,475		1,079		25,522
Lost fixed cost recovery (b)	2020	29,698		—		32,435		—
Palo Verde VIEs (Note 6)	2046	—		20,170		—		20,015
Deferred compensation	2036	—		37,581		—		36,523
Deferred property taxes	2027	8,569		64,214		8,569		66,356
Loss on reacquired debt	2038	1,637		13,259		1,637		13,668
Tax expense of Medicare subsidy	2024	1,235		6,122		1,235		6,176
TCA balancing account (b)	2020	306		—		3,860		772
AG-1 deferral	2022	2,654		5,155		2,654		5,819
Mead-Phoenix transmission line CIAC	2050	332		9,961		332		10,044
Coal reclamation	2026	1,546		17,392		1,546		15,607
SCR deferral	N/A	—		30,581		—		23,276
Tax expense adjuster mechanism (c)	2019	5,451		—		—		—
Other	Various	3,079		4,013		1,947		3,185
Total regulatory assets (d)		$	135,225	$	1,321,507	$	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	March 31, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act	(a)	$	91,401	$	1,178,216	$	—	$	1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act	2058	6,302		243,418		6,302		243,691
Asset retirement obligations	2057	—		337,844		—		278,585
Removal costs	(b)	50,701		156,578		39,866		177,533
Other postretirement benefits	(c)	37,864		116,478		37,864		125,903
Income taxes — deferred investment tax credit	2047	2,164		51,027		2,164		51,120
Income taxes — change in rates	2048	2,764		69,954		2,769		70,069
Spent nuclear fuel	2027	7,190		54,866		6,503		57,002
Renewable energy standard (a)	2020	47,943		—		44,966		20
Demand side management (a)	2020	1,581		24,146		14,604		4,123
Sundance maintenance	2030	6,657		11,637		1,278		17,228
Deferred gains on utility property	2022	3,923		5,975		4,423		6,581
Four Corners coal reclamation	2038	1,858		17,690		1,858		17,871
Tax expense adjustor mechanism (a)	2020	14		—		3,237		—
Other	Various	42		4,253		42		3,541
Total regulatory liabilities		$	260,404	$	2,272,082	$	165,876	$	2,325,976

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

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

(c)

See Note 5.

XML

Retirement Plans and Other Postretirement Benefits

3 Months Ended

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

Contributions

We have made voluntary contributions of $90 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

3 Months Ended

Mar. 31, 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 months ended March 31, 2019 and 2018 of $5 million, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

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

	March 31, 2019		December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	104,808	$	105,775
Equity — Noncontrolling interests	130,663		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

3 Months Ended

Mar. 31, 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 March 31, 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	March 31, 2019	December 31, 2018
Power	GWh	1,146	250
Gas	Billion cubic feet	233	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 months ended March 31, 2019 and 2018 (dollars in thousands):

 

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

(a) During the three months ended March 31, 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 $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 months ended March 31, 2019 and 2018 (dollars in thousands):

 

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

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

Derivative Instruments in the Condensed Consolidated Balance Sheets

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

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

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, 2019 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 March 31, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,658		$	(2,857	)	$	801		$	(38	)	$	763
Investments and other assets	1,016			(881		)	135			—			135
Total assets	4,674			(3,738		)	936			(38		)	898
Current liabilities	(34,487		)	2,857			(31,630		)	(1,659		)	(33,289		)
Deferred credits and other	(15,725		)	881			(14,844		)	—			(14,844		)
Total liabilities	(50,212		)	3,738			(46,474		)	(1,659		)	(48,133		)
Total	$	(45,538	)	$	—		$	(45,538	)	$	(1,697	)	$	(47,235	)

(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 $1,659 and cash margin provided to counterparties of ($38).

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 March 31, 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 March 31, 2019 (dollars in thousands):

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

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

We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $102 million if our debt credit ratings were to fall below investment grade.

XML

Commitments and Contingencies

3 Months Ended

Mar. 31, 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).

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $14.1 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.6 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 $24.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $71.2 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

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

Other than the item described above, there have been no material changes, as of March 31, 2019, outside the normal course of business in contractual obligations from the information provided in our 2018 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 Coal Supply Agreement - 4CA Matter" below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

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

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 Note 4 for 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. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. 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 recently 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 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. On June 2, 2014, EPA issued two proposed rules to regulate greenhouse gas ("GHG") emissions from modified and reconstructed EGUs pursuant to Section 111(b) of the Clean Air Act and existing fossil fuel-fired power plants pursuant to Clean Air Act Section 111(d). On August 3, 2015, EPA finalized carbon pollution standards for EGUs, the "Clean Power Plan". On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan and proposed replacement regulations on August 21, 2018. In addition, judicial challenges to the Clean Power Plan are pending before the D.C. Circuit, though that litigation is currently in abeyance while EPA develops regulatory action to potentially repeal and replace that regulation.

EPA's pending proposal to regulate carbon emissions from EGUs replaces the Clean Power Plan with standards that are based entirely upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the Clean Power Plan, EPA's proposed "Affordable Clean Energy Rule" would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. In addition, to address the New Source Review ("NSR") implications of power plant upgrades potentially necessary to achieve compliance with the proposed Affordable Clean Energy Rule standards, EPA also proposed to revise EPA's NSR regulations to more readily authorize the implementation of EGU efficiency upgrades.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to approve the EPA's recently proposed Affordable Clean Energy Rule. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal, which is still pending.

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

Federal Agency Environmental Lawsuit Related to Four Corners

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

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. Oral argument for this appeal occurred on March 7, 2019. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court 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. EPA indicated that, depending on the extent of public comments it receives concerning the permit proposal, it anticipates taking final action on a new NPDES permit by August 2019. At this time we cannot predict the outcome of EPA's reconsideration of the NPDES permit and whether reconsideration will have a material impact on our financial position, results of operations or cash flows.

Four Corners - 4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. Concurrent with the settlement of the 2016 Coal Supply Agreement matter described above, NTEC and 4CA agreed to allow for the purchase by NTEC of the 7% interest, consistent with the option. On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement providing for the sale to NTEC of 4CA's 7% interest in Four Corners. Completion of the sale was subject to the receipt of approval by FERC, which was received on July 2, 2018, and the sale transaction closed on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. 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 March 31, 2019, standby letters of credit totaled $0.2 million and will expire in 2019. As of March 31, 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 March 31, 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 Coal Supply Agreement - 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

3 Months Ended

Mar. 31, 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 months ended March 31, 2019 and 2018 (dollars in thousands):

	Three Months Ended   March 31,
	2019			2018
Other income:
Interest income	$	2,302		$	1,891
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Miscellaneous	23			2
Total other income	$	7,169		$	3,985
Other expense:
Non-operating costs	$	(2,704	)	$	(1,646	)
Investment losses — net	(238		)	(176		)
Miscellaneous	(1,416		)	(1,407		)
Total other expense	$	(4,358	)	$	(3,229	)

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

	Three Months Ended   March 31,
	2019			2018
Other income:
Interest income	$	1,550		$	1,678
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Miscellaneous	22			2
Total other income	$	6,416		$	3,772
Other expense:
Non-operating costs	$	(2,467	)	$	(1,539	)
Miscellaneous	(1,411		)	(1,406		)
Total other expense	$	(3,878	)	$	(2,945	)

XML

Earnings Per Share

3 Months Ended

Mar. 31, 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 months ended March 31, 2019 and 2018 (in thousands, except per share amounts):

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

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 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 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 trust. 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 March 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at March 31, 2019
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	3,598		$	1,076		$	(3,776	)	(a)	$	898
Nuclear decommissioning trust:
Equity securities	7,547		—			—			2,630			(b)	10,177
U.S. commingled equity funds	—		—			—			451,229			(c)	451,229
U.S. Treasury debt	155,231		—			—			—				155,231
Corporate debt	—		108,509			—			—				108,509
Mortgage-backed debt securities	—		113,002			—			—				113,002
Municipal bonds	—		70,375			—			—				70,375
Other fixed income	—		10,786			—			—				10,786
Subtotal nuclear decommissioning trust	162,778		302,672			—			453,859				919,309
Other special use funds:
Equity securities	11,471		—			—			1,563			(b)	13,034
U.S. Treasury debt	208,945		—			—			—				208,945
Municipal bonds	—		16,228			—			—				16,228
Subtotal other special use funds	220,416		16,228			—			1,563				238,207
Total Assets	$	383,194	$	322,498		$	1,076		$	451,646			$	1,158,414
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(43,524	)	$	(6,688	)	$	2,079		(a)	$	(48,133	)

(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 (a) (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 debt 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 March 31, 2019 and December 31, 2018:

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

(a) Includes swaps and physical and financial contracts.

	December 31, 2018 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	—	$	2,456	Discounted cash flows	Electricity forward price (per MWh)	$17.88 - $37.03	$	26.10
Natural Gas:
Forward Contracts (a)	2		5,760		Discounted cash flows	Natural gas forward price (per MMBtu)	$1.79 - $2.92	$	2.48
Total	$	2	$	8,216

(a) Includes swaps and physical and financial contracts.

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

	Three Months Ended   March 31,
Commodity Contracts	2019			2018
Net derivative balance at beginning of period	$	(8,214	)	$	(18,256	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(1,579		)	(2,322		)
Settlements	518			782
Transfers into Level 3 from Level 2	(2		)	(2,445		)
Transfers from Level 3 into Level 2	3,665			2,487
Net derivative balance at end of period	$	(5,612	)	$	(19,754	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

Financial Instruments Not Carried at Fair Value

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 3 for our long-term debt fair values. The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $57 million as of March 31, 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

3 Months Ended

Mar. 31, 2019

Investments, Debt and Equity Securities [Abstract]

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Condensed Consolidated Balance Sheets. See Note 11 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts - To fund the future costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning

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 Accounts - 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 period and in future periods. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including other-than-temporary impairments) 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 March 31, 2019 and December 31, 2018 (dollars in thousands):  

	March 31, 2019
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
Equity securities	$	458,776	$	11,471	$	470,247		$	273,817	$	(4	)
Available for sale-fixed income securities	457,903		225,173		683,076		(a)	15,306		(2,250		)
Other	2,630		1,563		4,193		(b)	—		—
Total	$	919,309	$	238,207	$	1,157,516		$	289,123	$	(2,254	)

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

(b) Represents net pending securities sales and purchases.

	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		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 months ended March 31, 2019 and 2018 (dollars in thousands):

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

(a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds.

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

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

(a)

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

XML

New Accounting Standards

3 Months Ended

Mar. 31, 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.

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. The new standard is 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.

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. 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

3 Months Ended

Mar. 31, 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 months ended March 31, 2019 and 2018 (dollars in thousands):

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2018	$	(45,997	)		$	(1,711	)		$	(47,708	)
Amounts reclassified from accumulated other comprehensive loss	879			(a)	328			(b)	1,207
Balance March 31, 2019	$	(45,118	)		$	(1,383	)		$	(46,501	)
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	900			(a)	409			(b)	1,309
Reclassification of income tax effect related to tax reform	(7,954		)	(c)	(598		)	(c)	(8,552		)
Balance March 31, 2018	$	(49,494	)		$	(2,847	)		$	(52,341	)

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

(c)

In 2018, the company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2019 and 2018 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2018	$	(25,396	)		$	(1,711	)		$	(27,107	)
Amounts reclassified from accumulated other comprehensive loss	752			(a)	328			(b)	1,080
Balance March 31, 2019	$	(24,644	)		$	(1,383	)		$	(26,027	)
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	857			(a)	409			(b)	1,266
Reclassification of income tax effect related to tax reform	(4,440		)	(c)	(598		)	(c)	(5,038		)
Balance March 31, 2018	$	(28,004	)		$	(2,847	)		$	(30,851	)

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

(c)

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

XML

Income Taxes

3 Months Ended

Mar. 31, 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. 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 (see Note 6).  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.

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, we are no longer subject to state income tax examinations by tax authorities for years before 2014.

XML

Leases

3 Months Ended

Mar. 31, 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.

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

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

The following table provides information related to our lease costs for the three months ended March 31, 2019 (dollars in thousands):

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

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). 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. Short-term lease cost is immaterial.

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

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

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

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

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

	March 31, 2019
Weighted average remaining lease term	8 years
Weighted average discount rate	3.86		%
	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	3,087

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

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

XML

New Accounting Standards (Policies)

3 Months Ended

Mar. 31, 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.

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. The new standard is 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.

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. 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)

3 Months Ended

Mar. 31, 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):

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

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

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

XML

Revenue (Tables)

3 Months Ended

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

XML

Long-Term Debt and Liquidity Matters (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	448,953	$	446,835	$	448,796	$	443,955
APS	4,687,155		4,942,057		4,689,436		4,789,608
Total	$	5,136,108	$	5,388,892	$	5,138,232	$	5,233,563

XML

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 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 (liability) for 2019 and 2018 (dollars in thousands):

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

Schedule of regulatory assets

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

	Amortization Through	March 31, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	723,307	$	—	$	733,351
Retired power plant costs	2033	28,182		160,167		28,182		167,164
Income taxes — allowance for funds used during construction ("AFUDC") equity	2049	6,457		151,541		6,457		151,467
Deferred fuel and purchased power — mark-to-market (Note 7)	2023	29,340		14,360		31,728		23,768
Deferred fuel and purchased power (b) (c)	2020	7,583		—		37,164		—
Four Corners cost deferral	2024	8,077		38,209		8,077		40,228
Income taxes — investment tax credit basis adjustment	2047	1,079		25,475		1,079		25,522
Lost fixed cost recovery (b)	2020	29,698		—		32,435		—
Palo Verde VIEs (Note 6)	2046	—		20,170		—		20,015
Deferred compensation	2036	—		37,581		—		36,523
Deferred property taxes	2027	8,569		64,214		8,569		66,356
Loss on reacquired debt	2038	1,637		13,259		1,637		13,668
Tax expense of Medicare subsidy	2024	1,235		6,122		1,235		6,176
TCA balancing account (b)	2020	306		—		3,860		772
AG-1 deferral	2022	2,654		5,155		2,654		5,819
Mead-Phoenix transmission line CIAC	2050	332		9,961		332		10,044
Coal reclamation	2026	1,546		17,392		1,546		15,607
SCR deferral	N/A	—		30,581		—		23,276
Tax expense adjuster mechanism (c)	2019	5,451		—		—		—
Other	Various	3,079		4,013		1,947		3,185
Total regulatory assets (d)		$	135,225	$	1,321,507	$	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	March 31, 2019				December 31, 2018
		Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act	(a)	$	91,401	$	1,178,216	$	—	$	1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act	2058	6,302		243,418		6,302		243,691
Asset retirement obligations	2057	—		337,844		—		278,585
Removal costs	(b)	50,701		156,578		39,866		177,533
Other postretirement benefits	(c)	37,864		116,478		37,864		125,903
Income taxes — deferred investment tax credit	2047	2,164		51,027		2,164		51,120
Income taxes — change in rates	2048	2,764		69,954		2,769		70,069
Spent nuclear fuel	2027	7,190		54,866		6,503		57,002
Renewable energy standard (a)	2020	47,943		—		44,966		20
Demand side management (a)	2020	1,581		24,146		14,604		4,123
Sundance maintenance	2030	6,657		11,637		1,278		17,228
Deferred gains on utility property	2022	3,923		5,975		4,423		6,581
Four Corners coal reclamation	2038	1,858		17,690		1,858		17,871
Tax expense adjustor mechanism (a)	2020	14		—		3,237		—
Other	Various	42		4,253		42		3,541
Total regulatory liabilities		$	260,404	$	2,272,082	$	165,876	$	2,325,976

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

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

(c)

See Note 5.

XML

Retirement Plans and Other Postretirement Benefits (Tables)

3 Months Ended

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

XML

Palo Verde Sale Leaseback Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2019

Variable Interest Entities [Abstract]

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

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

	March 31, 2019		December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	104,808	$	105,775
Equity — Noncontrolling interests	130,663		125,790

XML

Derivative Accounting (Tables)

3 Months Ended

Mar. 31, 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 March 31, 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	March 31, 2019	December 31, 2018
Power	GWh	1,146	250
Gas	Billion cubic feet	233	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 months ended March 31, 2019 and 2018 (dollars in thousands):

 

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

(a) During the three months ended March 31, 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 months ended March 31, 2019 and 2018 (dollars in thousands):

 

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

(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 March 31, 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 March 31, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,658		$	(2,857	)	$	801		$	(38	)	$	763
Investments and other assets	1,016			(881		)	135			—			135
Total assets	4,674			(3,738		)	936			(38		)	898
Current liabilities	(34,487		)	2,857			(31,630		)	(1,659		)	(33,289		)
Deferred credits and other	(15,725		)	881			(14,844		)	—			(14,844		)
Total liabilities	(50,212		)	3,738			(46,474		)	(1,659		)	(48,133		)
Total	$	(45,538	)	$	—		$	(45,538	)	$	(1,697	)	$	(47,235	)

(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 $1,659 and cash margin provided to counterparties of ($38).

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 March 31, 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 March 31, 2019: (dollars in thousands)	Gross  Recognized  Derivatives  (a)			Amounts Offset  (b)			Net  Recognized  Derivatives			Other  (c)			Amount Reported on Balance Sheets
Current assets	$	3,658		$	(2,857	)	$	801		$	(38	)	$	763
Investments and other assets	1,016			(881		)	135			—			135
Total assets	4,674			(3,738		)	936			(38		)	898
Current liabilities	(34,487		)	2,857			(31,630		)	(1,659		)	(33,289		)
Deferred credits and other	(15,725		)	881			(14,844		)	—			(14,844		)
Total liabilities	(50,212		)	3,738			(46,474		)	(1,659		)	(48,133		)
Total	$	(45,538	)	$	—		$	(45,538	)	$	(1,697	)	$	(47,235	)

(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 $1,659 and cash margin provided to counterparties of ($38).

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 March 31, 2019 (dollars in thousands):

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

(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)

3 Months Ended

Mar. 31, 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 months ended March 31, 2019 and 2018 (dollars in thousands):

	Three Months Ended   March 31,
	2019			2018
Other income:
Interest income	$	2,302		$	1,891
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Miscellaneous	23			2
Total other income	$	7,169		$	3,985
Other expense:
Non-operating costs	$	(2,704	)	$	(1,646	)
Investment losses — net	(238		)	(176		)
Miscellaneous	(1,416		)	(1,407		)
Total other expense	$	(4,358	)	$	(3,229	)

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

	Three Months Ended   March 31,
	2019			2018
Other income:
Interest income	$	1,550		$	1,678
Debt return on Four Corners SCR (Note 4)	4,844			2,092
Miscellaneous	22			2
Total other income	$	6,416		$	3,772
Other expense:
Non-operating costs	$	(2,467	)	$	(1,539	)
Miscellaneous	(1,411		)	(1,406		)
Total other expense	$	(3,878	)	$	(2,945	)

XML

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 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 months ended March 31, 2019 and 2018 (in thousands, except per share amounts):

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

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at March 31, 2019
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	3,598		$	1,076		$	(3,776	)	(a)	$	898
Nuclear decommissioning trust:
Equity securities	7,547		—			—			2,630			(b)	10,177
U.S. commingled equity funds	—		—			—			451,229			(c)	451,229
U.S. Treasury debt	155,231		—			—			—				155,231
Corporate debt	—		108,509			—			—				108,509
Mortgage-backed debt securities	—		113,002			—			—				113,002
Municipal bonds	—		70,375			—			—				70,375
Other fixed income	—		10,786			—			—				10,786
Subtotal nuclear decommissioning trust	162,778		302,672			—			453,859				919,309
Other special use funds:
Equity securities	11,471		—			—			1,563			(b)	13,034
U.S. Treasury debt	208,945		—			—			—				208,945
Municipal bonds	—		16,228			—			—				16,228
Subtotal other special use funds	220,416		16,228			—			1,563				238,207
Total Assets	$	383,194	$	322,498		$	1,076		$	451,646			$	1,158,414
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(43,524	)	$	(6,688	)	$	2,079		(a)	$	(48,133	)

(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 (a) (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 debt 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 March 31, 2019 and December 31, 2018:

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

(a) Includes swaps and physical and financial contracts.

	December 31, 2018 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	—	$	2,456	Discounted cash flows	Electricity forward price (per MWh)	$17.88 - $37.03	$	26.10
Natural Gas:
Forward Contracts (a)	2		5,760		Discounted cash flows	Natural gas forward price (per MMBtu)	$1.79 - $2.92	$	2.48
Total	$	2	$	8,216

(a)

Includes swaps and physical and financial contracts.

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 months ended March 31, 2019 and 2018 (dollars in thousands):

	Three Months Ended   March 31,
Commodity Contracts	2019			2018
Net derivative balance at beginning of period	$	(8,214	)	$	(18,256	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(1,579		)	(2,322		)
Settlements	518			782
Transfers into Level 3 from Level 2	(2		)	(2,445		)
Transfers from Level 3 into Level 2	3,665			2,487
Net derivative balance at end of period	$	(5,612	)	$	(19,754	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

XML

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2019 and December 31, 2018 (dollars in thousands):  

	March 31, 2019
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
Equity securities	$	458,776	$	11,471	$	470,247		$	273,817	$	(4	)
Available for sale-fixed income securities	457,903		225,173		683,076		(a)	15,306		(2,250		)
Other	2,630		1,563		4,193		(b)	—		—
Total	$	919,309	$	238,207	$	1,157,516		$	289,123	$	(2,254	)

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

(b) Represents net pending securities sales and purchases.

	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		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 months ended March 31, 2019 and 2018 (dollars in thousands):

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

(a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds.

Fair value of fixed income securities, summarized by contractual maturities

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

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

(a)

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

XML

Changes in Accumulated Other Comprehensive Loss (Tables)

3 Months Ended

Mar. 31, 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 months ended March 31, 2019 and 2018 (dollars in thousands):

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2018	$	(45,997	)		$	(1,711	)		$	(47,708	)
Amounts reclassified from accumulated other comprehensive loss	879			(a)	328			(b)	1,207
Balance March 31, 2019	$	(45,118	)		$	(1,383	)		$	(46,501	)
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	900			(a)	409			(b)	1,309
Reclassification of income tax effect related to tax reform	(7,954		)	(c)	(598		)	(c)	(8,552		)
Balance March 31, 2018	$	(49,494	)		$	(2,847	)		$	(52,341	)

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

(c)

In 2018, the company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2019 and 2018 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2018	$	(25,396	)		$	(1,711	)		$	(27,107	)
Amounts reclassified from accumulated other comprehensive loss	752			(a)	328			(b)	1,080
Balance March 31, 2019	$	(24,644	)		$	(1,383	)		$	(26,027	)
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)
OCI (loss) before reclassifications	—				(96		)		(96		)
Amounts reclassified from accumulated other comprehensive loss	857			(a)	409			(b)	1,266
Reclassification of income tax effect related to tax reform	(4,440		)	(c)	(598		)	(c)	(5,038		)
Balance March 31, 2018	$	(28,004	)		$	(2,847	)		$	(30,851	)

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

(b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

(c)

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

XML

Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Lease cost

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

	March 31, 2019
Weighted average remaining lease term	8 years
Weighted average discount rate	3.86		%
	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	3,087

The following table provides information related to our lease costs for the three months ended March 31, 2019 (dollars in thousands):

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

Schedule of future minimum payments

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

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

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

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

XML

Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash paid during the period for:
Income taxes, net of refunds	$ 1	$ 0
Interest, net of amounts capitalized	63,764	56,026
Significant non-cash investing and financing activities:
Accrued capital expenditures	95,879	86,991
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	2,293	0
APS
Cash paid during the period for:
Income taxes, net of refunds	0	0
Interest, net of amounts capitalized	61,387	54,873
Significant non-cash investing and financing activities:
Accrued capital expenditures	95,879	86,944
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	$ 2,293	$ 0

XML

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Operating revenues	$ 740,530	$ 692,714
Regulatory cost recovery revenue	20,000	10,000
Electric Service | Retail residential electric service
Disaggregation of Revenue [Line Items]
Operating revenues	351,566	316,675
Electric Service | Retail non-residential electric service
Disaggregation of Revenue [Line Items]
Operating revenues	332,668	343,189
Electric Service | Wholesale energy sales
Disaggregation of Revenue [Line Items]
Operating revenues	36,452	12,089
Transmission Services For Others
Disaggregation of Revenue [Line Items]
Operating revenues	15,249	14,845
Other sources
Disaggregation of Revenue [Line Items]
Operating revenues	4,595	5,916
Electric and Transmission Service
Disaggregation of Revenue [Line Items]
Operating revenues	$ 721,000	$ 683,000

XML

Long-Term Debt and Liquidity Matters - Narrative (Details)			3 Months Ended
	Mar. 01, 2019 USD ($)	Feb. 26, 2019 USD ($)	Mar. 31, 2019 USD ($) Facility	Feb. 28, 2019 USD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2018 USD ($)
Long-Term Debt and Liquidity Matters
Shot-term debt			$ 244,050,000		$ 76,400,000
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing June 2019
Long-Term Debt and Liquidity Matters
Debt instrument, term			364 days
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)						$ 150,000,000
Shot-term debt			$ 49,000,000
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 | 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			38,000,000
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
Long-Term Debt and Liquidity Matters
Shot-term debt			157,500,000		$ 0
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 | 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 | Term Loan Facility
Long-Term Debt and Liquidity Matters
Extinguishment of debt	$ 500,000,000
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			$ 158,000,000
LIBOR | Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing June 2019
Long-Term Debt and Liquidity Matters
Debt instrument, basis spread on variable rate			0.70%
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	Mar. 31, 2019	Dec. 31, 2018
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 5,136,108	$ 5,138,232
Fair Value	5,388,892	5,233,563
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	448,953	448,796
Fair Value	446,835	443,955
APS
Estimated fair value of long-term debt, including current maturities
Carrying Amount	4,687,155	4,689,436
Fair Value	$ 4,942,057	$ 4,789,608

XML

Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS	Apr. 22, 2019 USD ($)	Jan. 03, 2018 Customer	Nov. 13, 2017 USD ($)	Mar. 27, 2017 USD ($) $ / kWh	Mar. 26, 2017 $ / kWh	Mar. 31, 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, environmental surcharge cap rate (in dollars per kWh) | $ / kWh				0.00050	0.00016
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
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Public utilities, rate matters, demand side management adjustor charge	$ 5,000,000

XML

Regulatory Matters - Cost Recovery Mechanism and Net Metering (Details)																		3 Months Ended		12 Months Ended
	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	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) $ / kWh	Dec. 31, 2012 $ / kWh	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																		$ (16,709,000)	$ 18,950,000
Amounts charged to customers																		(12,872,000)	(20,002,000)
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																		(16,709,000)	18,950,000
Amounts charged to customers																		$ (12,872,000)	(20,002,000)
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
Gross-up for revenue requirement of rate regulation				$ 86,500,000						$ 119,100,000
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
Deferred fuel and purchased power costs — current period																		(16,709,000)	18,950,000
Amounts charged to customers																		(12,872,000)	(20,002,000)
Ending balance																		7,583,000	$ 74,585,000	$ 75,637,000
PSA rate (in dollars per kWh) | $ / kWh			0.001658						0.004555			0.000555		(0.001348)
Forward component of increase in PSA (in dollars per kWh) | $ / kWh			0.000536						0.002009			0.000876		(0.001027)
Historical 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					$ (22,700,000)								$ 35,100,000
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS
Change in regulatory asset
PSA rate for prior year (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 | APS
Change in regulatory asset
Gross-up for revenue requirement of rate regulation	$ 34,500,000
Deferred taxes amortization, period	28 years 6 months

XML

Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions			1 Months Ended		3 Months Ended
	Dec. 23, 2014	Dec. 30, 2013	Sep. 30, 2018	Apr. 30, 2018	Mar. 31, 2019	Jun. 30, 2016	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					$ 46.0
Regulatory noncurrent asset amortization period					10 years
Retired power plant costs
Business Acquisition [Line Items]
Net book value					$ 85.0
Navajo Plant
Business Acquisition [Line Items]
Net book value					$ 85.0
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	Mar. 31, 2019	Dec. 31, 2018
Detail of regulatory assets
Regulatory assets, current	$ 135,225	$ 166,902
Regulatory assets, non-current	1,321,507	1,342,941
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	723,307	733,351
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	28,182	28,182
Regulatory assets, non-current	160,167	167,164
Income taxes — allowance for funds used during construction (AFUDC) equity
Detail of regulatory assets
Regulatory assets, current	6,457	6,457
Regulatory assets, non-current	151,541	151,467
Deferred fuel and purchased power — mark-to-market (Note 7)
Detail of regulatory assets
Regulatory assets, current	29,340	31,728
Regulatory assets, non-current	14,360	23,768
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	7,583	37,164
Regulatory assets, non-current	0	0
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	8,077	8,077
Regulatory assets, non-current	38,209	40,228
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,079	1,079
Regulatory assets, non-current	25,475	25,522
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	29,698	32,435
Regulatory assets, non-current	0	0
Palo Verde VIEs (Note 6)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	20,170	20,015
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	37,581	36,523
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	8,569	8,569
Regulatory assets, non-current	64,214	66,356
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,637	1,637
Regulatory assets, non-current	13,259	13,668
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,235	1,235
Regulatory assets, non-current	6,122	6,176
TCA balancing account
Detail of regulatory assets
Regulatory assets, current	306	3,860
Regulatory assets, non-current	0	772
AG-1 deferral
Detail of regulatory assets
Regulatory assets, current	2,654	2,654
Regulatory assets, non-current	5,155	5,819
Mead-Phoenix transmission line CIAC
Detail of regulatory assets
Regulatory assets, current	332	332
Regulatory assets, non-current	9,961	10,044
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	1,546	1,546
Regulatory assets, non-current	17,392	15,607
SCR deferral
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	30,581	23,276
Tax expense adjustor mechanism
Detail of regulatory assets
Regulatory assets, current	5,451	0
Regulatory assets, non-current	0	0
Other
Detail of regulatory assets
Regulatory assets, current	3,079	1,947
Regulatory assets, non-current	$ 4,013	$ 3,185

XML

Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Detail of regulatory liabilities
Regulatory liabilities, current	$ 260,404	$ 165,876
Regulatory liabilities, non-current	2,272,082	2,325,976
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	337,844	278,585
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	50,701	39,866
Regulatory liabilities, non-current	156,578	177,533
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	37,864	37,864
Regulatory liabilities, non-current	116,478	125,903
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	2,164	2,164
Regulatory liabilities, non-current	51,027	51,120
Income taxes — change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	2,764	2,769
Regulatory liabilities, non-current	69,954	70,069
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	7,190	6,503
Regulatory liabilities, non-current	54,866	57,002
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	47,943	44,966
Regulatory liabilities, non-current	0	20
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	1,581	14,604
Regulatory liabilities, non-current	24,146	4,123
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	6,657	1,278
Regulatory liabilities, non-current	11,637	17,228
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	3,923	4,423
Regulatory liabilities, non-current	5,975	6,581
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	1,858	1,858
Regulatory liabilities, non-current	17,690	17,871
Tax expense adjustor mechanism
Detail of regulatory liabilities
Regulatory liabilities, current	14	3,237
Regulatory liabilities, non-current	0	0
Other
Detail of regulatory liabilities
Regulatory liabilities, current	42	42
Regulatory liabilities, non-current	4,253	3,541
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
Detail of regulatory liabilities
Regulatory liabilities, current	91,401	0
Regulatory liabilities, non-current	1,178,216	1,272,709
United States Federal Energy Regulatory Commission | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
Detail of regulatory liabilities
Regulatory liabilities, current	6,302	6,302
Regulatory liabilities, non-current	$ 243,418	$ 243,691

XML

Retirement Plans and Other Postretirement Benefits - Narrative (Details)	3 Months Ended
	Mar. 31, 2019 USD ($)
Pension Benefits
Contributions
Voluntary employer contributions to pension plan	$ 90,000,000
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
	Mar. 31, 2019	Mar. 31, 2018
Amortization of:
Portion of cost (credit) charged to expense	$ (5,114)	$ (12,859)
Pension Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	12,543	14,213
Interest cost on benefit obligation	34,352	31,007
Expected return on plan assets	(42,893)	(45,667)
Amortization of:
Prior service cost (credit)	0	0
Net actuarial loss	11,239	7,782
Net periodic benefit cost (credit)	15,241	7,335
Portion of cost (credit) charged to expense	8,244	2,242
Other Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	4,714	5,105
Interest cost on benefit obligation	7,526	7,101
Expected return on plan assets	(9,603)	(10,520)
Amortization of:
Prior service cost (credit)	(9,455)	(9,461)
Net actuarial loss	0	0
Net periodic benefit cost (credit)	(6,818)	(7,775)
Portion of cost (credit) charged to expense	$ (4,817)	$ (5,605)

XML

Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details)	3 Months Ended
	Mar. 31, 2019 USD ($) power_plant Lease	Mar. 31, 2018 USD ($)	Dec. 31, 1986 Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,873,000	$ 4,873,000
APS
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts	3		3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,873,000	4,873,000
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
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	Mar. 31, 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	$ 104,808	$ 105,775
Equity — Noncontrolling interests	130,663	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	104,808	105,775
Equity — Noncontrolling interests	130,663	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	104,808	105,775
Equity — Noncontrolling interests	$ 130,663	$ 125,790

XML

Derivative Accounting - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Commodity Contracts
Derivative Accounting
Additional collateral to counterparties for energy related non-derivative instrument contracts	$ 102
Commodity Contracts | Designated as Hedging Instruments
Derivative Accounting
Estimated loss before income taxes to be reclassified from accumulated other comprehensive income	$ 1
APS
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%

XML

Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts MWh in Thousands, MMcf in Thousands	Mar. 31, 2019 MWh MMcf	Dec. 31, 2018 MWh MMcf
Outstanding gross notional amount of derivatives
Power | MWh	1,146	250
Gas | MMcf	233	218

XML

Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 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
Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(436,000)	(491,000)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income	8,170,000	(35,308,000)
Not Designated as Hedging Instruments | Operating revenues
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income	0	(1,219,000)
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income	$ 8,170,000	$ (34,089,000)

XML

Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($)	Mar. 31, 2019	Dec. 31, 2018
Assets
Gross Recognized Derivatives	$ 898,000	$ 1,113,000
Liabilities
Amount Reported on Balance Sheets	(48,133,000)	(60,037,000)
Current assets
Assets
Other	38,000
Commodity Contracts
Assets
Gross Recognized Derivatives	4,674,000	3,142,000
Amounts Offset	(3,738,000)	(2,185,000)
Net Recognized Derivatives	936,000	957,000
Other	(38,000)	156,000
Amount Reported on Balance Sheets	898,000	1,113,000
Liabilities
Gross Recognized Derivatives	(50,212,000)	(60,912,000)
Amounts Offset	3,738,000	2,185,000
Net Recognized Derivatives	(46,474,000)	(58,727,000)
Other	(1,659,000)	(1,310,000)
Amount Reported on Balance Sheets	(48,133,000)	(60,037,000)
Assets and Liabilities
Gross Recognized Derivatives	(45,538,000)	(57,770,000)
Amounts Offset	0	0
Net Recognized Derivatives	(45,538,000)	(57,770,000)
Other	(1,697,000)	(1,154,000)
Amount Reported on Balance Sheets	(47,235,000)	(58,924,000)
Commodity Contracts | Current assets
Assets
Gross Recognized Derivatives	3,658,000	3,106,000
Amounts Offset	(2,857,000)	(2,149,000)
Net Recognized Derivatives	801,000	957,000
Other	(38,000)	156,000
Amount Reported on Balance Sheets	763,000	1,113,000
Commodity Contracts | Investments and other assets
Assets
Gross Recognized Derivatives	1,016,000	36,000
Amounts Offset	(881,000)	(36,000)
Net Recognized Derivatives	135,000	0
Other	0	0
Amount Reported on Balance Sheets	135,000	0
Commodity Contracts | Current liabilities
Liabilities
Gross Recognized Derivatives	(34,487,000)	(36,345,000)
Amounts Offset	2,857,000	2,149,000
Net Recognized Derivatives	(31,630,000)	(34,196,000)
Other	(1,659,000)	(1,310,000)
Amount Reported on Balance Sheets	(33,289,000)	(35,506,000)
Commodity Contracts | Deferred credits and other
Liabilities
Gross Recognized Derivatives	(15,725,000)	(24,567,000)
Amounts Offset	881,000	36,000
Net Recognized Derivatives	(14,844,000)	(24,531,000)
Other	0	0
Amount Reported on Balance Sheets	$ (14,844,000)	$ (24,531,000)

XML

Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Mar. 31, 2019 USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	$ 50,212
Cash collateral posted	0
Additional cash collateral in the event credit-risk-related contingent features were fully triggered	$ 47,874

XML

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)		2 Months Ended	3 Months Ended
	Aug. 18, 2014 USD ($)	Apr. 10, 2019 USD ($)	Mar. 31, 2019 USD ($) time_period power_plant claim	Dec. 31, 1986 Trust
Commitments and Contingencies
Purchase obligation, increase			$ 180,000,000
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount	$ 57,400,000		10,200,000
Payments for legal settlements			74,200,000
APS
Commitments and Contingencies
Maximum insurance against public liability per occurrence for a nuclear incident (up to)			14,100,000,000
Maximum available nuclear liability insurance (up to)			450,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program			13,600,000,000
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			24,800,000
Collateral assurance provided based on rating triggers			$ 71,200,000
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	$ 16,700,000		$ 3,000,000.0
Number of claims submitted | claim			4
Number of settlement agreement time periods | time_period			4
Payments for legal settlements			$ 21,600,000
Subsequent Event | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount		$ 10,200,000
Subsequent Event | 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

XML

Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - APS - Contaminated groundwater wells $ in Millions				3 Months Ended
	Apr. 05, 2018 plaintiff	Dec. 16, 2016 plaintiff	Aug. 06, 2013 Defendant	Mar. 31, 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			3 Months Ended	12 Months Ended
	Jul. 03, 2018	Jul. 06, 2016	Mar. 31, 2019	Dec. 31, 2017	Dec. 31, 2018
APS | Letters of Credit Expiring in 2018, 2019
Financial Assurances
Outstanding letters of credit			$ 0.2
APS | Letters of Credit Expiring in 2019
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
	Mar. 31, 2019	Mar. 31, 2018
Other income:
Interest income	$ 2,302	$ 1,891
Debt return on Four Corners SCR (Note 4)	4,844	2,092
Miscellaneous	23	2
Total other income	7,169	3,985
Other expense:
Non-operating costs	(2,704)	(1,646)
Investment losses — net	(238)	(176)
Miscellaneous	(1,416)	(1,407)
Total other expense	(4,358)	(3,229)
APS
Other income:
Interest income	1,550	1,678
Debt return on Four Corners SCR (Note 4)	4,844	2,092
Miscellaneous	22	2
Total other income	6,416	3,772
Other expense:
Non-operating costs	(2,467)	(1,539)
Miscellaneous	(1,411)	(1,406)
Total other expense	$ (3,878)	$ (2,945)

XML

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 17,918	$ 17,918	$ 3,221
Weighted average common shares outstanding - basic (in shares)	112,337		112,017
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units (in shares)	398		476
Weighted average common shares outstanding — diluted (in shares)	112,735		112,493
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.16		$ 0.03
Net income attributable to common shareholders - diluted (in dollars per share)	$ 0.16		$ 0.03

XML

Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Assets
Cash equivalents		$ 1,200
Commodity contracts, assets	$ 898	1,113
Commodity contracts, liabilities	(3,776)	(2,029)
Nuclear decommissioning trust	919,309	851,134
Nuclear decommissioning trust, other	453,859	398,953
Other special use funds	238,207	236,101
Other special use funds, other	1,563	593
Total assets	1,158,414	1,089,548
Total assets, other	451,646	397,517
Liabilities
Total, other	2,079	875
Amount reported on balance sheet	(48,133)	(60,037)
Equity securities
Assets
Nuclear decommissioning trust	10,177	7,351
Nuclear decommissioning trust, other	2,630	2,148
Other special use funds	13,034	45,723
Other special use funds, other	1,563	593
U.S. commingled equity funds
Assets
Nuclear decommissioning trust	451,229	396,805
U.S. Treasury debt
Assets
Nuclear decommissioning trust	155,231	148,173
Other special use funds	208,945	173,310
Corporate debt
Assets
Nuclear decommissioning trust	108,509	96,656
Mortgage-backed debt securities
Assets
Nuclear decommissioning trust	113,002	113,115
Municipal bonds
Assets
Nuclear decommissioning trust	70,375	79,073
Other special use funds	16,228	17,068
Other fixed income
Assets
Nuclear decommissioning trust	10,786	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	162,778	153,376
Other special use funds	220,416	218,440
Total assets	383,194	373,016
Liabilities
Gross derivative liability	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities
Assets
Nuclear decommissioning trust	7,547	5,203
Other special use funds	11,471	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	155,231	148,173
Other special use funds	208,945	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 debt 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	3,598	3,140
Nuclear decommissioning trust	302,672	298,805
Other special use funds	16,228	17,068
Total assets	322,498	319,013
Liabilities
Gross derivative liability	(43,524)	(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	108,509	96,656
Significant Other Observable Inputs (Level 2) | Mortgage-backed debt securities
Assets
Nuclear decommissioning trust	113,002	113,115
Significant Other Observable Inputs (Level 2) | Municipal bonds
Assets
Nuclear decommissioning trust	70,375	79,073
Other special use funds	16,228	17,068
Significant Other Observable Inputs (Level 2) | Other fixed income
Assets
Nuclear decommissioning trust	10,786	9,961
Significant Unobservable Inputs (Level 3)
Assets
Cash equivalents		0
Commodity contracts, assets	1,076	2
Nuclear decommissioning trust	0	0
Other special use funds	0	0
Total assets	1,076	2
Liabilities
Gross derivative liability	(6,688)	(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 debt 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	$ 451,229	$ 396,805

XML

Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) - Forward Price $ in Thousands	Mar. 31, 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 | $	$ 1,076	$ 2
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $	6,688	$ 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 | $	382	$ 0
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $	$ 5,206	$ 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	50.50	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	19.77
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	67.40
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 | $	$ 694	$ 2
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $	$ 1,482	$ 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	2.46	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	1.90
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	2.97

XML

Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net derivative balance at beginning of period	$ (8,214)	$ (18,256)
Deferred as a regulatory asset or liability	(1,579)	(2,322)
Settlements	518	782
Transfers into Level 3 from Level 2	(2)	(2,445)
Transfers from Level 3 into Level 2	3,665	2,487
Net derivative balance at end of period	(5,612)	(19,754)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0

XML

Fair Value Measurements - Financial Instruments Not Carried at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Stated interest rate for notes receivable	3.90%
Note receivable, net book value	$ 57	$ 61

XML

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Nuclear decommissioning trust fund assets
Fair Value	$ 1,157,516		$ 1,087,235
Total Unrealized Gains	289,123		230,781
Total Unrealized Losses	(2,254)		(7,237)
Amortized cost	670,000		635,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	1,103	$ 815
Realized losses	(1,405)	(2,047)
Proceeds from the sale of securities	179,048	133,011
Equity securities
Nuclear decommissioning trust fund assets
Fair Value	470,247
Total Unrealized Gains	273,817
Total Unrealized Losses	(4)
Fair Value			447,138
Total Unrealized Gains			222,147
Total Unrealized Losses			(459)
Available for sale-fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	683,076		637,356
Total Unrealized Gains	15,306		8,634
Total Unrealized Losses	(2,250)		(6,778)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	86,284
1 year – 5 years	275,098
5 years – 10 years	123,923
Greater than 10 years	197,771
Total	683,076
Other
Nuclear decommissioning trust fund assets
Fair Value	4,193		2,741
Total Unrealized Gains	0		0
Total Unrealized Losses	0		0
Nuclear Decommissioning Trusts
Nuclear decommissioning trust fund assets
Fair Value	919,309		851,134
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	1,103	814
Realized losses	(1,405)	(2,047)
Proceeds from the sale of securities	122,593	130,456
Nuclear Decommissioning Trusts | Equity securities
Nuclear decommissioning trust fund assets
Fair Value	458,776
Fair Value			402,008
Nuclear Decommissioning Trusts | Available for sale-fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	457,903
Fair Value			446,978
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	26,100
1 year – 5 years	120,511
5 years – 10 years	120,342
Greater than 10 years	190,950
Total	457,903
Nuclear Decommissioning Trusts | Other
Nuclear decommissioning trust fund assets
Fair Value	2,630		2,148
Other Special Use Funds
Nuclear decommissioning trust fund assets
Fair Value	238,207		236,101
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	0	1
Realized losses	0	0
Proceeds from the sale of securities	56,455	$ 2,555
Other Special Use Funds | Equity securities
Nuclear decommissioning trust fund assets
Fair Value	11,471
Fair Value			45,130
Other Special Use Funds | Available for sale-fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	225,173
Fair Value			190,378
Other Special Use Funds | Other
Nuclear decommissioning trust fund assets
Fair Value	1,563		$ 593
Coal Reclamation Escrow Accounts | Available for sale-fixed income securities
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	20,085
1 year – 5 years	15,960
5 years – 10 years	3,581
Greater than 10 years	6,821
Total	46,447
Active Union Medical Trust | Available for sale-fixed income securities
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	40,099
1 year – 5 years	138,627
5 years – 10 years	0
Greater than 10 years	0
Total	$ 178,726

XML

Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		$ 5,348,705	$ 5,135,730
OCI (loss) before reclassifications			(96)
Amounts reclassified from accumulated other comprehensive loss		1,207	1,309
Reclassification of income tax effect related to tax reform			(8,552)
Balance at end of period		5,381,725	5,153,671
Pension and Other Postretirement Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(45,997)	(42,440)
OCI (loss) before reclassifications			0
Amounts reclassified from accumulated other comprehensive loss		879	900
Reclassification of income tax effect related to tax reform			(7,954)
Balance at end of period		(45,118)	(49,494)
Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(1,711)	(2,562)
OCI (loss) before reclassifications			(96)
Amounts reclassified from accumulated other comprehensive loss		328	409
Reclassification of income tax effect related to tax reform			(598)
Balance at end of period		(1,383)	(2,847)
Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(47,708)	(45,002)
Reclassification of income tax effect related to tax reform	[1]		(8,552)
Balance at end of period		(46,501)	(52,341)
APS
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		5,786,797	5,385,869
OCI (loss) before reclassifications			(96)
Amounts reclassified from accumulated other comprehensive loss		1,080	1,266
Reclassification of income tax effect related to tax reform			(5,038)
Balance at end of period		5,821,026	5,401,512
APS | Pension and Other Postretirement Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(25,396)	(24,421)
OCI (loss) before reclassifications			0
Amounts reclassified from accumulated other comprehensive loss		752	857
Reclassification of income tax effect related to tax reform			(4,440)
Balance at end of period		(24,644)	(28,004)
APS | Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(1,711)	(2,562)
OCI (loss) before reclassifications			(96)
Amounts reclassified from accumulated other comprehensive loss		328	409
Reclassification of income tax effect related to tax reform			(598)
Balance at end of period		(1,383)	(2,847)
APS | Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period		(27,107)	(26,983)
Reclassification of income tax effect related to tax reform	[1]		(5,038)
Balance at end of period		$ (26,027)	$ (30,851)

[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.

XML

Income Taxes (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Income Tax Disclosure [Abstract]
Reduction in net deferred income tax liabilities	$ 1,140

XML

Leases - Additional information (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating Leased Assets [Line Items]
Operating lease right-of-use assets (Note 16)	$ 193,897	$ 194,000	$ 0
Operating lease, liability	119,139	119,000
Other	(39,257)		(129,312)
Other current liabilities	$ (114,361)		$ (184,229)
Accounting Standards Update 2016-02
Operating Leased Assets [Line Items]
Other		85,000
Other current liabilities		$ 10,000

XML

Leases - Lease costs (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Operating Leased Assets [Line Items]
Operating lease cost	$ 4,348
Variable lease cost	17,290
Total lease cost	21,638
Purchased Power Lease Contracts [Member]
Operating Leased Assets [Line Items]
Operating lease cost	0
Variable lease cost	17,290
Total lease cost	17,290
Land, Property and Equipment Leases [Member]
Operating Leased Assets [Line Items]
Operating lease cost	4,348
Variable lease cost	0
Total lease cost	$ 4,348

XML

Leases - Maturity of our operating lease liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
2019 (remainder of fiscal year)	$ 65,038
2019			$ 68,246
2020	12,424		12,428
2021	9,585		9,478
2022	6,621		6,513
2023	5,496		5,359
Thereafter	41,618		42,236
Total lease commitments	140,782		144,260
Less imputed interest	21,643
Total lease liabilities	119,139	$ 119,000
Purchased Power Lease Contracts [Member]
Lessee, Lease, Description [Line Items]
2019 (remainder of fiscal year)	54,499
2019			54,499
2020	0		0
2021	0		0
2022	0		0
2023	0		0
Thereafter	0		0
Total lease commitments	54,499		54,499
Less imputed interest	814
Total lease liabilities	53,685
Land, Property and Equipment Leases [Member]
Lessee, Lease, Description [Line Items]
2019 (remainder of fiscal year)	10,539
2019			13,747
2020	12,424		12,428
2021	9,585		9,478
2022	6,621		6,513
2023	5,496		5,359
Thereafter	41,618		42,236
Total lease commitments	86,283		$ 89,761
Less imputed interest	20,829
Total lease liabilities	$ 65,454

XML

Leases - Other additional information related to operating lease liabilities (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Weighted average remaining lease term	8 years
Weighted average discount rate	3.86%
Cash paid for amounts included in the measurement of lease liabilities (dollars in thousands): Operating cash flows	$ 3,087