Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND

FINANCIAL STATEMENT SCHEDULES



	Page

Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)	79
Report of Independent Registered Public Accounting Firm	80
Pinnacle West Consolidated Statements of Income for 2016, 2015 and 2014	82
Pinnacle West Consolidated Statements of Comprehensive Income for 2016, 2015, and 2014	83
Pinnacle West Consolidated Balance Sheets as of December 31, 2016 and 2015	84
Pinnacle West Consolidated Statements of Cash Flows for 2016, 2015 and 2014	86
Pinnacle West Consolidated Statements of Changes in Equity for 2016, 2015 and 2014	87

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)	88
Report of Independent Registered Public Accounting Firm	89
APS Consolidated Statements of Income for 2016, 2015 and 2014	91
APS Consolidated Statements of Comprehensive Income for 2016, 2015 and 2014	92
APS Consolidated Balance Sheets as of December 31, 2016 and 2015	93
APS Consolidated Statements of Cash Flows for 2016, 2015 and 2014	95
APS Consolidated Statements of Changes in Equity for 2016, 2015 and 2014	96

Combined Notes to Consolidated Financial Statements	97
Note 1. Summary of Significant Accounting Policies	97
Note 2. New Accounting Standards	104
Note 3. Regulatory Matters	106
Note 4. Income Taxes	118
Note 5. Lines of Credit and Short-Term Borrowings	122
Note 6. Long-Term Debt and Liquidity Matters	123
Note 7. Retirement Plans and Other Postretirement Benefits	126
Note 8. Leases	134
Note 9. Jointly-Owned Facilities	136
Note 10. Commitments and Contingencies	137
Note 11. Asset Retirement Obligations	146
Note 12. Selected Quarterly Financial Data (Unaudited)	148
Note 13. Fair Value Measurements	149
Note 14. Earnings Per Share	157
Note 15. Stock-Based Compensation	157
Note 16. Derivative Accounting	160
Note 17. Other Income and Other Expense	165
Note 18. Palo Verde Sale Leaseback Variable Interest Entities	166
Note 19. Nuclear Decommissioning Trusts	167
Note 20. Changes in Accumulated Other Comprehensive Loss	168

See Note 12 for the selected quarterly financial data (unaudited) required to be presented in this Item.

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2016. The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

February 24, 2017

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Pinnacle West Capital Corporation

Phoenix, Arizona

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become

inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.



/s/ Deloitte & Touche LLP

Phoenix, Arizona
February 24, 2017

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

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



	Year Ended December 31,
	2016			2015			2014

OPERATING REVENUES	$	3,498,682		$	3,495,443		$	3,491,632
OPERATING EXPENSES
Fuel and purchased power	1,075,510			1,101,298			1,179,829
Operations and maintenance	911,319			868,377			908,025
Depreciation and amortization	485,829			494,422			417,358
Taxes other than income taxes	166,499			171,812			172,295
Other expenses	3,541			4,932			2,883
Total	2,642,698			2,640,841			2,680,390
OPERATING INCOME	855,984			854,602			811,242
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	42,140			35,215			30,790
Other income (Note 17)	901			621			9,608
Other expense (Note 17)	(15,337		)	(17,823		)	(21,746		)
Total	27,704			18,013			18,652
INTEREST EXPENSE
Interest charges	205,720			194,964			200,950
Allowance for borrowed funds used during construction (Note 1)	(19,970		)	(16,259		)	(15,457		)
Total	185,750			178,705			185,493
INCOME BEFORE INCOME TAXES	697,938			693,910			644,401
INCOME TAXES (Note 4)	236,411			237,720			220,705
NET INCOME	461,527			456,190			423,696
Less: Net income attributable to noncontrolling interests (Note 18)	19,493			18,933			26,101
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	442,034		$	437,257		$	397,595

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	111,409			111,026			110,626
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,046			111,552			111,178

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	3.97		$	3.94		$	3.59
Net income attributable to common shareholders — diluted	$	3.95		$	3.92		$	3.58

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)



	Year Ended December 31,
	2016			2015			2014

NET INCOME	$	461,527		$	456,190		$	423,696

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax (expense) of $(585), $(342), and $(438) (Note 16)	(538		)	(957		)	(810		)
Reclassification of net realized loss, net of tax benefit of $985, $1,801 and $7,932 (Note 16)	2,941			4,187			13,483
Pension and other postretirement benefits activity, net of tax benefit (expense) of $633, $(13,302), and $1,307 (Note 7)	(1,477		)	20,163			(2,761		)
Total other comprehensive income	926			23,393			9,912

COMPREHENSIVE INCOME	462,453			479,583			433,608
Less: Comprehensive income attributable to noncontrolling interests	19,493			18,933			26,101

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	442,960		$	460,650		$	407,507

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2016			2015
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	8,881		$	39,488
Customer and other receivables	250,491			274,691
Accrued unbilled revenues	107,949			96,240
Allowance for doubtful accounts	(3,037		)	(3,125		)
Materials and supplies (at average cost)	253,979			234,234
Fossil fuel (at average cost)	28,608			45,697
Income tax receivable (Note 4)	3,751			589
Assets from risk management activities (Note 16)	19,694			15,905
Deferred fuel and purchased power regulatory asset (Note 3)	12,465			—
Other regulatory assets (Note 3)	94,410			149,555
Other current assets	45,028			37,242
Total current assets	822,219			890,516
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	1			12,106
Nuclear decommissioning trust (Notes 13 and 19)	779,586			735,196
Other assets	69,063			52,518
Total investments and other assets	848,650			799,820
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	17,341,888			16,222,232
Accumulated depreciation and amortization	(5,970,100		)	(5,594,094		)
Net	11,371,788			10,628,138
Construction work in progress	1,019,947			816,307
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)	113,515			117,385
Intangible assets, net of accumulated amortization of $603,637 and $546,038	90,022			123,975
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228	119,004			123,139
Total property, plant and equipment	12,714,276			11,808,944
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,313,428			1,214,146
Assets for other postretirement benefits (Note 7)	166,206			185,997
Other	139,474			128,835
Total deferred debits	1,619,108			1,528,978
TOTAL ASSETS	$	16,004,253		$	15,028,258

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2016			2015
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	264,631		$	297,480
Accrued taxes (Note 4)	138,964			138,600
Accrued interest	52,835			56,305
Common dividends payable	72,926			69,363
Short-term borrowings (Note 5)	177,200			—
Current maturities of long-term debt (Note 6)	125,000			357,580
Customer deposits	82,520			73,073
Liabilities from risk management activities (Note 16)	25,836			77,716
Liabilities for asset retirements (Note 11)	9,135			28,573
Deferred fuel and purchased power regulatory liability (Note 3)	—			9,688
Other regulatory liabilities (Note 3)	99,899			136,078
Other current liabilities	244,000			197,861
Total current liabilities	1,292,946			1,442,317
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	4,021,785			3,462,391
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	2,945,232			2,723,425
Regulatory liabilities (Notes 1, 3, 4 and 7)	948,916			994,152
Liabilities for asset retirements (Note 11)	615,340			415,003
Liabilities for pension benefits (Note 7)	509,310			480,998
Liabilities from risk management activities (Note 16)	47,238			89,973
Customer advances	88,672			115,609
Coal mine reclamation	221,910			201,984
Deferred investment tax credit	210,162			187,080
Unrecognized tax benefits (Note 4)	10,046			9,524
Other	156,784			186,345
Total deferred credits and other	5,753,610			5,404,093
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,392,053 and 111,095,402 issued at respective dates	2,596,030			2,541,668
Treasury stock at cost; 55,317 shares at end of 2016 and 115,030 shares at end of 2015	(4,133		)	(5,806		)
Total common stock	2,591,897			2,535,862
Retained earnings	2,255,547			2,092,803
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 7)	(39,070		)	(37,593		)
Derivative instruments (Note 16)	(4,752		)	(7,155		)
Total accumulated other comprehensive loss	(43,822		)	(44,748		)
Total shareholders’ equity	4,803,622			4,583,917
Noncontrolling interests (Note 18)	132,290			135,540
Total equity	4,935,912			4,719,457
TOTAL LIABILITIES AND EQUITY	$	16,004,253		$	15,028,258

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)



	Year Ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	461,527		$	456,190		$	423,696
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	565,011			571,664			496,487
Deferred fuel and purchased power	(60,303		)	14,997			(26,927		)
Deferred fuel and purchased power amortization	38,152			1,617			40,757
Allowance for equity funds used during construction	(42,140		)	(35,215		)	(30,790		)
Deferred income taxes	206,870			236,819			159,023
Deferred investment tax credit	23,082			8,473			26,246
Change in derivative instruments fair value	(403		)	(381		)	339
Stock compensation	18,883			18,756			33,059
Changes in current assets and liabilities:
Customer and other receivables	(2,489		)	(22,219		)	(52,672		)
Accrued unbilled revenues	(11,709		)	4,293			(3,737		)
Materials, supplies and fossil fuel	(1,491		)	(23,945		)	3,724
Income tax receivable	(3,162		)	2,509			132,419
Other current assets	(23,324		)	3,145			4,384
Accounts payable	(66,917		)	(34,266		)	(353		)
Accrued taxes	447			(2,013		)	9,615
Other current liabilities	29,594			603			17,892
Change in margin and collateral accounts — assets	673			(324		)	(343		)
Change in margin and collateral accounts — liabilities	17,735			22,776			(24,975		)
Change in unrecognized tax benefits	1,628			(10,328		)	2,778
Change in long-term regulatory liabilities	14,682			(20,535		)	59,618
Change in other long-term assets	(60,163		)	2,426			(56,561		)
Change in other long-term liabilities	(82,793		)	(100,715		)	(114,052		)
Net cash flow provided by operating activities	1,023,390			1,094,327			1,099,627
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,275,472		)	(1,076,087		)	(910,634		)
Contributions in aid of construction	64,296			46,546			20,325
Allowance for borrowed funds used during construction	(19,970		)	(16,259		)	(15,457		)
Proceeds from nuclear decommissioning trust sales	633,410			478,813			356,195
Investment in nuclear decommissioning trust	(635,691		)	(496,062		)	(373,444		)
Other	(18,651		)	(3,184		)	347
Net cash flow used for investing activities	(1,252,078		)	(1,066,233		)	(922,668		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151			842,415			731,126
Repayment of long-term debt	(370,430		)	(415,570		)	(652,578		)
Short-term borrowings and payments — net	137,200			(147,400		)	(5,725		)
Short-term debt borrowings under revolving credit facility	40,000			—			—
Dividends paid on common stock	(274,229		)	(260,027		)	(246,671		)
Common stock equity issuance and purchases - net	(4,867		)	19,373			15,288
Distributions to noncontrolling interests	(22,744		)	(35,002		)	(20,482		)
Other	—			1			161
Net cash flow provided by (used for) financing activities	198,081			3,790			(178,881		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(30,607		)	31,884			(1,922		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	39,488			7,604			9,526
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	8,881		$	39,488		$	7,604

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands, except per share amounts)



	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
Balance, December 31, 2013	110,280,703	$	2,491,558	(98,944	)	$	(4,308	)	$	1,785,273		$	(78,053	)	$	145,990		$	4,340,460

Net income		—				—			397,595			—			26,101			423,696
Other comprehensive income		—				—			—			9,912			—			9,912
Dividends on common stock ($2.33 per share)		—				—			(256,803		)	—			—			(256,803		)
Issuance of common stock	369,059	21,412				—			—			—			—			21,412
Purchase of treasury stock (a)		—		(139,746	)	(7,893		)	—			—			—			(7,893		)
Reissuance of treasury stock for stock-based compensation and other		—		160,290		8,800			—			—			—			8,800
Net capital activities by noncontrolling interests		—				—			—			—			(20,482		)	(20,482		)
Balance, December 31, 2014	110,649,762	2,512,970		(78,400	)	(3,401		)	1,926,065			(68,141		)	151,609			4,519,102

Net income		—				—			437,257			—			18,933			456,190
Other comprehensive income		—				—			—			23,393			—			23,393
Dividends on common stock ($2.44 per share)		—				—			(270,519		)	—			—			(270,519		)
Issuance of common stock	445,640	28,698				—			—			—			—			28,698
Purchase of treasury stock (a)		—		(154,751	)	(10,136		)	—			—			—			(10,136		)
Reissuance of treasury stock for stock-based compensation and other		—		118,121		7,731			—			—			—			7,731
Net capital activities by noncontrolling interests		—				—			—			—			(35,002		)	(35,002		)
Balance, December 31, 2015	111,095,402	2,541,668		(115,030	)	(5,806		)	2,092,803			(44,748		)	135,540			4,719,457

Net income		—				—			442,034			—			19,493			461,527
Other comprehensive income		—				—			—			926			—			926
Dividends on common stock ($2.56 per share)		—				—			(284,765		)	—			—			(284,765		)
Issuance of common stock	296,651	13,982				—			—			—			—			13,982
Purchase of treasury stock (a)		—		(128,105	)	(9,087		)	—			—			—			(9,087		)
Reissuance of treasury stock for stock-based compensation and other		—		187,818		10,760			—			—			—			10,760
Stock compensation cumulative effect adjustments (See Note 2)		40,380				—			5,475			—			—			45,855
Net capital activities by noncontrolling interests		—				—			—			—			(22,743		)	(22,743		)
Balance, December 31, 2016	111,392,053	$	2,596,030	(55,317	)	$	(4,133	)	$	2,255,547		$	(43,822	)	$	132,290		$	4,935,912

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

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

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(ARIZONA PUBLIC SERVICE COMPANY)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for APS. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2016. The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.

February 24, 2017

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Arizona Public Service Company

Phoenix, Arizona

We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiary (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.

inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Arizona Public Service Company and subsidiary as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.



/s/ Deloitte & Touche LLP

Phoenix, Arizona
February 24, 2017

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)



	Year Ended December 31,
	2016			2015			2014

ELECTRIC OPERATING REVENUES	$	3,489,754		$	3,492,357		$	3,488,946

OPERATING EXPENSES
Fuel and purchased power	1,082,625			1,101,298			1,179,829
Operations and maintenance	879,108			853,135			882,442
Depreciation and amortization	484,909			494,298			417,264
Income taxes (Note 4)	259,353			260,143			245,036
Taxes other than income taxes	165,779			171,499			171,583
Total	2,871,774			2,880,373			2,896,154
OPERATING INCOME	617,980			611,984			592,792

OTHER INCOME (DEDUCTIONS)
Income taxes (Note 4)	13,511			14,302			7,676
Allowance for equity funds used during construction (Note 1)	42,140			35,215			30,790
Other income (Note 17)	8,607			2,834			11,295
Other expense (Note 17)	(17,514		)	(19,019		)	(13,403		)
Total	46,744			33,332			36,358

INTEREST EXPENSE
Interest on long-term debt	189,828			180,123			186,323
Interest on short-term borrowings	7,983			7,376			6,796
Debt discount, premium and expense	4,760			4,793			4,168
Allowance for borrowed funds used during construction (Note 1)	(19,481		)	(16,183		)	(15,457		)
Total	183,090			176,109			181,830

NET INCOME	481,634			469,207			447,320

Less: Net income attributable to noncontrolling interests (Note 18)	19,493			18,933			26,101

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	462,141		$	450,274		$	421,219

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)



	Year Ended December 31,
	2016			2015			2014

NET INCOME	$	481,634		$	469,207		$	447,320

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax (expense) of $(585), $(342), and $(438) (Note 16)	(538		)	(957		)	(809		)
Reclassification of net realized loss, net of tax benefit of $985, $1,801, and $7,932 (Note 16)	2,941			4,187			13,483
Pension and other postretirement benefits activity, net of tax (expense) benefit of $293, $(11,776), and $4,655 (Note 7)	(729		)	18,006			(7,635		)
Total other comprehensive income	1,674			21,236			5,039

COMPREHENSIVE INCOME	483,308			490,443			452,359
Less: Comprehensive income attributable to noncontrolling interests	19,493			18,933			26,101

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	463,815		$	471,510		$	426,258

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2016			2015
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	$	17,228,787		$	16,218,724
Accumulated depreciation and amortization	(5,881,941		)	(5,590,937		)
Net	11,346,846			10,627,787
Construction work in progress	989,497			812,845
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)	113,515			117,385
Intangible assets, net of accumulated amortization of $603,637 and $546,038	89,868			123,820
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228	119,004			123,139
Total property, plant and equipment	12,658,730			11,804,976
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 13 and 19)	779,586			735,196
Assets from risk management activities (Note 16)	1			12,106
Other assets	48,320			34,455
Total investments and other assets	827,907			781,757
CURRENT ASSETS
Cash and cash equivalents	8,840			22,056
Customer and other receivables	262,611			274,428
Accrued unbilled revenues	107,949			96,240
Allowance for doubtful accounts	(3,037		)	(3,125		)
Materials and supplies (at average cost)	252,777			234,234
Fossil fuel (at average cost)	28,608			45,697
Income tax receivable	11,174			—
Assets from risk management activities (Note 16)	19,694			15,905
Deferred fuel and purchased power regulatory asset (Note 3)	12,465			—
Other regulatory assets (Note 3)	94,410			149,555
Other current assets	41,849			35,765
Total current assets	837,340			870,755
DEFERRED DEBITS
Regulatory assets (Notes 1, 3, and 4)	1,313,428			1,214,146
Assets for other postretirement benefits (Note 7)	162,911			182,625
Other	130,859			127,923
Total deferred debits	1,607,198			1,524,694
TOTAL ASSETS	$	15,931,175		$	14,982,182

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2016			2015
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,421,696			2,379,696
Retained earnings	2,331,245			2,148,493
Accumulated other comprehensive (loss):
Pension and other postretirement benefits (Note 7)	(20,671		)	(19,942		)
Derivative instruments (Note 16)	(4,752		)	(7,155		)
Total accumulated other comprehensive loss	(25,423		)	(27,097		)
Total shareholder equity	4,905,680			4,679,254
Noncontrolling interests (Note 18)	132,290			135,540
Total equity	5,037,970			4,814,794
Long-term debt less current maturities (Note 6)	4,021,785			3,337,391
Total capitalization	9,059,755			8,152,185
CURRENT LIABILITIES
Short-term borrowings (Note 5)	135,500			—
Current maturities of long-term debt (Note 6)	—			357,580
Accounts payable	259,161			291,574
Accrued taxes (Note 4)	130,576			144,488
Accrued interest	52,525			56,003
Common dividends payable	72,900			69,400
Customer deposits	82,520			73,073
Liabilities from risk management activities (Note 16)	25,836			77,716
Liabilities for asset retirements (Note 11)	8,703			28,573
Deferred fuel and purchased power regulatory liability (Note 3)	—			9,688
Other regulatory liabilities (Note 3)	99,899			136,078
Other current liabilities	226,417			180,535
Total current liabilities	1,094,037			1,424,708
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	2,999,295			2,764,489
Regulatory liabilities (Notes 1, 3, and 4)	948,916			994,152
Liabilities for asset retirements (Note 11)	607,234			415,003
Liabilities for pension benefits (Note 7)	488,253			459,065
Liabilities from risk management activities (Note 16)	47,238			89,973
Customer advances	88,672			115,609
Coal mine reclamation	206,645			201,984
Deferred investment tax credit	210,162			187,080
Unrecognized tax benefits (Note 4)	37,408			35,251
Other	143,560			142,683
Total deferred credits and other	5,777,383			5,405,289
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	15,931,175		$	14,982,182

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)



	Year Ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	481,634		$	469,207		$	447,320
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	564,091			571,540			496,393
Deferred fuel and purchased power	(60,303		)	14,997			(26,927		)
Deferred fuel and purchased power amortization	38,152			1,617			40,757
Allowance for equity funds used during construction	(42,140		)	(35,215		)	(30,790		)
Deferred income taxes	221,167			223,069			155,401
Deferred investment tax credit	23,082			8,473			26,246
Change in derivative instruments fair value	(403		)	(381		)	339
Changes in current assets and liabilities:
Customer and other receivables	(1,601		)	(21,040		)	(52,466		)
Accrued unbilled revenues	(11,709		)	4,293			(3,737		)
Materials, supplies and fossil fuel	(1,454		)	(23,945		)	3,724
Income tax receivable	(14,567		)	—			135,179
Other current assets	(21,640		)	4,498			3,766
Accounts payable	(67,543		)	(34,891		)	(2,355		)
Accrued taxes	(13,912		)	13,378			8,650
Other current liabilities	5,097			(3,718		)	33,970
Change in margin and collateral accounts — assets	673			(324		)	(343		)
Change in margin and collateral accounts — liabilities	17,735			22,776			(24,975		)
Change in long-term regulatory liabilities	14,682			(20,535		)	59,618
Change in unrecognized tax benefits	1,628			(10,328		)	2,778
Change in other long-term assets	(45,866		)	(813		)	(62,739		)
Change in other long-term liabilities	(76,855		)	(82,628		)	(85,642		)
Net cash flow provided by operating activities	1,009,948			1,100,030			1,124,167
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,248,010		)	(1,072,053		)	(910,084		)
Contributions in aid of construction	64,296			46,546			20,325
Allowance for borrowed funds used during construction	(19,481		)	(16,183		)	(15,457		)
Proceeds from nuclear decommissioning trust sales	633,410			478,813			356,195
Investment in nuclear decommissioning trust	(635,691		)	(496,062		)	(373,444		)
Other	(13,865		)	(1,093		)	347
Net cash flow used for investing activities	(1,219,341		)	(1,060,032		)	(922,118		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151			842,415			606,126
Repayment of long-term debt	(370,430		)	(415,570		)	(527,578		)
Short-term borrowings and payments — net	135,500			(147,400		)	(5,725		)
Dividends paid on common stock	(281,300		)	(266,900		)	(253,600		)
Equity infusion from Pinnacle West	42,000			—			—
Noncontrolling interests	(22,744		)	(35,002		)	(20,482		)
Net cash flow provided by (used for) financing activities	196,177			(22,457		)	(201,259		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(13,216		)	17,541			790
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	22,056			4,515			3,725
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	8,840		$	22,056		$	4,515
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Income taxes, net of refunds	$	26,864		$	14,831		$	(86,054	)
Interest, net of amounts capitalized	181,809			167,670			173,436
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	114,874		$	83,798		$	44,712
Dividends declared but not paid	72,900			69,400			65,800

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)



	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount
Balance, December 31, 2013	71,264,947	$	178,162	$	2,379,696	$	1,804,398		$	(53,372	)	$	145,990		$	4,454,874

Net income		—		—		421,219			—			26,101			447,320
Other comprehensive income		—		—		—			5,039			—			5,039
Dividends on common stock		—		—		(256,900		)	—			—			(256,900		)
Other		—		—		1			—			—			1
Net capital activities by noncontrolling interests		—		—		—			—			(20,482		)	(20,482		)
Balance, December 31, 2014	71,264,947	178,162		2,379,696		1,968,718			(48,333		)	151,609			4,629,852

Net income		—		—		450,274			—			18,933			469,207
Other comprehensive income		—		—		—			21,236			—			21,236
Dividends on common stock		—		—		(270,500		)	—			—			(270,500		)
Other		—		—		1			—			—			1
Net capital activities by noncontrolling interests		—		—		—			—			(35,002		)	(35,002		)
Balance, December 31, 2015	71,264,947	178,162		2,379,696		2,148,493			(27,097		)	135,540			4,814,794

Equity infusion from Pinnacle West		—		42,000		—			—			—			42,000
Net income		—		—		462,141			—			19,493			481,634
Other comprehensive income		—		—		—			1,674			—			1,674
Dividends on common stock		—		—		(284,800		)	—			—			(284,800		)
Stock compensation cumulative effect adjustments (See Note 2)		—		—		5,411			—			—			5,411
Net capital activities by noncontrolling interests		—		—		—			—			(22,743		)	(22,743		)
Balance, December 31, 2016	71,264,947	$	178,162	$	2,421,696	$	2,331,245		$	(25,423	)	$	132,290		$	5,037,970

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

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

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

We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).

Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on net cash flows provided by operating activities. The following tables show the impacts of the reclassifications of the prior years (previously reported) amounts (dollars in thousands):



Statement of Cash Flows for the Year Ended December 31, 2015	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Stock compensation	$	—		$	18,756		$	18,756
Change in other long term liabilities	(81,959		)	(18,756		)	(100,715		)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Statement of Cash Flows for the Year Ended December 31, 2014	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Stock compensation	$	—		$	33,059		$	33,059
Change in other long-term liabilities	(80,993		)	(33,059		)	(114,052		)

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with 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.

Regulatory Accounting

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

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

See Note 3 for additional information.

Electric Revenues

We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.

Property, Plant and Equipment

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


•	material and labor;


•	contractor costs;


•	capitalized leases;


•	construction overhead costs (where applicable); and


•	allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, 2016 and 2015 consolidated balance sheets is composed of the following (dollars in thousands):



Property, Plant and Equipment:	2016			2015
Generation	$	7,874,898		$	7,336,902
Transmission	2,746,508			2,494,744
Distribution	5,738,801			5,543,561
General plant	981,681			847,025
Plant in service and held for future use	17,341,888			16,222,232
Accumulated depreciation and amortization	(5,970,100		)	(5,594,094		)
Net	11,371,788			10,628,138
Construction work in progress	1,019,947			816,307
Palo Verde sale leaseback, net of accumulated depreciation	113,515			117,385
Intangible assets, net of accumulated amortization	90,022			123,975
Nuclear fuel, net of accumulated amortization	119,004			123,139
Total property, plant and equipment	$	12,714,276		$	11,808,944

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

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 11.

APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2016 were as follows:

Fossil plant — 19 years;
Nuclear plant — 27 years;
Other generation — 26 years;
Transmission — 39 years;
Distribution — 33 years; and
General plant — 7 years.

Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS's acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. See Note 3 for further discussion. These costs were deferred and are now being amortized on the depreciation line of the Consolidated Statements of Income.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $422 million in 2016, $430 million in 2015, and $396 million in 2014. For the years 2014 through 2016, the depreciation rates ranged from a low of 0.30% to a high of 14.12%. The weighted-average depreciation rate was 2.66% in 2016, 2.74% in 2015, and 2.77% in 2014.

Allowance for Funds Used During Construction

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

AFUDC was calculated by using a composite rate of 7.17% for 2016, 8.02% for 2015, and 8.47% for 2014. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Materials and Supplies

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements

We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).

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

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

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

See Note 13 for additional information about fair value measurements.

Derivative Accounting

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

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

Loss Contingencies and Environmental Liabilities

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 7 for additional information on pension and other postretirement benefits.

Nuclear Fuel

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

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE suspended the fee. In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2016. See Note 10 for information on spent nuclear fuel disposal costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).

Cash and Cash Equivalents

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	Year ended December 31,
	2016		2015		2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$	9,956	$	6,550	$	(102,154	)
Interest, net of amounts capitalized	184,462		170,209		177,074
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	114,855	$	83,798	$	44,712
Dividends declared but not paid	72,926		69,363		65,790

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $58 million in 2016, $58 million in 2015, and $53 million in 2014. Estimated amortization expense on existing intangible assets over the next five years is $41 million in 2017, $23 million in 2018, $12 million in 2019, $4 million in 2020, and $1 million in 2021. At December 31, 2016, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).

Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments.

Business Segments

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

Preferred Stock

At December 31, 2016, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Standards

ASU 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting

In March 2016, new stock compensation accounting guidance was issued intended to simplify the accounting for employee share-based payments. The new guidance impacts several aspects of the accounting for share-based payments including: modifies the tax withholding threshold that triggers liability classification of an award, requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, simplifies the accounting for forfeitures, and clarifies certain cash flow presentation matters. Certain aspects of the standard must be adopted using a prospective approach and other aspects must be adopted using a modified retrospective approach.

During the fourth quarter of 2016, we elected to early adopt this standard, and accordingly have applied the guidance effective as of January 1, 2016. Prior to adoption of the new standard, our stock compensation awards were generally classified as liability awards and accounted for at fair value until settled because employees could withhold at more than the minimum statutory tax withholding rate. In accordance with the new guidance, certain of these stock compensation awards are now classified as equity awards and accounted for at grant date fair value. As a result of adopting the new standard, Pinnacle West recorded a cumulative effect adjustment to retained earnings of $6 million. The other provisions of the standard did not have a material impact on our consolidated financial statements. See Note 15 for additional details of the adoption impacts.

ASU 2015-07, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)

In May 2015, new accounting guidance was issued that removes the requirement to categorize certain investments valued using net asset value, as a practical expedient, within the fair value hierarchy. We retrospectively adopted this guidance during the first quarter of 2016. The adoption of this guidance modifies our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results. See Note 7 and Note 13.

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.

We plan on adopting this standard on January 1, 2018, and are currently evaluating the transition method and the effect on our financial statements. As part of our evaluation we continue to actively monitor certain industry issues being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups may impact our application of the standard, specifically in regards to the treatment of contributions in aid of construction.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements.

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 will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be 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. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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 2017-01, Business Combinations: Clarifying the Definition of a Business

In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are evaluating the impacts of adopting this new standard, and the impacts it may have on our financial statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%).

The principal provisions of the application are:


•	a test year ended December 31, 2015, adjusted as described below;


•	an original cost rate base of $6.8 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2015;


•	the following proposed capital structure and costs of capital:



	Capital Structure		Cost of Capital
Long-term debt	44.20	%	5.13	%
Common stock equity	55.80	%	10.50	%
Weighted-average cost of capital			8.13	%


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


•	a base rate for fuel and purchased power costs of $0.029882 per kWh based on estimated 2017 prices (a decrease from the current base fuel rate of $0.03207 per kWh);


•	authorization to defer for potential future recovery its share of the construction costs associated with installing selective catalytic reduction equipment at Four Corners (estimated at approximately $400 million in direct costs). APS proposes that the rates established in this rate case be increased through a step mechanism beginning in 2019 to reflect these deferred costs;


•	authorization to defer for potential future recovery in the Company’s next general rate case the construction costs APS incurs for its Ocotillo power plant modernization project, once the project reaches commercial operation. APS estimates the direct construction costs at approximately $500 million and that the new facility will be fully in service by early 2019;


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


•	updates and modifications to four of APS’s adjustor mechanisms - the PSA, the LFCR, the TCA and the Environmental Improvement Surcharge (“EIS”);

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


•	a number of proposed rate design changes for residential customers, including:


◦	change the on-peak time of use period from 12 p.m. - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;


◦	reduce the difference in the on- and off-peak energy price and lower all energy charges;


◦	offer four rate plan options, three of which have demand charges and a fourth that is available to non-partial requirements customers using less than 600 kWh on average per month; and


◦	modify the current net metering tariff to provide for a credit at the retail rate for the portion of generation by rooftop solar customers that offsets their own load, and for a credit for excess energy delivered to the grid at an export rate.


•	proposed rate design changes for commercial customers, including an aggregation rider that allows certain large customers to qualify for a reduced rate, an extra-high load factor rate schedule for certain customers, and an economic development rate offering for new loads meeting certain criteria.

The Company requested that the increase become effective July 1, 2017. On July 22, 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months.

The ACC staff and intervenors began filing their direct testimony in late December 2016 and additional filings of testimony are ongoing. On January 12, 2017, APS began settlement discussions with all parties. On January 13, 2017, the ALJ hearing the case before the ACC issued a procedural order delaying hearings on the case from the originally scheduled March 22, 2017 to April 24, 2017, to allow parties to participate in settlement discussions and prepare testimony on the distributed generation rate design issues addressed in the value and cost of DG decision. According to the procedural order, settlement discussions are to be completed and, if applicable, any related settlement must be filed by March 17, 2017. The procedural order also extended the rate case completion date as calculated by Commission rule for an additional 33 days. APS cannot predict the outcome of this case.

Prior Rate Case Filing

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

Settlement Agreement

The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million.

Other key provisions of the 2012 Settlement Agreement include the following:

An authorized return on common equity of 10.0%;
A capital structure comprised of 46.1% debt and 53.9% common equity;

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


•	A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;


•	Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:


•	Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

Deferral of 100% in all years if Arizona property tax rates decrease;


•	A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of 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, see "Four Corners" below);


•	Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;


•	Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

Modifications to the PSA, including the elimination of the 90/10 sharing provision;


•	A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the settlement agreement for the 2009 retail rate case (the "2009 Settlement Agreement");


•	Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;


•	Modification of the TCA to streamline the process for future transmission-related rate changes; and


•	Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.

The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC.

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. The ACC has not yet ruled on the Company’s 2017 RES Implementation Plan.

In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically. The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the EPA. The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. APS cannot predict the outcome of this proceeding.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.

On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program.

On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on the Company’s 2017 DSM Plan.

Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.

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


•	APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;


•	An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;


•	The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

•

The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and


•	The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2016 and 2015 (dollars in thousands):



	Year Ended December 31,
	2016			2015
Beginning balance	$	(9,688	)	$	6,926
Deferred fuel and purchased power costs - current period	60,303			(14,997		)
Amounts charged to customers	(38,150		)	(1,617		)
Ending balance	$	12,465		$	(9,688	)

The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh.

Transmission Rates, Transmission Cost Adjustor 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 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, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 in

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2015.

Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 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, 2016.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies to make changes to their protocols in the future. As a result, APS is evaluating how its formula rate protocols compare with more recently approved formula rate protocols and anticipates that it will make a filing to update its formula rate protocols in the first quarter of 2017.

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 distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were 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. 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 kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units.

APS files for a LFCR adjustment every January. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two month delay in implementation did not have an adverse effect on APS. APS filed its 2017 LFCR adjustment on January 13, 2017. APS requested an adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective the first billing cycle of March 2017.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation 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 ALJ 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 decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

cost methodology is being developed. The price established by this resource comparison proxy method will be updated annually (between 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 that utility 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 the date new rates are effective based on APS' pending rate case will be grandfathered for a period of 20 years from the date of interconnection;


•	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 rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case, which is scheduled for hearing by the ACC in April 2017. APS cannot predict the outcome of this determination.

The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases.

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 asserts 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's request for rehearing is required for TASC to challenge this decision in court. To date, the ACC has taken no action on the rehearing request. The ACC's decision is expected to remain in effect during any legal challenge.

Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB")

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case. The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision. On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

System Benefits Charge

The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016. Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge. The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to 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 APS to produce all information previously requested through the subpoenas. Commissioner Burns has also scheduled a workshop in this matter for March 17, 2017. APS and Pinnacle West cannot predict the outcome of this matter.

Four Corners

On December 30, 2013, APS purchased 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 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 includes 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 provides 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 $64 million as of December 31, 2016 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter will be resolved.

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. APS cannot predict the outcome of either matter.

Cholla

On September 11, 2014, APS announced that it would close Cholla Unit 2 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. APS closed Unit 2 on October 1, 2015. On January 13, 2017, EPA approved a final rule incorporating APS's compromise proposal. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and is seeking recovery of the unit’s decommissioning and other retirement-related costs over the previously estimated remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($116 million as of December 31, 2016), 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. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Navajo Plant

On February 13, 2017, the co-owners of the Navajo Plant voted not to pursue continued operation of the plant beyond December 2019, the expiration of the current lease term, and to pursue a new lease or lease extension with the Navajo Nation that would allow decommissioning activities to begin after December 2019 instead of later this year. Various stakeholders including regulators, tribal representatives and others interested in the continued operation of the plant intend to meet to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. We cannot predict whether any alternate solutions will be found that would be acceptable to all of the stakeholders and feasible to implement. APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($108 million as of December 31, 2016, see Note 9 for additional details) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. We cannot predict whether APS would obtain such recovery.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities

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



S	Amortization Through	December 31, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	711,059	$	—	$	619,223
Retired power plant costs	2033	9,913		117,591		9,913		127,518
Income taxes - AFUDC equity	2046	6,305		152,118		5,495		133,712
Deferred fuel and purchased power — mark-to-market (Note 16)	2020	—		42,963		71,852		69,697
Four Corners cost deferral	2024	6,689		56,894		6,689		63,582
Income taxes — investment tax credit basis adjustment	2046	2,120		54,356		1,766		48,462
Lost fixed cost recovery	2017	61,307		—		45,507		—
Palo Verde VIEs (Note 18)	2046	—		18,775		—		18,143
Deferred compensation	2036	—		35,595		—		34,751
Deferred property taxes	(d)	—		73,200		—		50,453
Loss on reacquired debt	2038	1,637		16,942		1,515		16,375
AG-1 deferral	2018	—		5,868		—		—
Demand side management (b)	2017	3,744		—		—		—
Tax expense of Medicare subsidy	2024	1,513		10,589		1,520		12,163
Transmission vegetation management	2016	—		—		4,543		—
Mead-Phoenix transmission line CIAC	2050	332		10,708		332		11,040
Deferred fuel and purchased power (b) (c)	2017	12,465		—		—		—
Coal reclamation	2026	418		5,182		418		6,085
Other	Various	432		1,588		5		2,942
Total regulatory assets (e)		$	106,875	$	1,313,428	$	149,555	$	1,214,146


(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 OCI and result in lower future revenues. See Note 7 for further discussion.


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


(c)	Subject to a carrying charge.


(d)	Per the provision of the 2012 Settlement Agreement.


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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	Amortization Through	December 31, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Asset retirement obligations	2057	$	—	$	279,976	$	—	$	277,554
Removal costs	(a)	29,899		223,145		39,746		240,367
Other postretirement benefits	(d)	32,662		123,913		34,100		179,521
Income taxes — deferred investment tax credit	2046	4,368		108,827		3,604		97,175
Income taxes - change in rates	2045	1,771		70,898		1,113		72,454
Spent nuclear fuel	2047	—		71,726		3,051		67,437
Renewable energy standard (b)	2017	26,809		—		43,773		4,365
Demand side management (b)	2019	—		20,472		6,079		19,115
Sundance maintenance	2030	—		15,287		—		13,678
Deferred fuel and purchased power (b) (c)	2016	—		—		9,688		—
Deferred gains on utility property	2018	2,063		8,895		2,062		6,001
Four Corners coal reclamation	2031	—		18,248		—		8,920
Other	Various	2,327		7,529		2,550		7,565
Total regulatory liabilities		$	99,899	$	948,916	$	145,766	$	994,152


(a)	In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal (see Note 11).


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


(c)	Subject to a carrying charge.


(d)	See Note 7.

Income Taxes

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

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

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18). 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	Pinnacle West Consolidated									APS Consolidated
	2016			2015			2014			2016			2015			2014
Total unrecognized tax benefits, January 1	$	34,447		$	44,775		$	41,997		$	34,447		$	44,775		$	41,997
Additions for tax positions of the current year	2,695			2,175			4,309			2,695			2,175			4,309
Additions for tax positions of prior years	886			—			751			886			—			751
Reductions for tax positions of prior years for:
Changes in judgment	(1,953		)	(10,244		)	(2,282		)	(1,953		)	(10,244		)	(2,282		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	—			(2,259		)	—			—			(2,259		)	—
Total unrecognized tax benefits, December 31	$	36,075		$	34,447		$	44,775		$	36,075		$	34,447		$	44,775

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



	Pinnacle West Consolidated						APS Consolidated
	2016		2015		2014		2016		2015		2014
Tax positions, that if recognized, would decrease our effective tax rate	$	11,313	$	9,523	$	11,207	$	11,313	$	9,523	$	11,207

As of the balance sheet date, the tax year ended December 31, 2013 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 2012.

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



	Pinnacle West Consolidated							APS Consolidated
	2016		2015			2014		2016		2015			2014
Unrecognized tax benefit interest expense/(benefit) recognized	$	529	$	(161	)	$	752	$	529	$	(161	)	$	752

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):



	Pinnacle West Consolidated						APS Consolidated
	2016		2015		2014		2016		2015		2014
Unrecognized tax benefit interest accrued	$	1,333	$	804	$	965	$	1,333	$	804	$	965

Additionally, as of December 31, 2016, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	Pinnacle West Consolidated							APS Consolidated
	Year Ended December 31,							Year Ended December 31,
	2016		2015			2014		2016		2015		2014
Current:
Federal	$	8,630	$	(12,335	)	$	25,054	$	711	$	6,485	$	40,115
State	1,259		4,763			10,382		4,276		7,813		15,598
Total current	9,889		(7,572		)	35,436		4,987		14,298		55,713
Deferred:
Federal	201,743		221,505			167,365		215,178		208,326		165,027
State	24,779		23,787			17,904		25,677		23,217		16,620
Total deferred	226,522		245,292			185,269		240,855		231,543		181,647
Income tax expense	$	236,411	$	237,720		$	220,705	$	245,842	$	245,841	$	237,360

On the APS Consolidated Statements of Income, federal and state income taxes are allocated between operating income and other income.

The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):



	Pinnacle West Consolidated									APS Consolidated
	Year Ended December 31,									Year Ended December 31,
	2016			2015			2014			2016			2015			2014
Federal income tax expense at 35% statutory rate	$	244,278		$	242,869		$	225,540		$	254,617		$	250,267		$	239,638
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	16,311			18,265			18,149			18,750			20,433			21,148
Credits and favorable adjustments related to prior years resolved in current year	—			(2,169		)	—			—			(1,892		)	—
Medicare Subsidy Part-D	844			837			830			844			837			830
Allowance for equity funds used during construction (see Note 1)	(11,724		)	(9,711		)	(8,523		)	(11,724		)	(9,711		)	(8,523		)
Palo Verde VIE noncontrolling interest (see Note 18)	(6,823		)	(6,626		)	(9,135		)	(6,823		)	(6,626		)	(9,135		)
Investment tax credit amortization	(5,887		)	(5,527		)	(4,928		)	(5,887		)	(5,527		)	(4,928		)
Other	(588		)	(218		)	(1,228		)	(3,935		)	(1,940		)	(1,670		)
Income tax expense	$	236,411		$	237,720		$	220,705		$	245,842		$	245,841		$	237,360

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2016, APS has recorded a regulatory liability of $74 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2016, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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



	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2016			2015			2016			2015
DEFERRED TAX ASSETS
Risk management activities	$	26,614		$	70,498		$	26,614		$	70,498
Regulatory liabilities:
Asset retirement obligation and removal costs	200,140			216,765			200,140			216,765
Unamortized investment tax credits	113,195			100,779			113,195			100,779
Other postretirement benefits	60,375			83,034			60,375			83,034
Other	63,311			60,707			63,311			60,707
Pension liabilities	204,436			191,028			194,981			181,787
Renewable energy incentives	56,379			60,956			56,379			60,956
Credit and loss carryforwards	75,944			59,557			1,645			—
Other	158,421			149,033			187,453			176,016
Total deferred tax assets	958,815			992,357			904,093			950,542
DEFERRED TAX LIABILITIES
Plant-related	(3,297,989		)	(3,116,752		)	(3,297,989		)	(3,116,752		)
Risk management activities	(7,594		)	(10,626		)	(7,594		)	(10,626		)
Other postretirement assets	(63,477		)	(71,737		)	(62,819		)	(70,986		)
Regulatory assets:
Allowance for equity funds used during construction	(61,088		)	(54,110		)	(61,088		)	(54,110		)
Deferred fuel and purchased power — mark-to-market	(21,396		)	(55,020		)	(21,396		)	(55,020		)
Pension benefits	(274,184		)	(240,692		)	(274,184		)	(240,692		)
Retired power plant costs (see Note 3)	(49,166		)	(53,420		)	(49,166		)	(53,420		)
Other	(123,987		)	(108,441		)	(123,987		)	(108,441		)
Other	(5,166		)	(4,984		)	(5,165		)	(4,984		)
Total deferred tax liabilities	(3,904,047		)	(3,715,782		)	(3,903,388		)	(3,715,031		)
Deferred income taxes — net	$	(2,945,232	)	$	(2,723,425	)	$	(2,999,295	)	$	(2,764,489	)

As of December 31, 2016, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $98 million, which first begin to expire in 2031, and other federal and state loss carryforwards of $5 million, which first begin to expire in 2019. The credit and loss carryforwards amount above has been reduced by $27 million of unrecognized tax benefits.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lines of Credit and Short-Term Borrowings

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

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2016 and 2015 (dollars in thousands):



	December 31, 2016									December 31, 2015
	Pinnacle West			APS			Total			Pinnacle West		APS		Total
Commitments under Credit Facilities	$	275,000		$	1,000,000		$	1,275,000		$	200,000	$	1,000,000	$	1,200,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(41,700		)	(135,500		)	(177,200		)	—		—		—
Amount of Credit Facilities Available	$	233,300		$	864,500		$	1,097,800		$	200,000	$	1,000,000	$	1,200,000

Weighted-Average Commitment Fees	0.125%			0.100%						0.125%		0.100%

Pinnacle West

On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $200 million facility that matures in May 2021. 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. At December 31, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $1.7 million commercial paper borrowings.

On August 31, 2016, PNW entered into a $75 million 364-day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At December 31, 2016, Pinnacle West had $40 million outstanding under the facility.

APS

During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021.

At December 31, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021. 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 December 31, 2016, APS had $135.5 million of commercial paper outstanding and no outstanding borrowings or letters of credit

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

under its revolving credit facilities. See "Financial Assurances" in Note 10 for a discussion of APS's other outstanding letters of credit.

Debt Provisions

On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of 7% of APS’s capitalization, and $500 million (which is required to be used for costs relating to purchases of natural gas and power). This financing order is set to expire on December 31, 2017. See Note 6 for additional long-term debt provisions.

Long-Term Debt and Liquidity Matters

All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2016 and 2015 (dollars in thousands):



	Maturity	Interest	December 31,
	Dates (a)	Rates	2016			2015
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975		$	92,405
Fixed	2024-2029	1.75%-4.70%	147,150			211,150
Total pollution control bonds			183,125			303,555
Senior unsecured notes	2019-2046	2.20%-8.75%	3,725,000			3,375,000
Term loans	2018-2019	(c)	150,000			50,000
Unamortized discount			(11,816		)	(10,374		)
Unamortized premium			4,506			4,686
Unamortized debt issuance cost			(29,030		)	(27,896		)
Total APS long-term debt			4,021,785			3,694,971
Less current maturities			—			357,580
Total APS long-term debt less current maturities			4,021,785			3,337,391
Pinnacle West
Term loan	2017	(d)	125,000			125,000
Less current maturities			125,000			—
Total PNW long-term debt less current maturities			—			125,000
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	4,021,785		$	3,462,391

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

(b) The weighted-average rate for the variable rate pollution control bonds was 0.81% at December 31, 2016 and 0.01%-0.24% at December 31, 2015.


(c)	The weighted-average interest rate was 1.427% at December 31, 2016, and 1.024% at December 31, 2015.

(d) The interest rate was 1.520% at December 31, 2016 and 1.174% at December 31, 2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



Year	Consolidated Pinnacle West		Consolidated APS
2017	$	125,000	$	—
2018	82,000		82,000
2019	600,000		600,000
2020	250,000		250,000
2021	—		—
Thereafter	3,126,125		3,126,125
Total	$	4,183,125	$	4,058,125

Debt Fair Value

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):



	As of December 31, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125,000	$	125,000	$	125,000	$	125,000
APS	4,021,785		4,300,789		3,694,971		3,981,367
Total	$	4,146,785	$	4,425,789	$	3,819,971	$	4,106,367

Credit Facilities and Debt Issuances

APS

On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. Interest rates are based on APS's senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

On May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E.

On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On August 1, 2016, APS repaid at maturity APS's $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016.

On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016.

On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B.

On December 6, 2016, APS redeemed at par and canceled all $17 million of the Coconino County Arizona Pollution Control Corporation Revenue Bonds (Arizona Public Service Company Project), Series 1998.

See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2016, the ratio was approximately 48% for Pinnacle West and 47% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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

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

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2016, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.1 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.6 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2016.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017. See Note 5 for additional short-term debt provisions.

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries. These plans provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement (HRA). The Company is providing a subsidy allowing post-65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The remeasurement reduced net periodic benefit costs in 2014 by $10 million ($5 million of which reduced expense). The remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income.

Because of the plan changes, the Company is currently in the process of seeking IRS approval to move up to $140 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to move into a new account to pay for active union employee medical costs. As of December 31, 2016, such methodology would result in an amount of approximately $140 million being transferred to the new account.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 13 for further discussion of how fair values are determined. Due to subjective and complex judgments, which

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory liability. In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over three years beginning in July 2012. We amortized approximately $5 million in 2015, $8 million in 2014, $8 million in 2013 and $4 million in 2012.

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, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):



	Pension									Other Benefits
	2016			2015			2014			2016			2015			2014
Service cost-benefits earned during the period	$	53,792		$	59,627		$	53,080		$	14,993		$	16,827		$	18,139
Interest cost on benefit obligation	131,647			123,983			129,194			29,721			28,102			41,243
Expected return on plan assets	(173,906		)	(179,231		)	(158,998		)	(36,495		)	(36,855		)	(46,400		)
Amortization of:
Prior service cost (credit)	527			594			869			(37,883		)	(37,968		)	(9,626		)
Net actuarial loss	40,717			31,056			10,963			4,589			4,881			1,175
Net periodic benefit cost	$	52,777		$	36,029		$	35,108		$	(25,075	)	$	(25,013	)	$	4,531
Portion of cost charged to expense	$	26,172		$	20,036		$	21,985		$	(12,435	)	$	(10,391	)	$	6,000

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2016 and 2015 (dollars in thousands):



	Pension						Other Benefits
	2016			2015			2016			2015
Change in Benefit Obligation
Benefit obligation at January 1	$	3,033,803		$	3,078,648		$	647,020		$	682,335
Service cost	53,792			59,627			14,993			16,827
Interest cost	131,647			123,983			29,721			28,102
Benefit payments	(142,247		)	(137,115		)	(26,231		)	(24,988		)
Actuarial (gain) loss	127,467			(91,340		)	50,942			(55,256		)
Benefit obligation at December 31	3,204,462			3,033,803			716,445			647,020
Change in Plan Assets
Fair value of plan assets at January 1	2,542,774			2,615,404			833,017			834,625
Actual return on plan assets	166,408			(44,690		)	63,463			(2,399		)
Employer contributions	100,000			100,000			819			791
Benefit payments	(133,825		)	(127,940		)	(14,648		)	—
Fair value of plan assets at December 31	2,675,357			2,542,774			882,651			833,017
Funded Status at December 31	$	(529,105	)	$	(491,029	)	$	166,206		$	185,997

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2016 and 2015 (dollars in thousands):



	2016		2015
Projected benefit obligation	$	3,204,462	$	3,033,803
Accumulated benefit obligation	3,049,406		2,873,467
Fair value of plan assets	2,675,357		2,542,774

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2016 and 2015 (dollars in thousands):



	Pension						Other Benefits
	2016			2015			2016		2015
Noncurrent asset	$	—		$	—		$	166,206	$	185,997
Current liability	(19,795		)	(10,031		)	—		—
Noncurrent liability	(509,310		)	(480,998		)	—		—
Net amount recognized	$	(529,105	)	$	(491,029	)	$	166,206	$	185,997

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2016 and 2015 (dollars in thousands):



	Pension						Other Benefits
	2016			2015			2016			2015
Net actuarial loss	$	773,750		$	679,501		$	146,509		$	127,124
Prior service cost (credit)	81			609			(303,417		)	(341,301		)
APS’s portion recorded as a regulatory (asset) liability	(711,059		)	(619,223		)	156,575			213,621
Income tax expense (benefit)	(24,202		)	(23,663		)	833			925
Accumulated other comprehensive loss	$	38,570		$	37,224		$	500		$	369

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2017 (dollars in thousands):



	Pension		Other Benefits
Net actuarial loss	$	46,971	$	5,181
Prior service cost (credit)	81		(37,842		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017	$	47,052	$	(32,661	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2016		2015		2016		2015		2014
									January - September		October - December
Discount rate – pension	4.08	%	4.37	%	4.37	%	4.02	%	4.88	%	4.88	%
Discount rate – other benefits	4.17	%	4.52	%	4.52	%	4.14	%	5.10	%	4.41	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets - pension	N/A		N/A		6.90	%	6.90	%	6.90	%	6.90	%
Expected long-term return on plan assets - other benefits	N/A		N/A		4.45	%	4.45	%	6.80	%	4.25	%
Initial healthcare cost trend rate (pre-65 participants)	7.00	%	7.00	%	7.00	%	7.00	%	7.50	%	7.50	%
Initial healthcare cost trend rate (post-65 participants)	5.00	%	5.00	%	5.00	%	5.00	%	7.50	%	5.00	%
Ultimate healthcare cost trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Number of years to ultimate trend rate (pre-65 participants)	4		4		4		4		4		4
Number of years to ultimate trend rate (post-65 participants)	0		0		0		0		4		0

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2017, we are assuming a 6.55% long-term rate of return for pension assets and 6.37% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final reports on its recommended mortality basis (“RP-2014 Mortality Tables Report” and "Mortality Improvement Scale MP-2014 Report"). At December 31, 2014, we updated our mortality assumptions using the recommended basis with modifications to better reflect our plan experience and additional data regarding mortality trends. The updated mortality assumptions resulted in a $67 million increase in Pinnacle West’s pension and other postretirement obligations, which was offset by the related regulatory asset, regulatory liability and accumulated other comprehensive income.

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in thousands):



	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	8,430	$	(5,455	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	8,440		(6,527		)
Effect on the accumulated other postretirement benefit obligation	108,046		(86,651		)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Plan Assets

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

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

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other government agencies, U.S Treasury Futures Contracts, and fixed income debt securities issued by corporations. Long-term fixed income assets may also include interest rate swaps, and other instruments.

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

Based on the IPS, and given the pension plan’s funded status at year-end 2016, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 39% to 45%. The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments. The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. As of December 31, 2016, long-term fixed income assets represented 57% of total pension plan assets, and return-generating assets represented 43% of total pension plan assets.

As of December 31, 2016, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. As of December 31, 2016, investment in fixed income assets represented 51% of the other postretirement benefit plan total assets, and non-fixed income assets represented 49% of the other postretirement benefit plan’s assets.

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income, U.S Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. U.S Treasury Future Contracts are valued using the quoted active market prices from the exchange

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (NAV) concept or its equivalent. Mutual funds, classified as Level 1, are valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). The trust's shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities is derived from the quoted active market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets. As of December 31, 2016, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, 2016, approximately $54 million of these commitments have been funded.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016, by asset category, are as follows (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2016
Pension Plan:
Cash and cash equivalents	$	13,995	$	—	$	—	$	13,995
Fixed income securities:
Corporate	—		1,210,453		—		1,210,453
U.S. Treasury	112,583		—		—		112,583
Other (b)	—		102,170		—		102,170
Common stock equities (c)	235,109		—		—		235,109
Mutual funds (d)	251,506		—		—		251,506
Common and collective trusts:
Equities	—		—		266,840		266,840
Real estate	—		—		161,449		161,449
Partnerships	—		—		208,915		208,915
Short-term investments and other (e)	—		—		112,337		112,337
Total	$	613,193	$	1,312,623	$	749,541	$	2,675,357
Other Benefits:
Cash and cash equivalents	$	304	$	—	$	—	$	304
Fixed income securities:
Corporate	—		268,193		—		268,193
U.S. Treasury	145,255		—		—		145,255
Other (b)	—		34,506		—		34,506
Common stock equities (c)	243,741		—		—		243,741
Mutual funds (d)	67,418		—		—		67,418
Common and collective trusts:
Equities	—		—		95,814		95,814
Real estate	—		—		14,509		14,509
Partnerships	—		—		3,060		3,060
Short-term investments and other (e)	—		—		9,851		9,851
Total	$	456,718	$	302,699	$	123,234	$	882,651


(a)	These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.


(b)	This category consists primarily of debt securities issued by municipalities.


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


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


(e)	This category includes plan receivables and payables.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2015, by asset category, are as follows (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2015
Pension Plan:
Cash and cash equivalents	$	1,893	$	—	$	—	$	1,893
Fixed Income Securities:
Corporate	—		1,108,736		—		1,108,736
U.S. Treasury	274,778		—		—		274,778
Other (b)	—		113,008		—		113,008
Common stock equities (c)	247,701		—		—		247,701
Mutual funds - International equities	116,307		—		—		116,307
Common and collective trusts:
Equities	—		—		315,989		315,989
Real Estate	—		—		150,359		150,359
Partnerships	—		—		169,937		169,937
Short-term investments and other (d)	—		—		44,066		44,066
Total	$	640,679	$	1,221,744	$	680,351	$	2,542,774
Other Benefits:
Cash and cash equivalents	$	240	$	—	$	—	$	240
Fixed Income Securities:
Corporate	—		217,026		—		217,026
U.S. Treasury	131,435		—		—		131,435
Other (b)	—		31,106		—		31,106
Common stock equities (c)	265,583		—		—		265,583
Mutual funds - International equities	52,568		—		—		52,568
Common and collective trusts:
Equities	—		—		110,055		110,055
Real Estate	—		—		13,512		13,512
Short-term investments and other (d)	—		—		11,492		11,492
Total	$	449,826	$	248,132	$	135,059	$	833,017


(a)	These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.


(b)	This category consists primarily of debt securities issued by municipalities.


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


(d)	This category includes plan receivables and payables.

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2016, $100 million in 2015, and $175 million in 2014. 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 $300 million during the 2017-2019 period. With regard to contributions to our other postretirement benefit plans, we made a contribution of

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approximately $1 million in each of 2016, 2015 and 2014. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans. APS funds its share of the contributions. APS’s share of the pension plan contribution was approximately $100 million in 2016, $100 million in 2015 and $175 million in 2014. APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2016, 2015 and 2014.

Estimated Future Benefit Payments

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



Year	Pension		Other Benefits
2017	$	172,859	$	31,126
2018	173,232		33,795
2019	182,944		36,195
2020	191,037		37,998
2021	196,292		39,368
Years 2022-2026	1,049,149		201,944

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

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2016, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $10 million for 2016, $9 million for 2015, and $9 million for 2014.

Leases

We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. See Note 2 for a discussion of the new lease accounting standard.

Total lease expense recognized in the Consolidated Statements of Income was $16 million in 2016, $17 million in 2015, and $18 million in 2014. APS’s lease expense was $15 million in 2016, $14 million in 2015, and $15 million in 2014.

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Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands):



Year	Pinnacle West Consolidated		APS
2017	$	12,330	$	11,919
2018	10,987		10,690
2019	9,019		8,767
2020	7,688		7,439
2021	5,266		5,020
Thereafter	59,647		57,207
Total future lease commitments	$	104,937	$	101,042

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

Jointly-Owned Facilities

APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2016 (dollars in thousands):



	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,770,324	$	1,080,072	$	17,615
Palo Verde Unit 2 (a)	16.8	%		581,572		360,757		9,717
Palo Verde Common	28.0	%	(b)	672,799		242,649		62,479
Palo Verde Sale Leaseback			(a)	351,050		237,535		—
Four Corners Generating Station	63.0	%		934,837		578,924		248,072
Navajo Generating Station Units 1, 2 and 3	14.0	%		279,629		176,931		5,761
Cholla common facilities (c)	63.3	%	(b)	159,707		58,276		806		(d)
Transmission facilities:
ANPP 500kV System	33.6	%	(b)	127,970		38,610		2,291
Navajo Southern System	22.5	%	(b)	62,135		20,491		334
Palo Verde — Yuma 500kV System	19.0	%	(b)	13,699		5,368		408
Four Corners Switchyards	51.3	%	(b)	39,850		10,474		1,044
Phoenix — Mead System	17.1	%	(b)	39,330		13,725		85
Palo Verde — Rudd 500kV System	50.0	%	(b)	91,904		19,818		227
Morgan — Pinnacle Peak System	65.2	%	(b)	140,374		13,557		—
Round Valley System	50.0	%	(b)	515		127		—
Palo Verde — Morgan System	85.8	%	(b)	125,908		1,326		28,949
Hassayampa — North Gila System	80.0	%	(b)	142,541		3,231		—
Cholla 500kV Switchyard	85.7	%	(b)	5,078		1,201		—
Saguaro 500kV Switchyard	75.0	%	(b)	20,456		12,426		2


(a)	See Note 18.


(b)	Weighted-average of interests.


(c)	PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.


(d)	Due to the closure of Cholla Unit 2 in 2015, all new Cholla common facilities construction is owned by APS at 50.5%

4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. At December 31, 2016, 4CA had plant in service of $110 million, accumulated depreciation of $79 million and construction work in progress of $30 million.

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Commitments and Contingencies

Palo Verde Nuclear 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 DOE in the Court of Federal Claims. The lawsuit sought to recover damages incurred due to DOE’s breach of the 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 provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019.

APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2016, and approved on February 1, 2017, in the amount of $11.3 million (APS’s share is $3.3 million). Payment for the claim is expected in the second quarter of 2017.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million (on January 1, 2017 this coverage was increased to $450 million), which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $13.1 billion (on January 1, 2017 this balance was decreased to $13.0 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 $127.3 million, subject to a maximum annual premium of $18.9 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 $111.1 million, with a maximum annual retrospective premium of approximately $16.6 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

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("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 $23.8 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 $64 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.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2017 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $977 million in 2017; $737 million in 2018; $598 million in 2019; $525 million in 2020; $524 million in 2021; and $7.3 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

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

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



	Years Ended December 31,
	2017		2018		2019		2020		2021		Thereafter
Coal take-or-pay commitments (a)	$	195,428	$	189,588	$	193,818	$	198,160	$	202,619	$	2,068,355


(a)	Total take-or-pay commitments are approximately $3.0 billion. The total net present value of these commitments is approximately $2.1 billion.

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



	Year Ended December 31,
	2016		2015		2014
Total purchases	$	160,066	$	211,327	$	236,773

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $40 million in 2017; $40 million in 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; and $420 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy.

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Coal Mine Reclamation Obligations

APS and 4CA must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $207 million at December 31, 2016 and $202 million at December 31, 2015. 4CA recorded an obligation for the coal mine final reclamation of approximately $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $17 million in 2017; $18 million in 2018; $19 million in 2019; $21 million in 2020; $22 million in 2021; and $241 million thereafter. 4CA expects to make payments for the final mine reclamation as follows: $1 million in 2017; $1 million in 2018; $1 million in 2019; $1 million in 2020; $2 million in 2021; and $17 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

Superfund-Related Matters

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, 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 RI/FS work plan. The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by June 2017. 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, 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, 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 contractors filed ancillary lawsuits for recovery of costs against APS and the other 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.

Southwest Power Outage

On September 8, 2011 at approximately 3:30 PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that

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occurred at a switchyard operated by APS. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.

On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision. On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016.

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 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 requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. EPA recently approved a proposed 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 recent Cholla rule approval.

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required controls for Four Corners Units 4 and 5 would be approximately $400 million. In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP, could be up to approximately $200 million. In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly,

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on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014.

In September 2014, APS met with EPA to propose a compromise BART strategy. Pending certain regulatory approvals, APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 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 current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015.

On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program. EPA signed the final rule approving the Agency's proposal on January 13, 2017. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review.

Mercury and Air Toxic Standards ("MATS"). In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $8 million for Cholla. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million, the majority of which has already been incurred. Litigation concerning the rules, including supplemental analyses EPA has prepared in support of the MATS regulation, is ongoing. These proceedings do not materially impact APS. Regardless of the results from further judicial or administrative proceedings concerning the MATS rulemaking, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla.

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 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. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will

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continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

On December 16, 2016, President Obama signed the 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. Because EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act, and Arizona has yet to determine whether it will develop a state-specific permitting program, it is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR.

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 $15 million. APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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, the majority of which has already been incurred. Additionally, the CCR rule requires ongoing groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

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, within the next 3 years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion. 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, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for existing, new, modified, and reconstructed EGUs. EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal.

With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO2 emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard

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that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, this timing will be impacted by the court-imposed stay described below.

Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ is continuing to assess alternatives while completing outreach and soliciting feedback from stakeholders. In addition to these ongoing state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation.

The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such a delay.

With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances.

As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation.

Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material.

Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of

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allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes.

In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains ongoing, and additional information or considerations may arise that change our expectations.

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 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. Briefing on the merits of this litigation is expected to extend through May 2017. 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. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million. For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment in the amount of $0.8 million and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed an appeal of the decision on August 31, 2015.

On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above, is approximately $0.8 million.

Peabody Bankruptcy

On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri. Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona. APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement.

On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleged that the Buyers breached the Agreement. On January 27, 2017, the bankruptcy court approved a settlement between the parties, and on February 6, 2017 the parties executed an amendment to the Coal Supply Agreement that allows for continuation of the agreement with modified terms and conditions acceptable to the parties.

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 certain commodity contract collateral obligations and other transactions. As of December 31, 2016, standby letters of credit totaled $35 million and will expire in 2017. As of December 31, 2016, surety bonds expiring through 2019 totaled $53 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2016. Effective July 6, 2016, Pinnacle West has issued two parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation assets.

The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2016, APS recognized an ARO for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million. In addition, 4CA acquired El Paso's share of Four Corners Units 4 & 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million. In addition, Four Corners spent $16 million in actual decommissioning costs. Finally, in 2016, APS received a new decommissioning study for the Palo Verde Nuclear Generating Station. This resulted in an increase to the ARO in the amount of $151 million, an increase in plant in service of $131 million, and a reduction of the regulatory liability of $20 million.

In 2015, a revision to the estimated cash flows for the decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the ARO in the amount of $24 million. Also in 2015, Four Corners spent $32 million in actual decommissioning costs. In addition, APS recognized an ARO for Cholla as a result of new CCR environmental rules that were published in the Federal Register in the second quarter of 2015. See Note 10 for additional information related to the CCR environmental rules. This resulted in an increase to the ARO in the amount of $39 million, an increase in plant in service of $23 million and a reduction of the regulatory liability of $16 million. Finally, in 2015 there was a revision in estimated cash flows for the Cholla decommissioning, which resulted in a decrease of the ARO in the amount of $3 million.

The following table shows the change in our asset retirement obligations for 2016 and 2015 (dollars in thousands):



	2016			2015
Asset retirement obligations at the beginning of year	$	443,576		$	390,750
Changes attributable to:
Accretion expense	26,656			25,163
Settlements	(15,732		)	(32,048		)
Estimated cash flow revisions	151,046			17,556
Newly incurred or acquired obligations	18,929			42,155
Asset retirement obligations at the end of year	$	624,475		$	443,576

Decommissioning activities for Four Corners Units 1-3 began in January 2014. Thus, $9 million of the total ARO of $624 million at December 31, 2016, is classified as a current liability on the balance sheet. At December 31, 2015, $29 million of the total ARO of $444 million was classified as a current liability on the balance sheet.

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 3.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2016 and 2015 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.



	2016 Quarter Ended								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,167	$	915,394	$	1,166,922	$	739,199	$	3,498,682
Operations and maintenance	243,195		242,279		217,568		208,277		911,319
Operating income	50,162		231,748		451,258		122,816		855,984
Income taxes	1,914		65,742		141,446		27,309		236,411
Net income	9,326		126,182		267,900		58,119		461,527
Net income attributable to common shareholders	4,453		121,308		263,027		53,246		442,034

Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.04	$	1.09	$	2.36	$	0.48	$	3.97
Net income attributable to common shareholders — Diluted	0.04		1.08		2.35		0.47		3.95



	2015 Quarter Ended								2015
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	671,219	$	890,648	$	1,199,146	$	734,430	$	3,495,443
Operations and maintenance	214,944		210,965		220,449		222,019		868,377
Operating income	67,684		231,973		445,111		109,834		854,602
Income taxes	7,947		67,371		139,555		22,847		237,720
Net income	20,727		127,507		261,978		45,978		456,190
Net income attributable to common shareholders	16,122		122,902		257,116		41,117		437,257

Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.15	$	1.11	$	2.32	$	0.37	$	3.94
Net income attributable to common shareholders — Diluted	0.14		1.10		2.30		0.37		3.92

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Selected Quarterly Financial Data (Unaudited) - APS

APS's quarterly financial information for 2016 and 2015 is as follows (dollars in thousands):



	2016 Quarter Ended,								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,632	$	909,757	$	1,166,359	$	737,006	$	3,489,754
Operations and maintenance	238,711		233,712		209,366		197,319		879,108
Operating income	48,930		165,684		307,601		95,765		617,980
Net income attributable to common shareholder	7,253		127,188		269,220		58,480		462,141



	2015 Quarter Ended,								2015
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	670,668	$	889,723	$	1,198,380	$	733,586	$	3,492,357
Operations and maintenance	209,947		208,031		216,011		219,146		853,135
Operating income	61,333		162,704		301,238		86,709		611,984
Net income attributable to common shareholder	19,868		125,362		261,187		43,857		450,274

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 that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange traded equities, exchange traded derivative instruments, exchange traded mutual funds, cash equivalents, and investments in U.S. Treasury securities.

Level 2 — Utilizes 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). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, they are not traded on an exchange. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires certain instruments valued using NAV to no longer be classified within the fair value hierarchy. As such, certain instruments valued using NAV are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments. See Note 7 for the fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.

Coal Reclamation Trust Investments

The coal reclamation trust holds cash equivalent investments in money market funds that are valued using quoted prices in active markets, and are reported within Level 1.

Risk Management Activities — Derivative Instruments

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.

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 and the use of option valuation models with significant unobservable inputs.

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 our Nuclear Decommissioning Trust

The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities 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.

Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper.

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust 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 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We price securities using information provided by our trustee for our nuclear decommissioning trust assets. Our trustee uses pricing services that utilize the valuation methodologies described 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 trustee’s internal operating controls and valuation processes. See Note 19 for additional discussion about our nuclear decommissioning trust.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at December 31, 2016 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, 2016
Assets
Coal reclamation trust - cash equivalents (b)	$	14,521	$	—		$	—		$	—			$	14,521
Risk management activities — derivative instruments:
Commodity contracts	—		43,722			11,076			(35,103		)	(c)	19,695
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			353,261			(d)	353,261
Fixed income securities:
Cash and cash equivalent funds	—		—			—			795			(e)	795
U.S. Treasury	95,441		—			—			—				95,441
Corporate debt	—		111,623			—			—				111,623
Mortgage-backed securities	—		115,337			—			—				115,337
Municipal bonds	—		80,997			—			—				80,997
Other	—		22,132			—			—				22,132
Subtotal nuclear decommissioning trust	95,441		330,089			—			354,056				779,586
Total	$	109,962	$	373,811		$	11,076		$	318,953			$	813,802
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(45,641	)	$	(58,482	)	$	31,049		(c)	$	(73,074	)


(a)	Primarily consists of long-dated electricity contracts.


(b)	Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets.


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


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


(e)	Represents nuclear decommissioning trust net pending securities sales and purchases.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 2015 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, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	22,992		$	30,364		$	(25,345	)	(b)	$	28,011
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			314,957			(c)	314,957
Fixed income securities:
Cash and cash equivalent funds	12,260		—			—			(335		)	(d)	11,925
U.S. Treasury	117,245		—			—			—				117,245
Corporate debt	—		96,243			—			—				96,243
Mortgage-backed securities	—		99,065			—			—				99,065
Municipal bonds	—		72,206			—			—				72,206
Other	—		23,555			—			—				23,555
Subtotal nuclear decommissioning trust	129,505		291,069			—			314,622				735,196
Total	$	129,505	$	314,061		$	30,364		$	289,277			$	763,207
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(144,044	)	$	(63,343	)	$	39,698		(b)	$	(167,689	)


(a)	Primarily consists of heat rate options and other long-dated electricity contracts.


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


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


(d)	Represents nuclear decommissioning trust net pending securities sales and purchases.

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 and option model inputs. 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 3).

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The remaining option contract expired on October 1, 2016. The significant unobservable inputs at December 31, 2015 for these instruments include electricity prices, and volatilities. If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease. If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase. The commodity prices and volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs.

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 December 31, 2016 and December 31, 2015:



	December 31, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	10,648	$	32,042	Discounted cash flows	Electricity forward price (per MWh)	$16.43 - $41.07	$	29.86
Natural Gas:
Forward Contracts (a)	428		26,440		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.32 - $3.60	$	2.81
Total	$	11,076	$	58,482


(a)	Includes swaps and physical and financial contracts.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	December 31, 2015 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	24,543	$	54,679	Discounted cash flows	Electricity forward price (per MWh)	$15.92 - $40.73	$	26.86
Option Contracts (b)	—		5,628		Option model	Electricity forward price (per MWh)	$23.87 - $44.13	$	33.91
						Electricity price volatilities	40% - 59%	52		%
						Natural gas price volatilities	32% - 40%	35		%
Natural Gas:
Forward Contracts (a)	5,821		3,036		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.18 - $3.14	$	2.61
Total	$	30,364	$	63,343


(a)	Includes swaps and physical and financial contracts.


(b)	Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.

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 years ended December 31, 2016 and 2015 (dollars in thousands):



	Year Ended December 31,
Commodity Contracts	2016			2015
Net derivative balance at beginning of period	$	(32,979	)	$	(41,386	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—
Included in OCI	88			(452		)
Deferred as a regulatory asset or liability	(37,543		)	(4,009		)
Settlements	15,146			14,809
Transfers into Level 3 from Level 2	1,900			(6,256		)
Transfers from Level 3 into Level 2	5,982			4,315
Net derivative balance at end of period	$	(47,406	)	$	(32,979	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

Amounts included in earnings are recorded in either operating revenues or fuel and purchased power depending on the nature of the underlying contract.

Transfers 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Instruments Not Carried at Fair Value

The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our short-term borrowings are classified within Level 2 of the fair value hierarchy. See Note 6 for our long-term debt fair values.

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2016, 2015 and 2014 (in thousands, except per share amounts):



	2016		2015		2014
Net income attributable to common shareholders	$	442,034	$	437,257	$	397,595
Weighted average common shares outstanding — basic	111,409		111,026		110,626
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	637		526		552
Weighted average common shares outstanding — diluted	112,046		111,552		111,178
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	3.97	$	3.94	$	3.59
Net Income attributable to common shareholders - diluted	$	3.95	$	3.92	$	3.58

Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan authorizes up to 4.6 million common shares to be available for grant. As of December 31, 2016, 2.5 million common shares were available for issuance under the 2012 Plan. During 2016, 2015, and 2014, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation Expense and Activity

During the fourth quarter of 2016, we adopted new stock-based compensation accounting guidance prescribed by ASU 2016-09, see Note 2. Prior to the adoption of this guidance we had certain awards that were accounted for as liability awards due to the ability of the employee to withhold taxes beyond the minimum statutory tax withholding rate. Under the new standard, the tax withholding terms of our awards no longer trigger liability treatment. Accordingly, effective, January 1, 2016 certain awards that were previously classified as liability awards are now accounted for as equity awards. The impacts of this accounting change relating to prior years have been applied using a modified retrospective approach, resulting in a $6 million cumulative-effect adjustment, net of income tax expense of $3 million, to increase Retained Earnings as of January 1, 2016. The impacts of this accounting change relating to the current year, resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. Due to this transition approach, the following discussion reflects this change in the 2016 expense and activity; however, expense and activities relating to 2015 and 2014 reflect the historical treatment. The new standard also requires excess income tax benefits and deficiencies arising from stock based compensation to now be recognized in the period incurred, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. These other provisions of the standard did not have a material impact on our consolidated financial statements.

Compensation cost included in net income for stock-based compensation plans was $19 million in 2016, $19 million in 2015, and $33 million in 2014. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $10 million in 2016, $7 million in 2015, and $13 million in 2014.

As of December 31, 2016, there were approximately $13 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years.

The total fair value of shares vested was $22 million in 2016, $21 million in 2015 and $22 million in 2014.

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2016, 2015 and 2014.



	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2016		2015		2014		2016		2015		2014
Units granted	141,811		152,651		179,291		166,666		151,430		166,244
Weighted-average grant date fair value	$	67.34	$	64.12	$	54.89	$	66.60	$	64.97	$	54.86


(a)	Units granted includes awards that will be cash settled of 43,952 in 2016, 45,104 in 2015, and 49,018 in 2014.


(b)	Reflects the target payout level.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table is a summary of the status of non-vested awards as of December 31, 2016 and changes during the year.



	Restricted Stock Units, Stock Grants, and Stock Units					Performance Shares
	Shares			Weighted-Average Grant Date Fair Value		Shares (b)		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2016	428,287			$	56.69	305,832		$	58.86
Granted	141,811			67.34		166,666		66.60
Change in performance factor	—			—		15,573		54.09
Vested	(230,881	)		55.07		(171,303	)	54.09
Forfeited (c)	(3,958	)		62.86		(4,044	)	62.34
Nonvested at December 31, 2016	335,259		(a)	62.04		312,724		65.32
Vested Awards Outstanding at December 31, 2016	174,201					171,303


(a)	Includes 112,554 of awards that will be cash settled.


(b)	The nonvested performance shares are reflected at target payout level. The performance metric component increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests.


(c)	We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $3 million, $10 million and $9 million in 2016, 2015 and 2014, respectively. This includes cash used to settle restricted stock units of $3 million for each of the years 2016, 2015 and 2014. Restricted stock units that are cash settled are classified as liability awards. Share-based liabilities paid relating to performance shares were $16 million in 2015 and $12 million in 2014. In 2016, performance shares were classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees. Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date. Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West. This award vested on December 31, 2016, because he remained employed with the Company through that date. The Board can increase the number of awards that vest, up to an additional 33,745 restricted stock units, payable in stock, if certain performance requirements are met.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Performance Share Awards

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

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

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges 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 Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. See Note 13 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.

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

As of December 31, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):



Commodity	Quantity
Power	1,314	GWh
Gas	194	Billion cubic feet

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 years ended December 31, 2016, 2015 and 2014 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2016			2015			2014
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	47		$	(615	)	$	(372	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(3,926		)	(5,988		)	(21,415		)


(a)	During the years ended December 31, 2016, 2015, and 2014, we had no 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 $3 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2016, 2015 and 2014 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2016		2015			2014
Net Gain Recognized in Income	Operating revenues	$	771	$	574		$	324
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	25,711		(108,973		)	(66,367		)
Total		$	26,482	$	(108,399	)	$	(66,043	)


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

Derivative Instruments in the Consolidated Balance Sheets

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 significant majority of our derivative instruments are not currently designated as hedging instruments. The Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015, include gross liabilities of $2 million and $3 million, respectively, of derivative instruments designated as hedging instruments.

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 December 31, 2016 and 2015. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.



As of December 31, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	48,094		$	(28,400	)	$	19,694		$	—		$	19,694
Investments and other assets	6,704			(6,703		)	1			—			1
Total assets	54,798			(35,103		)	19,695			—			19,695

Current liabilities	(50,182		)	28,400			(21,782		)	(4,054		)	(25,836		)
Deferred credits and other	(53,941		)	6,703			(47,238		)	—			(47,238		)
Total liabilities	(104,123		)	35,103			(69,020		)	(4,054		)	(73,074		)
Total	$	(49,325	)	$	—		$	(49,325	)	$	(4,054	)	$	(53,379	)


(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 $4,054.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



As of December 31, 2015: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	37,396		$	(22,163	)	$	15,233		$	672		$	15,905
Investments and other assets	15,960			(3,854		)	12,106			—			12,106
Total assets	53,356			(26,017		)	27,339			672			28,011

Current liabilities	(113,560		)	40,223			(73,337		)	(4,379		)	(77,716		)
Deferred credits and other	(93,827		)	3,854			(89,973		)	—			(89,973		)
Total liabilities	(207,387		)	44,077			(163,310		)	(4,379		)	(167,689		)
Total	$	(154,031	)	$	18,060		$	(135,971	)	$	(3,707	)	$	(139,678	)


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


(b)	Includes cash collateral provided to counterparties of $18,060.


(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 $4,379, and cash margin provided to counterparties of $672.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2016, we have 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 trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2016 (dollars in thousands):



	December 31, 2016
Aggregate fair value of derivative instruments in a net liability position	$	104,123
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	23,914


(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 $144 million if our debt credit ratings were to fall below investment grade.

Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2016, 2015 and 2014 (dollars in thousands):



	2016			2015			2014
Other income:
Interest income	$	884		$	493		$	1,010
Debt return on the purchase of Four Corners units 4 & 5	—			—			8,386
Miscellaneous	17			128			212
Total other income	$	901		$	621		$	9,608
Other expense:
Non-operating costs	$	(9,235	)	$	(11,292	)	$	(9,657	)
Investment losses — net	(1,747		)	(2,080		)	(9,426		)
Miscellaneous	(4,355		)	(4,451		)	(2,663		)
Total other expense	$	(15,337	)	$	(17,823	)	$	(21,746	)

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2016, 2015 and 2014 (dollars in thousands):



	2016			2015			2014
Other income:
Interest income	$	261		$	163		$	689
Debt return on the purchase of Four Corners units 4 & 5	—			—			8,386
Gain on disposition of property	5,745			716			1,197
Miscellaneous	2,601			1,955			1,023
Total other income	$	8,607		$	2,834		$	11,295
Other expense:
Non-operating costs (a)	$	(11,034	)	$	(11,648	)	$	(10,397	)
Loss on disposition of property	(1,246		)	(2,219		)	(615		)
Miscellaneous	(5,234		)	(5,152		)	(2,391		)
Total other expense	$	(17,514	)	$	(19,019	)	$	(13,403	)

(a)As defined by FERC, includes non-operating utility income and expense (items excluded from utility rate recovery).

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 for the period 2017 through 2023, and about $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 2016, 2015 and 2014 of $19 million, $19 million and $26 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Consolidated Balance Sheets at December 31, 2016 and December 31, 2015 include the following amounts relating to the VIEs (dollars in thousands):



	December 31, 2016		December 31, 2015
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	113,515	$	117,385
Equity-Noncontrolling interests	132,290		135,540

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 million over the lease extension term.

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.

Nuclear Decommissioning Trusts

To fund the 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. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2016 and December 31, 2015 (dollars in thousands):



	Fair Value		Total Unrealized Gains		Total Unrealized Losses
December 31, 2016
Equity securities	$	353,261	$	188,091	$	—
Fixed income securities	425,530		9,820		(4,962		)
Net receivables (a)	795		—		—
Total	$	779,586	$	197,911	$	(4,962	)



	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2015
Equity securities	$	314,957		$	157,098	$	(115	)
Fixed income securities	420,574			11,955		(2,645		)
Net payables (a)	(335		)	—		—
Total	$	735,196		$	169,053	$	(2,760	)


(a)	Net receivables/(payables) relate to pending purchases and sales of securities.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):



	Year Ended December 31,
	2016			2015			2014
Realized gains	$	11,213		$	5,189		$	4,725
Realized losses	(10,106		)	(6,225		)	(4,525		)
Proceeds from the sale of securities (a)	633,410			478,813			356,195


(a)	Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2016 is as follows (dollars in thousands):



	Fair Value
Less than one year	$	13,063
1 year – 5 years	119,292
5 years – 10 years	105,612
Greater than 10 years	187,563
Total	$	425,530

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 years ended December 31, 2016 and 2015 (dollars in thousands):



	Year Ended December 31,
	2016			2015
Balance at beginning of period	$	(44,748	)	$	(68,141	)
Derivative Instruments
OCI (loss) before reclassifications	(538		)	(957		)
Amounts reclassified from accumulated other comprehensive loss (a)	2,941			4,187
Net current period OCI (loss)	2,403			3,230
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	(4,509		)	16,980
Amounts reclassified from accumulated other comprehensive loss (b)	3,032			3,183
Net current period OCI (loss)	(1,477		)	20,163
Balance at end of period	$	(43,822	)	$	(44,748	)


(a)	These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 16.


(b)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Changes in Accumulated Other Comprehensive Loss - APS

The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2016 and 2015 (dollars in thousands):



	Year Ended December 31,
	2016			2015
Balance at beginning of period	$	(27,097	)	$	(48,333	)
Derivative Instruments
OCI (loss) before reclassifications	(538		)	(957		)
Amounts reclassified from accumulated other comprehensive loss (a)	2,941			4,187
Net current period OCI (loss)	2,403			3,230
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	(3,821		)	14,726
Amounts reclassified from accumulated other comprehensive loss (b)	3,092			3,280
Net current period OCI (loss)	(729		)	18,006
Balance at end of period	$	(25,423	)	$	(27,097	)


(a)	These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 16.


(b)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)



	Year Ended December 31,
	2016			2015			2014
Operating revenues	$	370		$	550		$	642
Operating expenses	26,424			12,733			23,507
Operating loss	(26,054		)	(12,183		)	(22,865		)
Other
Equity in earnings of subsidiaries	462,027			446,508			411,528
Other expense	(1,771		)	(3,302		)	(3,276		)
Total	460,256			443,206			408,252
Interest expense	3,151			2,672			3,663
Income before income taxes	431,051			428,351			381,724
Income tax benefit	(10,983		)	(8,906		)	(15,871		)
Net income attributable to common shareholders	442,034			437,257			397,595
Other comprehensive income — attributable to common shareholders	926			23,393			9,912
Total comprehensive income — attributable to common shareholders	$	442,960		$	460,650		$	407,507

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2016			2015
ASSETS
Current assets
Cash and cash equivalents	$	41		$	17,432
Accounts receivable	81,751			93,093
Income tax receivable	—			14,895
Other current assets	340			197
Total current assets	82,132			125,617
Investments and other assets
Investments in subsidiaries	5,084,035			4,815,236
Deferred income taxes	53,805			41,065
Other assets	38,500			43,422
Total investments and other assets	5,176,340			4,899,723
Total Assets	$	5,258,472		$	5,025,340
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	5,421		$	5,901
Accrued taxes	12,050			6,904
Common dividends payable	72,926			69,363
Short-term borrowings	41,700			—
Current maturities of long-term debt	125,000			—
Other current liabilities	31,182			33,120
Total current liabilities	288,279			115,288

Long-term debt less current maturities	—			125,000

Pension liabilities	21,057			21,933
Other	13,224			43,662
Total deferred credits and other	34,281			65,595
Common stock equity
Common stock	2,591,897			2,535,862
Accumulated other comprehensive loss	(43,822		)	(44,748		)
Retained earnings	2,255,547			2,092,803
Total Pinnacle West Shareholders’ equity	4,803,622			4,583,917
Noncontrolling interests	132,290			135,540
Total Equity	4,935,912			4,719,457
Total Liabilities and Equity	$	5,258,472		$	5,025,340

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)



	Year Ended December 31,
	2016			2015			2014
Cash flows from operating activities
Net income	$	442,034		$	437,257		$	397,595
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(462,027		)	(446,508		)	(411,528		)
Depreciation and amortization	85			92			94
Deferred income taxes	(12,402		)	12,967			4,406
Accounts receivable	15,823			11,336			(22,945		)
Accounts payable	10,402			637			2,017
Accrued taxes and income tax receivables — net	20,041			(12,882		)	(1,795		)
Dividends received from subsidiaries	239,300			266,900			253,600
Other	5,514			(6,995		)	18,432
Net cash flow provided by operating activities	258,770			262,804			239,876
Cash flows from investing activities
Construction work in progress	(18,457		)	(3,462		)	—
Investments in subsidiaries	(19,242		)	(3,491		)	(10,236		)
Repayments of loans from subsidiaries	1,026			157			322
Advances of loans to subsidiaries	(2,092		)	(1,010		)	(1,450		)
Net cash flow used for investing activities	(38,765		)	(7,806		)	(11,364		)
Cash flows from financing activities
Issuance of long-term debt	—			—			125,000
Short-term debt borrowings under revolving credit facility	40,000			—			—
Commercial Paper - net	1,700			—			—
Dividends paid on common stock	(274,229		)	(260,027		)	(246,671		)
Repayment of long-term debt	—			—			(125,000		)
Common stock equity issuance - net of purchases	(4,867		)	19,373			15,288
Other	—			—			161
Net cash flow used for financing activities	(237,396		)	(240,654		)	(231,222		)
Net increase (decrease) in cash and cash equivalents	(17,391		)	14,344			(2,710		)
Cash and cash equivalents at beginning of year	17,432			3,088			5,798
Cash and cash equivalents at end of year	$	41		$	17,432		$	3,088

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of the Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

PINNACLE WEST CAPITAL CORPORATION

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)



Column A	Column B		Column C				Column D		Column E
			Additions
Description	Balance at beginning of period		Charged to cost and expenses		Charged to other accounts		Deductions		Balance at end of period
Reserve for uncollectibles:
2016	$	3,125	$	4,025	$	—	$	4,113	$	3,037
2015	3,094		4,073		—		4,042		3,125
2014	3,203		3,942		—		4,051		3,094

ARIZONA PUBLIC SERVICE COMPANY

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)



Column A	Column B		Column C				Column D		Column E
			Additions
Description	Balance at beginning of period		Charged to cost and expenses		Charged to other accounts		Deductions		Balance at end of period
Reserve for uncollectibles:
2016	$	3,125	$	4,025	$	—	$	4,113	$	3,037
2015	3,094		4,073		—		4,042		3,125
2014	3,203		3,942		—		4,051		3,094

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