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)	74
Report of Independent Registered Public Accounting Firm	75
Pinnacle West Consolidated Statements of Income for 2015, 2014 and 2013	77
Pinnacle West Consolidated Statements of Comprehensive Income for 2015, 2014, and 2013	78
Pinnacle West Consolidated Balance Sheets as of December 31, 2015 and 2014	79
Pinnacle West Consolidated Statements of Cash Flows for 2015, 2014 and 2013	81
Pinnacle West Consolidated Statements of Changes in Equity for 2015, 2014 and 2013	82

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)	83
Report of Independent Registered Public Accounting Firm	84
APS Consolidated Statements of Income for 2015, 2014 and 2013	86
APS Consolidated Statements of Comprehensive Income for 2015, 2014 and 2013	87
APS Consolidated Balance Sheets as of December 31, 2015 and 2014	88
APS Consolidated Statements of Cash Flows for 2015, 2014 and 2013	90
APS Consolidated Statements of Changes in Equity for 2015, 2014 and 2013	91

Combined Notes to Consolidated Financial Statements	92
Note 1. Summary of Significant Accounting Policies	92
Note 2. New Accounting Standards	98
Note 3. Regulatory Matters	99
Note 4. Income Taxes	107
Note 5. Lines of Credit and Short-Term Borrowings	112
Note 6. Long-Term Debt and Liquidity Matters	113
Note 7. Retirement Plans and Other Postretirement Benefits	116
Note 8. Leases	125
Note 9. Jointly-Owned Facilities	126
Note 10. Commitments and Contingencies	126
Note 11. Asset Retirement Obligations	135
Note 12. Selected Quarterly Financial Data (Unaudited)	136
Note 13. Fair Value Measurements	137
Note 14. Earnings Per Share	144
Note 15. Stock-Based Compensation	144
Note 16. Derivative Accounting	147
Note 17. Other Income and Other Expense	152
Note 18. Palo Verde Sale Leaseback Variable Interest Entities	152
Note 19. Nuclear Decommissioning Trusts	154
Note 20. Changes in Accumulated Other Comprehensive Loss	155

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, 2015. The effectiveness of our internal control over financial reporting as of December 31, 2015 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 19, 2016

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, 2015 and 2014, 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, 2015. 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, 2015, 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, 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 19, 2016

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

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



	Year Ended December 31,
	2015			2014			2013

OPERATING REVENUES	$	3,495,443		$	3,491,632		$	3,454,628
OPERATING EXPENSES
Fuel and purchased power	1,101,298			1,179,829			1,095,709
Operations and maintenance	868,377			908,025			924,727
Depreciation and amortization	494,422			417,358			415,708
Taxes other than income taxes	171,812			172,295			164,167
Other expenses	4,932			2,883			7,994
Total	2,640,841			2,680,390			2,608,305
OPERATING INCOME	854,602			811,242			846,323
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	35,215			30,790			25,581
Other income (Note 17)	621			9,608			1,704
Other expense (Note 17)	(17,823		)	(21,746		)	(16,024		)
Total	18,013			18,652			11,261
INTEREST EXPENSE
Interest charges	194,964			200,950			201,888
Allowance for borrowed funds used during construction (Note 1)	(16,259		)	(15,457		)	(14,861		)
Total	178,705			185,493			187,027
INCOME BEFORE INCOME TAXES	693,910			644,401			670,557
INCOME TAXES (Note 4)	237,720			220,705			230,591
NET INCOME	456,190			423,696			439,966
Less: Net income attributable to noncontrolling interests (Note 18)	18,933			26,101			33,892
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	437,257		$	397,595		$	406,074

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	111,026			110,626			109,984
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	111,552			111,178			110,806

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	3.94		$	3.59		$	3.69
Net income attributable to common shareholders — diluted	$	3.92		$	3.58		$	3.66

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,
	2015			2014			2013

NET INCOME	$	456,190		$	423,696		$	439,966

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $(342), $(438), and $140 (Note 16)	(957		)	(810		)	(213		)
Reclassification of net realized loss, net of tax benefit of $1,801, $7,932 and $17,472 (Note 16)	4,187			13,483			26,747
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(13,302), $1,307, and $(6,156) (Note 7)	20,163			(2,761		)	9,421
Total other comprehensive income	23,393			9,912			35,955

COMPREHENSIVE INCOME	479,583			433,608			475,921
Less: Comprehensive income attributable to noncontrolling interests	18,933			26,101			33,892

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	460,650		$	407,507		$	442,029

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2015			2014
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	39,488		$	7,604
Customer and other receivables	274,691			297,740
Accrued unbilled revenues	96,240			100,533
Allowance for doubtful accounts	(3,125		)	(3,094		)
Materials and supplies (at average cost)	234,234			218,889
Fossil fuel (at average cost)	45,697			37,097
Deferred income taxes (Note 4)	—			122,232
Income tax receivable (Note 4)	589			3,098
Assets from risk management activities (Note 16)	15,905			13,785
Deferred fuel and purchased power regulatory asset (Note 3)	—			6,926
Other regulatory assets (Note 3)	149,555			129,808
Other current assets	37,242			38,817
Total current assets	890,516			973,435
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	12,106			17,620
Nuclear decommissioning trust (Notes 13 and 19)	735,196			713,866
Other assets	52,518			54,047
Total investments and other assets	799,820			785,533
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	16,222,232			15,543,063
Accumulated depreciation and amortization	(5,594,094		)	(5,397,751		)
Net	10,628,138			10,145,312
Construction work in progress	816,307			682,807
Palo Verde sale leaseback, net of accumulated depreciation of $233,665 and $229,795 (Note 18)	117,385			121,255
Intangible assets, net of accumulated amortization of $546,038 and $489,538	123,975			119,755
Nuclear fuel, net of accumulated amortization of $146,228 and $143,554	123,139			125,201
Total property, plant and equipment	11,808,944			11,194,330
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,214,146			1,054,087
Assets for other postretirement benefits (Note 7)	185,997			152,290
Other	128,835			129,215
Total deferred debits	1,528,978			1,335,592
TOTAL ASSETS	$	15,028,258		$	14,288,890

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2015			2014
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	297,480		$	295,211
Accrued taxes (Note 4)	138,600			140,613
Accrued interest	56,305			52,603
Common dividends payable	69,363			65,790
Short-term borrowings (Note 5)	—			147,400
Current maturities of long-term debt (Note 6)	357,580			383,570
Customer deposits	73,073			72,307
Liabilities from risk management activities (Note 16)	77,716			59,676
Liabilities for asset retirements (Note 11)	28,573			32,462
Deferred fuel and purchased power regulatory liability (Note 3)	9,688			—
Other regulatory liabilities (Note 3)	136,078			130,549
Other current liabilities	197,861			178,962
Total current liabilities	1,442,317			1,559,143
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	3,462,391			3,006,573
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	2,723,425			2,582,636
Regulatory liabilities (Notes 1, 3, 4 and 7)	994,152			1,051,196
Liabilities for asset retirements (Note 11)	415,003			358,288
Liabilities for pension benefits (Note 7)	480,998			453,736
Liabilities from risk management activities (Note 16)	89,973			50,602
Customer advances	115,609			123,052
Coal mine reclamation	201,984			198,292
Deferred investment tax credit	187,080			178,607
Unrecognized tax benefits (Note 4)	9,524			19,377
Other	186,345			188,286
Total deferred credits and other	5,404,093			5,204,072
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,095,402 and 110,649,762 issued at respective dates	2,541,668			2,512,970
Treasury stock at cost; 115,030 shares at end of 2015 and 78,400 shares at end of 2014	(5,806		)	(3,401		)
Total common stock	2,535,862			2,509,569
Retained earnings	2,092,803			1,926,065
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 7)	(37,593		)	(57,756		)
Derivative instruments (Note 16)	(7,155		)	(10,385		)
Total accumulated other comprehensive loss	(44,748		)	(68,141		)
Total shareholders’ equity	4,583,917			4,367,493
Noncontrolling interests (Note 18)	135,540			151,609
Total equity	4,719,457			4,519,102
TOTAL LIABILITIES AND EQUITY	$	15,028,258		$	14,288,890

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,
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	456,190		$	423,696		$	439,966
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	571,664			496,487			492,322
Deferred fuel and purchased power	14,997			(26,927		)	21,678
Deferred fuel and purchased power amortization	1,617			40,757			31,190
Allowance for equity funds used during construction	(35,215		)	(30,790		)	(25,581		)
Deferred income taxes	236,819			159,023			249,296
Deferred investment tax credit	8,473			26,246			52,542
Change in derivative instruments fair value	(381		)	339			534
Changes in current assets and liabilities:
Customer and other receivables	(22,219		)	(52,672		)	(44,991		)
Accrued unbilled revenues	4,293			(3,737		)	(1,951		)
Materials, supplies and fossil fuel	(23,945		)	3,724			(11,878		)
Income tax receivable	2,509			132,419			(133,094		)
Other current assets	3,145			4,384			(17,913		)
Accounts payable	(34,266		)	(353		)	45,414
Accrued taxes	(2,013		)	9,615			6,059
Other current liabilities	603			17,892			(7,513		)
Change in margin and collateral accounts — assets	(324		)	(343		)	993
Change in margin and collateral accounts — liabilities	22,776			(24,975		)	12,355
Change in long-term income tax receivable	—			—			137,270
Change in unrecognized tax benefits	(10,328		)	2,778			(91,425		)
Change in long-term regulatory liabilities	(20,535		)	59,618			64,473
Change in other long-term assets	2,426			(56,561		)	(42,389		)
Change in other long-term liabilities	(81,959		)	(80,993		)	(24,050		)
Net cash flow provided by operating activities	1,094,327			1,099,627			1,153,307
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,076,087		)	(910,634		)	(1,016,322		)
Contributions in aid of construction	46,546			20,325			41,090
Allowance for borrowed funds used during construction	(16,259		)	(15,457		)	(14,861		)
Proceeds from nuclear decommissioning trust sales	478,813			356,195			446,025
Investment in nuclear decommissioning trust	(496,062		)	(373,444		)	(463,274		)
Other	(3,184		)	347			(2,059		)
Net cash flow used for investing activities	(1,066,233		)	(922,668		)	(1,009,401		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	842,415			731,126			136,307
Repayment of long-term debt	(415,570		)	(652,578		)	(122,828		)
Short-term borrowings and payments — net	(147,400		)	(5,725		)	60,950
Dividends paid on common stock	(260,027		)	(246,671		)	(235,244		)
Common stock equity issuance - net of purchases	19,373			15,288			17,319
Distributions to noncontrolling interests	(35,002		)	(20,482		)	(17,385		)
Other	1			161			299
Net cash flow provided by (used for) financing activities	3,790			(178,881		)	(160,582		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	31,884			(1,922		)	(16,676		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	7,604			9,526			26,202
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	39,488		$	7,604		$	9,526

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, 2012	109,837,957	$	2,466,923	(95,192	)	$	(4,211	)	$	1,624,102		$	(114,008	)	$	129,483		$	4,102,289

Net income		—				—			406,074			—			33,892			439,966
Other comprehensive income		—				—			—			35,955			—			35,955
Dividends on common stock ($2.23 per share)		—				—			(244,903		)	—			—			(244,903		)
Issuance of common stock	442,746	24,635				—			—			—			—			24,635
Purchase of treasury stock (a)		—		(174,290	)	(9,727		)	—			—			—			(9,727		)
Reissuance of treasury stock for stock-based compensation and other		—		170,538		9,630			—			—			—			9,630
Net capital activities by noncontrolling interests		—				—			—			—			(17,385		)	(17,385		)
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

(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, 2015. The effectiveness of our internal control over financial reporting as of December 31, 2015 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 19, 2016

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, 2015 and 2014, 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, 2015. 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, 2015, 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, 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 19, 2016

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)



	Year Ended December 31,
	2015			2014			2013

ELECTRIC OPERATING REVENUES	$	3,492,357		$	3,488,946		$	3,451,251

OPERATING EXPENSES
Fuel and purchased power	1,101,298			1,179,829			1,095,709
Operations and maintenance	853,135			882,442			897,824
Depreciation and amortization	494,298			417,264			415,612
Income taxes (Note 4)	260,143			245,036			256,864
Taxes other than income taxes	171,499			171,583			163,377
Total	2,880,373			2,896,154			2,829,386
OPERATING INCOME	611,984			592,792			621,865

OTHER INCOME (DEDUCTIONS)
Income taxes (Note 4)	14,302			7,676			11,769
Allowance for equity funds used during construction (Note 1)	35,215			30,790			25,581
Other income (Note 17)	2,834			11,295			3,896
Other expense (Note 17)	(19,019		)	(13,403		)	(20,449		)
Total	33,332			36,358			20,797

INTEREST EXPENSE
Interest on long-term debt	180,123			186,323			188,011
Interest on short-term borrowings	7,376			6,796			6,605
Debt discount, premium and expense	4,793			4,168			4,046
Allowance for borrowed funds used during construction (Note 1)	(16,183		)	(15,457		)	(14,861		)
Total	176,109			181,830			183,801

NET INCOME	469,207			447,320			458,861

Less: Net income attributable to noncontrolling interests (Note 18)	18,933			26,101			33,892

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	450,274		$	421,219		$	424,969

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,
	2015			2014			2013

NET INCOME	$	469,207		$	447,320		$	458,861

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $(342), $(438), and $140 (Note 16)	(957		)	(809		)	(214		)
Reclassification of net realized loss, net of tax benefit of $1,801, $7,932, and $17,472 (Note 16)	4,187			13,483			26,747
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(11,776), $4,655, and $(6,003) (Note 7)	18,006			(7,635		)	9,190
Total other comprehensive income	21,236			5,039			35,723

COMPREHENSIVE INCOME	490,443			452,359			494,584
Less: Comprehensive income attributable to noncontrolling interests	18,933			26,101			33,892

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	471,510		$	426,258		$	460,692

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2015			2014
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	$	16,218,724		$	15,539,811
Accumulated depreciation and amortization	(5,590,937		)	(5,394,650		)
Net	10,627,787			10,145,161
Construction work in progress	812,845			682,807
Palo Verde sale leaseback, net of accumulated depreciation of $233,665 and $229,795 (Note 18)	117,385			121,255
Intangible assets, net of accumulated amortization of $546,038 and $489,538	123,820			119,600
Nuclear fuel, net of accumulated amortization of $146,228 and $143,554	123,139			125,201
Total property, plant and equipment	11,804,976			11,194,024
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 13 and 19)	735,196			713,866
Assets from risk management activities (Note 16)	12,106			17,620
Other assets	34,455			33,362
Total investments and other assets	781,757			764,848
CURRENT ASSETS
Cash and cash equivalents	22,056			4,515
Customer and other receivables	274,428			297,712
Accrued unbilled revenues	96,240			100,533
Allowance for doubtful accounts	(3,125		)	(3,094		)
Materials and supplies (at average cost)	234,234			218,889
Fossil fuel (at average cost)	45,697			37,097
Assets from risk management activities (Note 16)	15,905			13,785
Deferred fuel and purchased power regulatory asset (Note 3)	—			6,926
Other regulatory assets (Note 3)	149,555			129,808
Deferred income taxes (Note 4)	—			55,253
Other current assets	35,765			38,693
Total current assets	870,755			900,117
DEFERRED DEBITS
Regulatory assets (Notes 1, 3, and 4)	1,214,146			1,054,087
Assets for other postretirement benefits (Note 7)	182,625			149,260
Other	127,923			128,026
Total deferred debits	1,524,694			1,331,373
TOTAL ASSETS	$	14,982,182		$	14,190,362

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2015			2014
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	2,148,493			1,968,718
Accumulated other comprehensive (loss):
Pension and other postretirement benefits (Note 7)	(19,942		)	(37,948		)
Derivative instruments (Note 16)	(7,155		)	(10,385		)
Total shareholder equity	4,679,254			4,478,243
Noncontrolling interests (Note 18)	135,540			151,609
Total equity	4,814,794			4,629,852
Long-term debt less current maturities (Note 6)	3,337,391			2,881,573
Total capitalization	8,152,185			7,511,425
CURRENT LIABILITIES
Short-term borrowings (Note 5)	—			147,400
Current maturities of long-term debt (Note 6)	357,580			383,570
Accounts payable	291,574			289,930
Accrued taxes (Note 4)	144,488			131,110
Accrued interest	56,003			52,358
Common dividends payable	69,400			65,800
Customer deposits	73,073			72,307
Liabilities from risk management activities (Note 16)	77,716			59,676
Liabilities for asset retirements (Note 11)	28,573			32,462
Deferred fuel and purchased power regulatory liability (Note 3)	9,688			—
Other regulatory liabilities (Note 3)	136,078			130,549
Other current liabilities	180,535			167,302
Total current liabilities	1,424,708			1,532,464
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	2,764,489			2,571,365
Regulatory liabilities (Notes 1, 3, and 4)	994,152			1,051,196
Liabilities for asset retirements (Note 11)	415,003			358,288
Liabilities for pension benefits (Note 7)	459,065			424,508
Liabilities from risk management activities (Note 16)	89,973			50,602
Customer advances	115,609			123,052
Coal mine reclamation	201,984			198,292
Deferred investment tax credit	187,080			178,607
Unrecognized tax benefits (Note 4)	35,251			45,740
Other	142,683			144,823
Total deferred credits and other	5,405,289			5,146,473
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	14,982,182		$	14,190,362

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,
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	469,207		$	447,320		$	458,861
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	571,540			496,393			492,226
Deferred fuel and purchased power	14,997			(26,927		)	21,678
Deferred fuel and purchased power amortization	1,617			40,757			31,190
Allowance for equity funds used during construction	(35,215		)	(30,790		)	(25,581		)
Deferred income taxes	223,069			155,401			278,101
Deferred investment tax credit	8,473			26,246			52,542
Change in derivative instruments fair value	(381		)	339			534
Changes in current assets and liabilities:
Customer and other receivables	(21,040		)	(52,466		)	(46,552		)
Accrued unbilled revenues	4,293			(3,737		)	(1,951		)
Materials, supplies and fossil fuel	(23,945		)	3,724			(11,878		)
Income tax receivable	—			135,179			(134,590		)
Other current assets	4,498			3,766			(17,112		)
Accounts payable	(34,891		)	(2,355		)	47,870
Accrued taxes	13,378			8,650			5,760
Other current liabilities	(3,718		)	33,970			(9,005		)
Change in margin and collateral accounts — assets	(324		)	(343		)	993
Change in margin and collateral accounts — liabilities	22,776			(24,975		)	12,355
Change in long-term regulatory liabilities	(20,535		)	59,618			64,473
Change in long-term income tax receivable	—			—			137,665
Change in unrecognized tax benefits	(10,328		)	2,778			(91,244		)
Change in other long-term assets	(813		)	(62,739		)	(46,675		)
Change in other long-term liabilities	(82,628		)	(85,642		)	(24,969		)
Net cash flow provided by operating activities	1,100,030			1,124,167			1,194,691
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,072,053		)	(910,084		)	(1,016,322		)
Contributions in aid of construction	46,546			20,325			41,090
Allowance for borrowed funds used during construction	(16,183		)	(15,457		)	(14,861		)
Proceeds from nuclear decommissioning trust sales	478,813			356,195			446,025
Investment in nuclear decommissioning trust	(496,062		)	(373,444		)	(463,274		)
Other	(1,093		)	347			(2,067		)
Net cash flow used for investing activities	(1,060,032		)	(922,118		)	(1,009,409		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	842,415			606,126			136,307
Repayment of long-term debt	(415,570		)	(527,578		)	(122,828		)
Short-term borrowings and payments — net	(147,400		)	(5,725		)	60,950
Dividends paid on common stock	(266,900		)	(253,600		)	(242,100		)
Noncontrolling interests	(35,002		)	(20,482		)	(17,385		)
Net cash flow used for financing activities	(22,457		)	(201,259		)	(185,056		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	17,541			790			226
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	4,515			3,725			3,499
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	22,056		$	4,515		$	3,725
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Income taxes, net of refunds	$	14,831		$	(86,054	)	$	7,524
Interest, net of amounts capitalized	167,670			173,436			180,757
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	83,798		$	44,712		$	33,184
Dividends declared but not paid	69,400			65,800			62,500
Liabilities assumed related to acquisition of SCE’s Four Corners’ interest	—			—			145,609

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, 2012	71,264,947	$	178,162	$	2,379,696	$	1,624,237		$	(89,095	)	$	129,483		$	4,222,483

Net income		—		—		424,969			—			33,892			458,861
Other comprehensive income		—		—		—			35,723			—			35,723
Dividends on common stock		—		—		(244,800		)	—			—			(244,800		)
Other		—		—		(8		)	—			—			(8		)
Net capital activities by noncontrolling interests		—		—		—			—			(17,385		)	(17,385		)
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

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, and BCE. 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.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado and BCE. 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.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West’s property, plant and equipment included in the December 31, 2015 and 2014 consolidated balance sheets is composed of the following (dollars in thousands):



Property, Plant and Equipment:	2015			2014
Generation	$	7,336,902		$	7,158,729
Transmission	2,494,744			2,247,309
Distribution	5,543,561			5,339,322
General plant	847,025			797,703
Plant in service and held for future use	16,222,232			15,543,063
Accumulated depreciation and amortization	(5,594,094		)	(5,397,751		)
Net	10,628,138			10,145,312
Construction work in progress	816,307			682,807
Palo Verde sale leaseback, net of accumulated depreciation	117,385			121,255
Intangible assets, net of accumulated amortization	123,975			119,755
Nuclear fuel, net of accumulated amortization	123,139			125,201
Total property, plant and equipment	$	11,808,944		$	11,194,330

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-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, 2015 were as follows:

Fossil plant — 19 years;
Nuclear plant — 28 years;
Other generation — 25 years;
Transmission — 39 years;
Distribution — 33 years; and
Other — 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $430 million in 2015, $396 million in 2014, and $400 million in 2013. For the years 2013 through 2015, the depreciation rates ranged from a low of 0.30% to a high of 12.37%. The weighted-average depreciation rate was 2.74% in 2015, 2.77% in 2014, and 3.00% in 2013.

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 8.02% for 2015, 8.47% for 2014, and 8.56% for 2013. 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.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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



	Year ended December 31,
	2015		2014			2013
Cash paid (received) during the period for:
Income taxes, net of refunds	$	6,550	$	(102,154	)	$	18,537
Interest, net of amounts capitalized	170,209		177,074			184,010
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	83,798	$	44,712		$	33,184
Dividends declared but not paid	69,363		65,790			62,528
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)	—		—			145,609

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 2015, $53 million in 2014, and $53 million in 2013. Estimated amortization expense on existing intangible assets over the next five years is $48 million in 2016, $36 million in 2017, $18 million in 2018, $9 million in 2019, and $3 million in 2020. At December 31, 2015, the weighted-average remaining amortization period for intangible assets was 5 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).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2015, 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.

New Accounting Standards

In May 2014, new revenue recognition guidance was issued. This guidance 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. The new revenue standard will be effective for us on January 1, 2018. The guidance 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 are currently evaluating this new guidance and the impacts it may have on our financial statements.

In February 2015, new consolidation accounting guidance was issued that amends many aspects of the guidance relating to the analysis and consolidation of variable interest entities. The new guidance is effective for us, and will be adopted, during the first quarter of 2016; and may be adopted using either a full retrospective or modified retrospective approach. We do not expect the adoption of this guidance to have a material impact on our financial statements.

In January 2016, new guidance was issued relating to the recognition and measurement of financial instruments. The amended 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 guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

During the fourth quarter of 2015 we elected to early adopt the following accounting standard updates:


•	Balance sheet presentation of deferred income taxes. See Note 4.


•	Balance sheet presentation of debt issuance costs: Adopted on a retrospective basis, the new guidance requires debt issuance costs to be presented on the balance sheets as a direct reduction to the related debt liabilities. Prior to the adoption of this guidance we were required to present debt issuance costs as an asset on the balance sheets. As a result of adopting this guidance, our December 31, 2015 Consolidated Balance Sheet includes $28 million of debt issuance costs as a reduction to our long-term

•

Balance sheet presentation of debt issuance costs: Adopted on a retrospective basis, the new guidance requires debt issuance costs to be presented on the balance sheets as a direct reduction to the related debt liabilities. Prior to the adoption of this guidance we were required to present debt issuance costs as an asset on the balance sheets. As a result of adopting this guidance, our December 31, 2015 Consolidated Balance Sheet includes $28 million of debt issuance costs as a reduction to our long-term

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

debt. Our December 31, 2014 Consolidated Balance Sheet presents $25 million of debt issuance costs as a reduction to long-term debt; this amount was previously presented as a component of non-current other deferred debits. The adoption of this guidance did not impact our results of operations or cash flows. Debt issuance costs continue to be amortized as interest expense. See Note 6.

Regulatory Matters

Retail Rate Case Filings with the Arizona Corporation Commission

Upcoming Rate Case Filing

On January 29, 2016, APS filed a NOI informing the ACC that APS intends to submit a rate case application in June 2016 using an adjusted test year ending December 31, 2015. The NOI provides an overview of the key issues APS expects to address in its formal request such as rate design changes (residential, commercial and industrial), a decoupling mechanism, permission to defer for potential future recovery costs associated with the Company’s Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items. In its rate application, APS will request that its proposed pricing changes take effect in July 2017. APS is still developing the exact amount of the request.

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;


•	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:

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


•	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 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 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 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.

In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program, called the "Solar Partner Program", is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the requested budget to approximately $152 million.

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.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan for review by and approval of the ACC.

On June 1, 2012, APS filed its 2013 DSM Plan. In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan. The ACC approved a budget of $68.9 million for each of 2013 and 2014. The ACC also 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. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.

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. A formal rulemaking has not been initiated and there has been no additional action on the draft to date.

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);


•	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 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2015 and 2014 (dollars in thousands):



	Year Ended December 31,
	2015			2014
Beginning balance	$	6,926		$	20,755
Deferred fuel and purchased power costs - current period	(14,997		)	26,927
Amounts charged to customers	(1,617		)	(40,756		)
Ending balance	$	(9,688	)	$	6,926

The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year. This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh. On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.

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, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 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, 2014.

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 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 such as APS to make changes to their protocols in the future.

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 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014. The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. 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.

Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electric grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electric grid. The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.

On October 20, 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 has been scheduled to commence in April 2016. APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS has also requested intervention in the upcoming Tucson Electric Power Company rate case. The outcomes of these proceedings will not directly impact our financial position.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 oral argument is set for March 22, 2016. If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS 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 $70 million as of December 31, 2015 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 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 has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. 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. APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group. However, this alternative arrangement was not approved by FERC. 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 has established a regulatory asset of $12 million at December 31, 2015 in connection with the expiration of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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 plans to seek recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its next retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($122 million as of December 31, 2015), 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.

Regulatory Assets and Liabilities

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



	Amortization Through	December 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	619,223	$	—	$	485,037
Retired power plant costs	2033	9,913		127,518		9,913		136,182
Income taxes - AFUDC equity	2045	5,495		133,712		4,813		118,396
Deferred fuel and purchased power — mark-to-market (Note 16)	2018	71,852		69,697		51,209		46,233
Four Corners cost deferral	2024	6,689		63,582		6,689		70,565
Income taxes — investment tax credit basis adjustment	2045	1,766		48,462		1,716		46,200
Lost fixed cost recovery	2016	45,507		—		37,612		—
Palo Verde VIEs (Note 18)	2046	—		18,143		—		34,440
Deferred compensation	2036	—		34,751		—		34,162
Deferred property taxes	(d)	—		50,453		—		30,283
Loss on reacquired debt	2034	1,515		16,375		1,435		16,410
Tax expense of Medicare subsidy	2024	1,520		12,163		1,528		13,756
Transmission vegetation management	2016	4,543		—		9,086		4,543
Mead-Phoenix transmission line CIAC	2050	332		11,040		332		11,372
Deferred fuel and purchased power (b) (c)	2015	—		—		6,926		—
Coal reclamation	2026	418		6,085		418		6,503
Pension and other postretirement benefits deferral	2015	—		—		4,238		—
Other	Various	5		2,942		819		5
Total regulatory assets (e)		$	149,555	$	1,214,146	$	136,734	$	1,054,087


(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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(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.”

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



	Amortization Through	December 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Asset retirement obligations	2057	$	—	$	277,554	$	—	$	295,546
Removal costs	(a)	39,746		240,367		31,033		272,825
Other postretirement benefits	(d)	34,100		179,521		32,317		198,599
Income taxes — deferred investment tax credit	2045	3,604		97,175		3,505		92,727
Income taxes - change in rates	2045	1,113		72,454		371		72,423
Spent nuclear fuel	2047	3,051		67,437		4,396		65,594
Renewable energy standard (b)	2017	43,773		4,365		24,596		22,677
Demand side management (b)	2017	6,079		19,115		31,335		—
Sundance maintenance	2030	—		13,678		—		12,069
Deferred fuel and purchased power (b) (c)	2016	9,688		—		—		—
Deferred gains on utility property	2019	2,062		6,001		2,062		8,001
Four Corners coal reclamation	2031	—		8,920		—		1,200
Other	Various	2,550		7,565		934		9,535
Total regulatory liabilities		$	145,766	$	994,152	$	130,549	$	1,051,196


(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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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
	2015			2014			2013			2015			2014			2013
Total unrecognized tax benefits, January 1	$	44,775		$	41,997		$	133,422		$	44,775		$	41,997		$	133,241
Additions for tax positions of the current year	2,175			4,309			3,516			2,175			4,309			3,516
Additions for tax positions of prior years	—			751			13,158			—			751			13,158
Reductions for tax positions of prior years for:
Changes in judgment	(10,244		)	(2,282		)	(108,099		)	(10,244		)	(2,282		)	(107,918		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	(2,259		)	—			—			(2,259		)	—			—
Total unrecognized tax benefits, December 31	$	34,447		$	44,775		$	41,997		$	34,447		$	44,775		$	41,997

During the year ended December 31, 2013, Internal Revenue Service ("IRS") guidance was released which provided clarification regarding an APS tax accounting method change approved by the IRS in the third quarter of 2009. As a result of this guidance, uncertain tax positions decreased $67 million. Additionally, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, which further reduced uncertain tax positions by approximately $41 million. These reductions in uncertain tax positions, materially offset by an increase in deferred tax liabilities, resulted in a cash refund that was received in the first quarter of 2014.

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
	2015		2014		2013		2015		2014		2013
Tax positions, that if recognized, would decrease our effective tax rate	$	9,523	$	11,207	$	9,827	$	9,523	$	11,207	$	9,827

As of the balance sheet date, the tax year ended December 31, 2012 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 2011.

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
	2015			2014		2013			2015			2014		2013
Unrecognized tax benefit interest expense/(benefit) recognized	$	(161	)	$	752	$	(3,716	)	$	(161	)	$	752	$	(3,716	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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
	2015		2014		2013		2015		2014		2013
Unrecognized tax benefit interest accrued	$	804	$	965	$	213	$	804	$	965	$	213

Additionally, as of December 31, 2015, 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.

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,
	2015			2014		2013			2015		2014		2013
Current:
Federal	$	(12,335	)	$	25,054	$	(81,784	)	$	6,485	$	40,115	$	(97,531	)
State	4,763			10,382		10,537			7,813		15,598		11,983
Total current	(7,572		)	35,436		(71,247		)	14,298		55,713		(85,548		)
Deferred:
Federal	221,505			167,365		279,973			208,326		165,027		305,389
State	23,787			17,904		21,865			23,217		16,620		25,254
Total deferred	245,292			185,269		301,838			231,543		181,647		330,643
Income tax expense	$	237,720		$	220,705	$	230,591		$	245,841	$	237,360	$	245,095

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2015			2014			2013			2015			2014			2013
Federal income tax expense at 35% statutory rate	$	242,869		$	225,540		$	234,695		$	250,267		$	239,638		$	246,384
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	18,265			18,149			21,387			20,433			21,148			23,970
Credits and favorable adjustments related to prior years resolved in current year	(2,169		)	—			(3,356		)	(1,892		)	—			(3,231		)
Medicare Subsidy Part-D	837			830			823			837			830			823
Allowance for equity funds used during construction (see Note 1)	(9,711		)	(8,523		)	(6,997		)	(9,711		)	(8,523		)	(6,997		)
Palo Verde VIE noncontrolling interest (see Note 18)	(6,626		)	(9,135		)	(11,862		)	(6,626		)	(9,135		)	(11,862		)
Investment tax credit amortization	(5,527		)	(4,928		)	(3,548		)	(5,527		)	(4,928		)	(3,548		)
Other	(218		)	(1,228		)	(551		)	(1,940		)	(1,670		)	(444		)
Income tax expense	$	237,720		$	220,705		$	230,591		$	245,841		$	237,360		$	245,095

During the fourth quarter of 2015, we prospectively adopted guidance requiring deferred income tax assets and liabilities to be presented as non-current on the balance sheet and eliminating the requirement to present a current portion. As a result of this guidance all deferred income tax assets and liabilities are presented as net non-current deferred income tax liabilities on the Consolidated Balance Sheet as of December 31, 2015. Prior periods have not been restated.

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):



	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2015			2014			2015			2014
Current asset	$	—		$	122,232		$	—		$	55,253
Long-term liability	(2,723,425		)	(2,582,636		)	(2,764,489		)	(2,571,365		)
Deferred income taxes — net	$	(2,723,425	)	$	(2,460,404	)	$	(2,764,489	)	$	(2,516,112	)

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, 2015, APS has recorded a regulatory liability of $75 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 has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2015, 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,
	2015			2014			2015			2014
DEFERRED TAX ASSETS
Risk management activities	$	70,498		$	57,505		$	70,498		$	57,505
Regulatory liabilities:
Asset retirement obligation and removal costs	216,765			229,772			216,765			229,772
Unamortized investment tax credits	100,779			96,232			100,779			96,232
Other postretirement benefits	83,034			90,496			83,034			90,496
Other	60,707			60,409			60,707			60,409
Pension liabilities	191,028			205,227			181,787			194,541
Renewable energy incentives	60,956			65,169			60,956			65,169
Credit and loss carryforwards	59,557			68,347			—			—
Other	149,033			138,729			176,016			161,379
Total deferred tax assets	992,357			1,011,886			950,542			955,503
DEFERRED TAX LIABILITIES
Plant-related	(3,116,752		)	(2,958,369		)	(3,116,752		)	(2,958,369		)
Risk management activities	(10,626		)	(12,171		)	(10,626		)	(12,171		)
Other postretirement assets	(71,737		)	(59,170		)	(70,986		)	(58,495		)
Regulatory assets:
Allowance for equity funds used during construction	(54,110		)	(48,286		)	(54,110		)	(48,286		)
Deferred fuel and purchased power	—			(2,498		)	—			(2,498		)
Deferred fuel and purchased power — mark-to-market	(55,020		)	(38,187		)	(55,020		)	(38,187		)
Pension benefits	(240,692		)	(191,747		)	(240,692		)	(191,747		)
Retired power plant costs (see Note 3)	(53,420		)	(57,255		)	(53,420		)	(57,255		)
Other	(108,441		)	(99,123		)	(108,441		)	(99,123		)
Other	(4,984		)	(5,484		)	(4,984		)	(5,484		)
Total deferred tax liabilities	(3,715,782		)	(3,472,290		)	(3,715,031		)	(3,471,615		)
Deferred income taxes — net	$	(2,723,425	)	$	(2,460,404	)	$	(2,764,489	)	$	(2,516,112	)

As of December 31, 2015, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $82 million, which first begin to expire in 2031, and other federal and state loss carryforwards of $3 million, which first begin to expire in 2019. The credit and loss carryforwards amount above has been reduced by $26 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, 2015 and 2014 (dollars in thousands):



	December 31, 2015						December 31, 2014
	Pinnacle West		APS		Total		Pinnacle West		APS			Total
Commitments under Credit Facility	$	200,000	$	1,000,000	$	1,200,000	$	200,000	$	1,000,000		$	1,200,000
Outstanding Commercial Paper Borrowings	—		—		—		—		(147,400		)	(147,400		)
Amount of Credit Facility Available	$	200,000	$	1,000,000	$	1,200,000	$	200,000	$	852,600		$	1,052,600

Weighted-Average Commitment Fees	0.125%		0.100%				0.175%		0.125%

Pinnacle West

At December 31, 2015, Pinnacle West had a $200 million revolving credit facility that matures in May 2019. 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, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

On September 2, 2015, APS replaced its $500 million revolving credit facility that would have matured in April 2018, with a new $500 million facility that matures in September 2020.

At December 31, 2015, APS had two credit facilities totaling $1 billion, including the $500 million credit facility that matures in September 2020 and a $500 million credit facility that matures in May 2019. APS may increase the amount of each facility up to a maximum of $700 million each, 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 $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2015, APS had no outstanding borrowings or letters of credit 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2015 and 2014 (dollars in thousands):



	Maturity	Interest	December 31,
	Dates (a)	Rates	2015			2014
APS
Pollution control bonds:
Variable	2029-2038	(b)	$	92,405		$	156,405
Fixed	2024-2034	1.75%-5.75%	211,150			249,300
Total pollution control bonds			303,555			405,705
Senior unsecured notes	2016-2045	2.20%-8.75%	3,375,000			2,875,000
Palo Verde sale leaseback lessor notes	2015	8.00%	—			13,420
Term loan	2018	(c)	50,000			—
Unamortized discount			(10,374		)	(9,206		)
Unamortized premium			4,686			4,866
Unamortized debt issuance cost	(d)		(27,896		)	(24,642		)
Total APS long-term debt			3,694,971			3,265,143
Less current maturities	(e)		357,580			383,570
Total APS long-term debt less current maturities			3,337,391			2,881,573
Pinnacle West
Term loan	2017	(f)	125,000			125,000
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	3,462,391		$	3,006,573

(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 0.01%-0.24% at December 31, 2015 and 0.03%-0.27% at December 31, 2014.


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


(d)	In the fourth quarter of 2015, we adopted a new accounting standard related to balance sheet presentation of debt issuance costs. See Note 2 for additional details.

(e) Current maturities include $108 million of pollution control bonds expected to be remarketed in 2016 and $250 million in senior unsecured notes that mature in 2016.

(f) The weighted-average interest rate was 1.174% at December 31, 2015 and 1.019% at December 31, 2014.

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
2016	$	357,580	$	357,580
2017	125,000		—
2018	82,000		82,000
2019	500,000		500,000
2020	250,000		250,000
Thereafter	2,538,975		2,538,975
Total	$	3,853,555	$	3,728,555

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, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125,000	$	125,000	$	125,000	$	125,000
APS	3,694,971		3,981,367		3,265,143		3,714,108
Total	$	3,819,971	$	4,106,367	$	3,390,143	$	3,839,108

Credit Facilities and Debt Issuances

APS

On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% notes due May 15, 2015.

On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014.

On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On November 6, 2015, APS issued $250 million of 4.35% unsecured senior notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance via redemption and cancellation at par our indebtedness related to the principal amounts of the Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A and 2009 Series C both due June 1, 2034, and repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On November 17, 2015, APS redeemed at par and canceled all $38 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014.

On November 17, 2015, APS canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series B, purchased in connection with the mandatory tender provision on May 30, 2014.

On December 8, 2015, APS redeemed at par and canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series C.

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, 2015, the ratio was approximately 47% for Pinnacle West and 46% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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

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

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, 2015, APS was in

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.7 billion, and total capitalization was approximately $8.6 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.4 billion, assuming APS’s total capitalization remains the same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

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 an other postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries. This plan provides 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 will provide 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 and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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
	2015			2014			2013			2015			2014			2013
Service cost-benefits earned during the period	$	59,627		$	53,080		$	64,195		$	16,827		$	18,139		$	23,597
Interest cost on benefit obligation	123,983			129,194			112,392			28,102			41,243			41,536
Expected return on plan assets	(179,231		)	(158,998		)	(146,333		)	(36,855		)	(46,400		)	(45,717		)
Amortization of:
Prior service cost (credit)	594			869			1,097			(37,968		)	(9,626		)	(179		)
Net actuarial loss	31,056			10,963			39,852			4,881			1,175			11,310
Net periodic benefit cost	$	36,029		$	35,108		$	71,203		$	(25,013	)	$	4,531		$	30,547
Portion of cost charged to expense	$	20,036		$	21,985		$	38,968		$	(10,391	)	$	6,000		$	18,469

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2015 and 2014 (dollars in thousands):



	Pension						Other Benefits
	2015			2014			2015			2014
Change in Benefit Obligation
Benefit obligation at January 1	$	3,078,648		$	2,646,530		$	682,335		$	890,418
Service cost	59,627			53,080			16,827			18,139
Interest cost	123,983			129,194			28,102			41,243
Benefit payments	(137,115		)	(128,550		)	(24,988		)	(29,054		)
Actuarial (gain) loss	(91,340		)	378,394			(55,256		)	150,188
Plan amendments	—			—			—			(388,599		)
Benefit obligation at December 31	3,033,803			3,078,648			647,020			682,335
Change in Plan Assets
Fair value of plan assets at January 1	2,615,404			2,264,121			834,625			748,339
Actual return on plan assets	(44,690		)	292,992			(2,399		)	105,223
Employer contributions	100,000			175,000			791			770
Benefit payments	(127,940		)	(116,709		)	—			(19,707		)
Fair value of plan assets at December 31	2,542,774			2,615,404			833,017			834,625
Funded Status at December 31	$	(491,029	)	$	(463,244	)	$	185,997		$	152,290

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, 2015 and 2014 (dollars in thousands):



	2015		2014
Projected benefit obligation	$	3,033,803	$	3,078,648
Accumulated benefit obligation	2,873,467		2,873,741
Fair value of plan assets	2,542,774		2,615,404

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2015 and 2014 (dollars in thousands):



	Pension						Other Benefits
	2015			2014			2015		2014
Noncurrent asset	$	—		$	—		$	185,997	$	152,290
Current liability	(10,031		)	(9,508		)	—		—
Noncurrent liability	(480,998		)	(453,736		)	—		—
Net amount recognized	$	(491,029	)	$	(463,244	)	$	185,997	$	152,290

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2015 and 2014 (dollars in thousands):



	Pension						Other Benefits
	2015			2014			2015			2014
Net actuarial loss	$	679,501		$	577,976		$	127,124		$	148,006
Prior service cost (credit)	609			1,203			(341,301		)	(379,269		)
APS’s portion recorded as a regulatory (asset) liability	(619,223		)	(485,037		)	213,621			230,916
Income tax expense (benefit)	(23,663		)	(36,890		)	925			851
Accumulated other comprehensive loss	$	37,224		$	57,252		$	369		$	504

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 2016 (dollars in thousands):



	Pension		Other Benefits
Net actuarial loss	$	38,923	$	3,784
Prior service cost (credit)	527		(37,884		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2016	$	39,450	$	(34,100	)

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,
	2015		2014		2015		2014				2013
							January - September		October - December
Discount rate – pension	4.37	%	4.02	%	4.02	%	4.88	%	4.88	%	4.01	%
Discount rate – other benefits	4.52	%	4.14	%	4.14	%	5.10	%	4.41	%	4.20	%
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	%	7.00	%
Expected long-term return on plan assets - other benefits	N/A		N/A		4.45	%	6.80	%	4.25	%	7.00	%
Initial healthcare cost trend rate (pre-65 participants)	7.00	%	7.00	%	7.00	%	7.50	%	7.50	%	7.50	%
Initial healthcare cost trend rate (post-65 participants)	5.00	%	5.00	%	5.00	%	7.50	%	5.00	%	7.50	%
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		4		0		4

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 2016, we are assuming a 6.90% long-term rate of return for pension assets and 4.74% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	$	8,834	$	(5,890	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	9,069		(6,949		)
Effect on the accumulated other postretirement benefit obligation	100,322		(80,332		)

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.

Long-term fixed income assets, also known as liability-hedging assets, are designed 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, other government agencies, and corporations. Long-term fixed income assets may also include interest rate swaps, U.S. Treasury futures 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 hold investments in return-generating assets by holding securities in partnerships and common and collective trusts.

Based on the IPS, and given the pension plan’s funded status at year-end 2015, 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2015, long-term fixed income assets represented 60% of total pension plan assets, and return-generating assets represented 40% of total pension plan assets.

As of December 31, 2015, 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, 2015, investment in fixed income assets represented 40% of the other postretirement benefit plan total assets, and non-fixed income assets represented 60% of the other postretirement benefit plan’s assets. Fixed income assets are primarily invested in corporate bonds of investment-grade U.S. issuers, and U.S. Treasuries. Non-fixed income assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both emerging and developed markets.

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 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. 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. Exchange traded mutual funds, are classified as Level 1, as the valuation for these instruments is 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. 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, 2015, the plans were able to transact in the common and collective trusts at NAV and classifies these investments as Level 2.

Investments in partnerships are also valued using the concept of NAV, which 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, 2015, approximately $40 million of these commitments have been funded. Partnerships are classified as Level 2 if the plan is able to transact in the partnership at the NAV, otherwise the partnership is classified as Level 3.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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)		Significant Unobservable Inputs (Level 3)		Other (b)		Balance at December 31, 2015
Pension Plan:
Assets:
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 (a)	—		113,008		—		—		113,008
Equities:
U.S. companies	233,021		—		—		—		233,021
International companies	14,680		—		—		—		14,680
Common and collective trusts:
U.S. equities	—		130,097		—		—		130,097
International equities	—		185,892		—		—		185,892
Real estate	—		150,359		—		—		150,359
Partnerships	—		127,840		42,097		—		169,937
Mutual funds - International equities	116,307		—		—		—		116,307
Short-term investments and other	—		29,599		—		14,467		44,066
Total Pension Plan	$	640,679	$	1,845,531	$	42,097	$	14,467	$	2,542,774
Other Benefits:
Assets:
Cash and cash equivalents	$	240	$	—	$	—	$	—	$	240
Fixed income securities:
Corporate	—		217,026		—		—		217,026
U.S. Treasury	131,435		—		—		—		131,435
Other (a)	—		31,106		—		—		31,106
Equities:
U.S. companies	253,193		—		—		—		253,193
International companies	12,390		—		—		—		12,390
Common and collective trusts:
U.S. equities	—		81,516		—		—		81,516
International equities	—		28,539		—		—		28,539
Real estate	—		13,512		—		—		13,512
Mutual funds - International equities	52,568		—		—		—		52,568
Short-term investments and other	5,065		3,331		—		3,096		11,492
Total Other Benefits	$	454,891	$	375,030	$	—	$	3,096	$	833,017


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


(b)	Represents 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, 2014, 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)		Significant Unobservable Inputs (Level 3)		Other (b)		Balance at December 31, 2014
Pension Plan:
Assets:
Cash and cash equivalents	$	387	$	—	$	—	$	—	$	387
Fixed Income Securities:
Corporate	—		1,162,096		—		—		1,162,096
U.S. Treasury	291,817		—		—		—		291,817
Other (a)	—		113,265		—		—		113,265
Equities:
U.S. Companies	246,387		—		—		—		246,387
International Companies	18,069		—		—		—		18,069
Common and collective trusts:
U.S. Equities	—		127,336		—		—		127,336
International Equities	—		317,167		—		—		317,167
Real estate	—		129,715		—		—		129,715
Partnerships	—		138,337		27,929		—		166,266
Short-term investments and other	—		26,016		—		16,883		42,899
Total Pension Plan	$	556,660	$	2,013,932	$	27,929	$	16,883	$	2,615,404
Other Benefits:
Assets:
Cash and cash equivalents	$	318	$	—	$	—	$	—	$	318
Fixed Income Securities:
Corporate	—		187,961		—		—		187,961
U.S. Treasury	130,967		—		—		—		130,967
Other (a)	—		35,291		—		—		35,291
Equities:
U.S. Companies	265,106		—		—		—		265,106
International Companies	17,813		—		—		—		17,813
Common and collective trusts:
U.S. Equities	—		88,258		—		—		88,258
International Equities	—		85,746		—		—		85,746
Real Estate	—		11,657		—		—		11,657
Short-term investments and other	—		7,408		—		4,100		11,508
Total Other Benefits	$	414,204	$	416,321	$	—	$	4,100	$	834,625


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


(b)	Represents plan receivables and payables.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2015 and 2014 (dollars in thousands):



	Pension
Partnerships	2015			2014
Beginning balance at January 1	$	27,929		$	8,660
Actual return on assets still held at December 31	2,789			927
Purchases	13,187			19,984
Sales	(1,808		)	(1,642		)
Transfers in and/or out of Level 3	—			—
Ending balance at December 31	$	42,097		$	27,929

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 2015, $175 million in 2014, and $141 million in 2013. 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 2016-2018 period. With regard to contributions to our other postretirement benefit plans, we made a contribution of $1 million in 2015, $1 million in 2014, and $14 million in 2013. We expect to make contributions of approximately $1 million in each of 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 $100 million in 2015, $175 million in 2014, and $140 million in 2013. APS’s share of the contributions to the other postretirement benefit plan was $1 million in 2015, $1 million in 2014, and $14 million in 2013.

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
2016	$	152,146	$	26,468
2017	171,005		28,444
2018	170,534		30,490
2019	180,700		32,438
2020	188,988		33,982
Years 2021-2025	1,023,451		184,335

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 2015, 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

future contributions. Pinnacle West recorded expenses for this plan of approximately $9 million for 2015, $9 million for 2014, and $9 million for 2013.

Leases

We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.

Total lease expense recognized in the Consolidated Statements of Income was $17 million in 2015, $18 million in 2014, and $18 million in 2013. APS’s lease expense was $14 million in 2015, $15 million in 2014, and $15 million in 2013.

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
2016	$	9,182	$	8,797
2017	8,557		8,317
2018	7,045		6,880
2019	6,121		5,961
2020	4,835		4,680
Thereafter	61,251		61,101
Total future lease commitments	$	96,991	$	95,736

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 statement 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, 2015 (dollars in thousands):



	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,744,137	$	1,067,376	$	22,228
Palo Verde Unit 2 (a)	16.8	%		583,633		356,767		4,142
Palo Verde Common	28.0	%	(b)	643,201		231,609		64,069
Palo Verde Sale Leaseback			(a)	351,050		233,665		—
Four Corners Generating Station	63.0	%		857,555		577,321		77,317
Navajo Generating Station Units 1, 2 and 3	14.0	%		274,640		168,132		4,460
Cholla common facilities (c)	63.3	%	(b)	158,623		53,777		1,390
Transmission facilities:
ANPP 500kV System	33.4	%	(b)	109,348		36,576		1,594
Navajo Southern System	22.7	%	(b)	62,139		19,361		397
Palo Verde — Yuma 500kV System	19.3	%	(b)	14,043		5,226		133
Four Corners Switchyards	49.8	%	(b)	38,420		9,833		1,687
Phoenix — Mead System	17.1	%	(b)	39,089		13,173		151
Palo Verde — Estrella 500kV System	50.0	%	(b)	89,832		18,359		1,008
Morgan — Pinnacle Peak System	64.6	%	(b)	129,855		11,087		2,592
Round Valley System	50.0	%	(b)	703		286		—
Palo Verde — Morgan System	87.7	%	(b)	12		—		133,813
Hassayampa - North Gila System	80.0	%	(b)	164,854		1,159		—
Cholla 500 Switchyard	85.7	%	(b)	547		15		—
Saguaro 500 Switchyard	75.0	%	(b)	773		26		—


(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.

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 DOE in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 current reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

APS’s first claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2011 through June 30, 2014, and was for $42.0 million (APS’s share of this amount was $12.2 million), was received on June 1, 2015. APS's $12.2 million share was recorded as an adjustment to a regulatory liability and had no impact on the amount of current reported net income. APS’s second claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2014 through June 30, 2015, was filed for $12.0 million (APS's share of this amount would be $3.6 million), and has been submitted to, but not yet approved by, the DOE in the fourth quarter of 2015.

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 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 $13.5 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI"). The remaining balance of $13.1 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment of approximately $16.6 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective premium assessments 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 $23.1 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 $61.7 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2016 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $876 million in 2016; $949 million in 2017; $737 million in 2018; $603 million in 2019; $498 million in 2020; and $7.8 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,
	2016		2017		2018		2019		2020		Thereafter
Coal take-or-pay commitments (a)	$	170,714	$	195,428	$	189,588	$	193,818	$	198,160	$	2,270,974


(a)	Total take-or-pay commitments are approximately $3.2 billion. The total net present value of these commitments is approximately $2.2 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 payments under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):



	Year Ended December 31,
	2015		2014		2013
Total payments	$	211,327	$	236,773	$	188,496

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 $42 million in 2016; $40 million in 2017; $40 million in 2018; $40 million in 2019; $40 million in 2020; and $432 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy.

Coal Mine Reclamation Obligations

APS 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 $202 million at December 31, 2015 and $198 million at December 31, 2014. Under our current coal supply agreements, we expect to make payments for the final mine reclamation as follows: $15 million in 2016; $16 million in 2017; $18 million in 2018; $19 million in 2019; $20 million in 2020; and $262 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 remedial investigation and feasibility study work plan. 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. 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 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. The appeal is now fully briefed and pending before the United States Court of Appeals for the Ninth Circuit, which heard oral argument on February 9, 2016. A written decision on the case is expected 30-60 days after oral argument. We believe the District Court's decision will be upheld on appeal, but cannot predict the outcome at the appellate court. If the District Court's decision is reversed, the case would be remanded for discovery and trial, and there is insufficient information at this time to reasonably estimate any possible loss or range of loss to APS and Pinnacle West.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Clean Air Act Citizen Lawsuit

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. The case was held in abeyance while APS negotiated a settlement with DOJ and environmental plaintiffs. In March 2015, the parties agreed in principle to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On August 17, 2015, the consent decree was entered by the district court.

The settlement requires installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two Four Corners units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule requirements. The settlement also requires the Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.7 million for certain environmental mitigation projects to benefit the Navajo Nation. APS is responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, 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, Cholla and the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants.

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these 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. When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. APS is negotiating a definitive purchase agreement with NTEC for the purchase of the 7% interest. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015), 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, 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 wherein, 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 the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. APS is unable to predict when or whether APS's proposal may ultimately be approved by the EPA.

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 (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015). 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 United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS proceeding back to the DC Circuit Court. The Circuit Court then remanded the MATS rule back to EPA to address rulemaking deficiencies identified by the Supreme Court. Further EPA action on the MATS rule is pending. This proceeding does not materially impact APS. Regardless of how EPA addresses the deficiencies in 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.

Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

requirements. 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 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.

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, and its share of incremental costs for Cholla is approximately $85 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million.

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 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, it is expected that this timing will be impacted by the court-imposed stay described below.

ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, is presently working to develop a compliance plan for submittal to EPA. In addition to these on-going 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 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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, as an alternative to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, 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, greenhouse gas emissions, and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Notice of Intent to Sue Related to Four Corners

On December 21, 2015, several environmental groups filed a notice of intent to sue with OSM and other federal agencies under the Endangered Species Act alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the DOI's review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. We are monitoring this matter and will intervene if a lawsuit is filed. We cannot predict the timing or outcome of this matter.

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 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. The parties are engaged in settlement discussions and we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

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 debt arrangements, commodity contract collateral obligations, and other transactions. As of December 31, 2015, standby letters of credit totaled $79 million and will expire in 2016. As of December 31, 2015, surety bonds expiring through 2018 totaled $158 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

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

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.

In 2014, an update to the 2013 decommissioning study was completed for Palo Verde nuclear generation facility to incorporate additional spent fuel related charges resulting in an increase to the ARO in the amount of $20 million. Also in 2014, an updated Four Corners Units 1-3 coal-fired power plant decommissioning study was finalized, which resulted in an increase to the ARO of $24 million. In addition, Four Corners spent $30 million in actual decommissioning costs. Finally, in 2014 APS also recognized an ARO related to a new solar facility on leased property that requires the land to be returned to its original condition upon decommissioning of the plant, which resulted in an increase to the ARO of $6 million.

The following table shows the change in our asset retirement obligations for 2015 and 2014 (dollars in thousands):



	2015			2014
Asset retirement obligations at the beginning of year	$	390,750		$	346,729
Changes attributable to:
Accretion expense	25,163			23,567
Settlements	(32,048		)	(29,497		)
Estimated cash flow revisions	17,556			43,899
Newly incurred obligation	42,155			6,052
Asset retirement obligations at the end of year	$	443,576		$	390,750

As mentioned above, decommissioning activities for Four Corners Units 1-3 began in January 2014. Decommissioning activities for Cholla ash ponds began in January 2015. Thus, $29 million of the total ARO of $444 million at December 31, 2015, is classified as a current liability on the balance sheet. At December 31, 2014, $32 million of the total ARO of $391 million was classified as a current liability on the balance sheet.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2015 and 2014 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.



	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



	2014 Quarter Ended								2014
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	686,251	$	906,264	$	1,172,667	$	726,450	$	3,491,632
Operations and maintenance	212,882		211,222		223,418		260,503		908,025
Operating income	75,170		254,113		421,775		60,184		811,242
Income taxes	6,405		74,540		134,753		5,007		220,705
Net income	24,691		141,384		248,086		9,535		423,696
Net income attributable to common shareholders	15,766		132,458		243,961		5,410		397,595

Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.14	$	1.20	$	2.20	$	0.05	$	3.59
Net income attributable to common shareholders — Diluted	0.14		1.19		2.20		0.05		3.58

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Selected Quarterly Financial Data (Unaudited) - APS

APS's quarterly financial information for 2015 and 2014 is as follows (dollars in thousands):



	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



	2014 Quarter Ended,								2014
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	685,545	$	905,578	$	1,172,190	$	725,633	$	3,488,946
Operations and maintenance	208,285		208,059		212,430		253,668		882,442
Operating income	69,635		180,394		287,928		54,835		592,792
Net income attributable to common shareholder	19,518		134,916		251,047		15,738		421,219

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. This category also includes certain investments that are valued and redeemable based on NAV, such as common and collective trusts and commingled funds.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. 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.

Risk Management Activities — Derivative Instruments

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

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 based on the concept of NAV, which is a value primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV. We classify these investments as Level 2. 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 fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

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.

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, 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			—			—				314,957
Fixed income securities:
Cash and cash equivalent funds	12,260		—			—			(335		)	(c)	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		606,026			—			(335		)		735,196
Total	$	129,505	$	629,018		$	30,364		$	(25,680	)		$	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)	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, 2014 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, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	20,769		$	32,598		$	(21,962	)	(b)	$	31,405
Nuclear decommissioning trust:
U.S. commingled equity funds	—		309,620			—			—				309,620
Fixed income securities:
U.S. Treasury	118,843		—			—			—				118,843
Cash and cash equivalent funds	—		11,453			—			(7,245		)	(c)	4,208
Corporate debt	—		109,379			—			—				109,379
Mortgage-backed securities	—		88,465			—			—				88,465
Municipal bonds	—		69,139			—			—				69,139
Other	—		14,212			—			—				14,212
Subtotal nuclear decommissioning trust	118,843		602,268			—			(7,245		)		713,866
Total	$	118,843	$	623,037		$	32,598		$	(29,207	)		$	745,271
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(95,061	)	$	(73,984	)	$	58,767		(b)	$	(110,278	)


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


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


(c)	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 significant unobservable inputs at December 31, 2015 for these instruments include electricity prices, and volatilities. The significant unobservable inputs at December 31, 2014 for these instruments include electricity prices, gas 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, 2015 and December 31, 2014:



	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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	December 31, 2014 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	29,471	$	55,894	Discounted cash flows	Electricity forward price (per MWh)	$19.51 - $56.72	$	35.27
Option Contracts (b)	—		15,035		Option model	Electricity forward price (per MWh)	$32.14 - $66.09	$	45.83
						Natural gas forward price (per MMBtu)	$3.18 - $3.29	$	3.25
						Electricity price volatilities	23% - 63%	41		%
						Natural gas price volatilities	23% - 41%	31		%
Natural Gas:
Forward Contracts (a)	3,127		3,055		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.98 - $4.13	$	3.45
Total	$	32,598	$	73,984


(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, 2015 and 2014 (dollars in thousands):



	Year Ended December 31,
Commodity Contracts	2015			2014
Net derivative balance at beginning of period	$	(41,386	)	$	(49,165	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			102
Included in OCI	(452		)	(239		)
Deferred as a regulatory asset or liability	(4,009		)	(482		)
Settlements	14,809			12,080
Transfers into Level 3 from Level 2	(6,256		)	(2,090		)
Transfers from Level 3 into Level 2	4,315			(1,592		)
Net derivative balance at end of period	$	(32,979	)	$	(41,386	)
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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value

The carrying value of our 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, 2015, 2014 and 2013 (in thousands, except per share amounts):



	2015		2014		2013
Net income attributable to common shareholders	$	437,257	$	397,595	$	406,074
Weighted average common shares outstanding — basic	111,026		110,626		109,984
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	526		552		822
Weighted average common shares outstanding — diluted	111,552		111,178		110,806
Earnings per average common share attributable to common shareholders — basic	$	3.94	$	3.59	$	3.69
Earnings per average common share attributable to common shareholders — diluted	$	3.92	$	3.58	$	3.66

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, 2015, 2.8 million common shares were available for issuance under the 2012 Plan. During 2015, 2014, and 2013, the Company has granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. The Company has not granted stock options since 2004 and has no stock options outstanding. 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.

Stock-Based Compensation Expense and Activity

Compensation cost included in net income for stock-based compensation plans was $19 million in 2015, $33 million in 2014, and $25 million in 2013. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $7 million in 2015, $13 million in 2014, and $10 million in 2013.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2015, there were approximately $14 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. These costs are expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $21 million in 2015, $20 million in 2014 and $20 million in 2013.

The following table is a summary of awards granted and the weighted-average fair value for the three years ended 2015, 2014 and 2013.



	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2015		2014		2013		2015		2014		2013
Units granted	152,651		179,291		182,240		151,430		166,244		176,332
Weighted-average grant date fair value	$	64.12	$	54.89	$	55.14	$	64.97	$	54.86	$	55.45


(a)	Units granted includes awards that will be cash settled of 45,104 in 2015, 49,018 in 2014, and 52,620 in 2013.


(b)	Reflects the target payout level.

The following table is a summary of the status of non-vested awards as of December 31, 2015 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, 2015	480,933		(a)	$	51.27	324,230		$	54.92
Granted	152,651			64.12		151,430		64.97
Change in performance factor	—			—		40,496		54.98
Vested	(198,424	)		49.20		(202,480	)	54.98
Forfeited	(6,873	)		56.78		(7,844	)	57.89
Nonvested at December 31, 2015	428,287			56.69		305,832		59.78
Vested Awards Outstanding at December 31, 2015	106,712					202,480


(a)	Includes 127,634 of awards that will be cash settled and 353,299 of awards that will be settled in shares.


(b)	Nonvested performance shares are reflected at target payout level. The 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.

Share-based liabilities paid relating to restricted stock unit awards was $10 million, $9 million and $10 million in 2015, 2014 and 2013, respectively. This includes cash used to settle restricted stock units of $3 million, $3 million and $4 million in 2015, 2014 and 2013, respectively. Share-based liabilities paid relating to performance share awards was $16 million, $12 million and $15 million in 2015, 2014 and 2013, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units have been 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 amount of dividends that they would have received had they directly owned stock, equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

In December 2012, a retention award of 50,617 restricted stock units was granted to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West. This award will vest and will be paid in shares of common stock on December 31, 2016, provided that he remains employed with the Company until the vesting date. The award can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met.

Restricted stock unit awards 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.

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. 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 have been granted to officers and key employees. Performance share awards contain two performance element criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met. The performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period, as compared with the total shareholder return of all relevant companies in a specified utility index and the other 50% is based upon six non-financial separate performance metrics. 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 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. Management evaluates the probability of meeting the performance criteria at each balance sheet date. If

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.

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 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.

On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow hedges. This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts. For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through OCI, but are deferred through the PSA. The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur. Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 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, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):



Commodity	Quantity
Power	2,487	GWh
Gas	182	Billion cubic feet

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, 2015, 2014 and 2013 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2015			2014			2013
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(615	)	$	(372	)	$	(353	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(5,988		)	(21,415		)	(44,219		)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power (b)	—			—			—


(a)	During the years ended December 31, 2015, 2014, and 2013, 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 $4 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2015, 2014 and 2013 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2015			2014			2013
Net Gain Recognized in Income	Operating revenues	$	574		$	324		$	289
Net Loss Recognized in Income	Fuel and purchased power (a)	(108,973		)	(66,367		)	(10,449		)
Total		$	(108,399	)	$	(66,043	)	$	(10,160	)


(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.

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, 2015 and December 31, 2014, include gross liabilities of $3 million and $4 million, respectively, of derivative instruments designated as hedging instruments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2015 and 2014. 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, 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.



As of December 31, 2014: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	28,557		$	(15,127	)	$	13,430		$	355		$	13,785
Investments and other assets	24,810			(7,190		)	17,620			—			17,620
Total assets	53,367			(22,317		)	31,050			355			31,405

Current liabilities	(86,055		)	33,829			(52,226		)	(7,443		)	(59,669		)
Deferred credits and other	(82,990		)	32,388			(50,602		)	—			(50,602		)
Total liabilities	(169,045		)	66,217			(102,828		)	(7,443		)	(110,271		)
Total	$	(115,678	)	$	43,900		$	(71,778	)	$	(7,088	)	$	(78,866	)


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


(b)	Includes cash collateral provided to counterparties of $43,900.


(c)	Represents cash collateral and 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 $7,443, and cash margin provided to counterparties of $355.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 87% of Pinnacle West’s $28 million of risk management assets as of December 31, 2015. This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality. 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).

The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2015 (dollars in thousands):



	December 31, 2015
Aggregate fair value of derivative instruments in a net liability position	$	207,387
Cash collateral posted	18,060
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	112,301


(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 $161 million if our debt credit ratings were to fall below investment grade.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2015, 2014 and 2013 (dollars in thousands):



	2015			2014			2013
Other income:
Interest income	$	493		$	1,010		$	1,629
Debt return on the purchase of Four Corners units 4 & 5	—			8,386			—
Miscellaneous	128			212			75
Total other income	$	621		$	9,608		$	1,704
Other expense:
Non-operating costs	$	(11,292	)	$	(9,657	)	$	(8,207	)
Investment loss — net	(2,080		)	(9,426		)	(3,711		)
Miscellaneous	(4,451		)	(2,663		)	(4,106		)
Total other expense	$	(17,823	)	$	(21,746	)	$	(16,024	)

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2015, 2014 and 2013 (dollars in thousands):



	2015			2014			2013
Other income:
Interest income	$	163		$	689		$	1,234
Debt return on the purchase of Four Corners units 4 & 5	—			8,386			—
Gain on disposition of property	716			1,197			1,024
Miscellaneous	1,955			1,023			1,638
Total other income	$	2,834		$	11,295		$	3,896
Other expense:
Non-operating costs (a)	$	(11,648	)	$	(10,397	)	$	(9,626	)
Loss on disposition of property	(2,219		)	(615		)	(4,992		)
Miscellaneous	(5,152		)	(2,391		)	(5,831		)
Total other expense	$	(19,019	)	$	(13,403	)	$	(20,449	)

(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. The original lease was scheduled to end on December 31, 2015; however, the lease agreements include fixed rate renewal options which APS exercised on July 7, 2014. As a result, 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 2016 through 2023, and about $16 million annually for the period 2024 through

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At the end of the lease renewal periods, 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 fixed rate renewal periods 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. Predominately due to the fixed rate renewal periods, 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 and interest expense, resulting in an increase in net income for 2015, 2014 and 2013 of $19 million, $26 million and $34 million, respectively, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased in 2015 and 2014 compared with the prior year because of lower rent income resulting from the lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income that resulted from the lease extensions. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. Consolidation of these VIEs also results in changes to our Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Consolidated Balance Sheets at December 31, 2015 and December 31, 2014 include the following amounts relating to the VIEs (dollars in thousands):



	December 31, 2015		December 31, 2014
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	117,385	$	121,255
Current maturities of long-term debt	—		13,420
Equity-Noncontrolling interests	135,540		151,609

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances, such as a default by APS under the lease.

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 could 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 extension period, APS may be required to pay the noncontrolling equity participants approximately $288 million beginning in 2016, and up to $465 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	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	)



	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2014
Equity securities	$	309,620		$	159,274	$	(15	)
Fixed income securities	411,491			17,260		(1,073		)
Net payables (a)	(7,245		)	—		—
Total	$	713,866		$	176,534	$	(1,088	)


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

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,
	2015			2014			2013
Realized gains	$	5,189		$	4,725		$	5,459
Realized losses	(6,225		)	(4,525		)	(6,706		)
Proceeds from the sale of securities (a)	478,813			356,195			446,025


(a)	Proceeds are reinvested in the trust.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2015 is as follows (dollars in thousands):



	Fair Value
Less than one year	$	14,001
1 year – 5 years	117,356
5 years – 10 years	114,769
Greater than 10 years	174,448
Total	$	420,574

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, 2015 and 2014 (dollars in thousands):



	Year Ended December 31,
	2015			2014
Balance at beginning of period	$	(68,141	)	$	(78,053	)
Derivative Instruments
OCI (loss) before reclassifications	(957		)	(810		)
Amounts reclassified from accumulated other comprehensive loss (a)	4,187			13,483
Net current period OCI (loss)	3,230			12,673
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	16,980			(5,419		)
Amounts reclassified from accumulated other comprehensive loss (b)	3,183			2,658
Net current period OCI (loss)	20,163			(2,761		)
Balance at end of period	$	(44,748	)	$	(68,141	)


(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, 2015 and 2014 (dollars in thousands):



	Year Ended December 31,
	2015			2014
Balance at beginning of period	$	(48,333	)	$	(53,372	)
Derivative Instruments
OCI (loss) before reclassifications	(957		)	(809		)
Amounts reclassified from accumulated other comprehensive loss (a)	4,187			13,483
Net current period OCI (loss)	3,230			12,674
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	14,726			(10,415		)
Amounts reclassified from accumulated other comprehensive loss (b)	3,280			2,780
Net current period OCI (loss)	18,006			(7,635		)
Balance at end of period	$	(27,097	)	$	(48,333	)


(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,
	2015			2014			2013
Operating revenues	$	550		$	642		$	799
Operating expenses	12,733			23,507			24,930
Operating loss	(12,183		)	(22,865		)	(24,131		)
Other
Equity in earnings of subsidiaries	446,508			411,528			420,926
Other expense	(3,302		)	(3,276		)	(1,999		)
Total	443,206			408,252			418,927
Interest expense	2,672			3,663			3,226
Income before income taxes	428,351			381,724			391,570
Income tax benefit	(8,906		)	(15,871		)	(14,504		)
Net income attributable to common shareholders	437,257			397,595			406,074
Other comprehensive income — attributable to common shareholders	23,393			9,912			35,955
Total comprehensive income — attributable to common shareholders	$	460,650		$	407,507		$	442,029

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,
	2015			2014
ASSETS
Current assets
Cash and cash equivalents	$	17,432		$	3,088
Accounts receivable	93,093			99,958
Current deferred income taxes	—			66,979
Income tax receivable	14,895			7,329
Other current assets	197			124
Total current assets	125,617			177,478
Investments and other assets
Investments in subsidiaries	4,815,236			4,630,570
Deferred income taxes	41,065			—
Other assets	43,422			43,051
Total investments and other assets	4,899,723			4,673,621
Total Assets	$	5,025,340		$	4,851,099
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	5,901		$	5,250
Accrued taxes	6,904			12,220
Common dividends payable	69,363			65,790
Other current liabilities	33,120			38,992
Total current liabilities	115,288			122,252
Long-term debt less current maturities	125,000			125,000
Deferred credits and other
Deferred income taxes	—			12,055
Pension liabilities	21,933			29,228
Other	43,662			43,462
Total deferred credits and other	65,595			84,745
Common stock equity
Common stock	2,535,862			2,509,569
Accumulated other comprehensive loss	(44,748		)	(68,141		)
Retained earnings	2,092,803			1,926,065
Total Pinnacle West Shareholders’ equity	4,583,917			4,367,493
Noncontrolling interests	135,540			151,609
Total Equity	4,719,457			4,519,102
Total Liabilities and Equity	$	5,025,340		$	4,851,099

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,
	2015			2014			2013
Cash flows from operating activities
Net income	$	437,257		$	397,595		$	406,074
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(446,508		)	(411,528		)	(420,926		)
Depreciation and amortization	92			94			95
Deferred income taxes	12,967			4,406			(28,806		)
Accounts receivable	11,336			(22,945		)	21,671
Accounts payable	637			2,017			(2,449		)
Accrued taxes and income tax receivables — net	(12,882		)	(1,795		)	1,402
Dividends received from subsidiaries	266,900			253,600			242,100
Other	(6,995		)	18,432			(15,065		)
Net cash flow provided by operating activities	262,804			239,876			204,096
Cash flows from investing activities
Construction work in progress	(3,462		)	—			—
Investments in subsidiaries	(3,491		)	(10,236		)	(3,400		)
Repayments of loans from subsidiaries	157			322			2,149
Advances of loans to subsidiaries	(1,010		)	(1,450		)	(2,099		)
Net cash flow used for investing activities	(7,806		)	(11,364		)	(3,350		)
Cash flows from financing activities
Issuance of long-term debt	—			125,000			—
Dividends paid on common stock	(260,027		)	(246,671		)	(235,244		)
Repayment of long-term debt	—			(125,000		)	—
Common stock equity issuance	19,373			15,288			17,319
Other	—			161			298
Net cash flow used for financing activities	(240,654		)	(231,222		)	(217,627		)
Net increase (decrease) in cash and cash equivalents	14,344			(2,710		)	(16,881		)
Cash and cash equivalents at beginning of year	3,088			5,798			22,679
Cash and cash equivalents at end of year	$	17,432		$	3,088		$	5,798

See Combined Notes to Consolidated Financial Statements.

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:
2015	$	3,094	$	4,073	$	—	$	4,042	$	3,125
2014	3,203		3,942		—		4,051		3,094
2013	3,340		4,923		—		5,060		3,203

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:
2015	$	3,094	$	4,073	$	—	$	4,042	$	3,125
2014	3,203		3,942		—		4,051		3,094
2013	3,340		4,923		—		5,060		3,203

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