Pinnacle West Capital (PNW) 10-K 19 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	764,622
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 6,271,269,171
Entity Common Stock, Shares Outstanding		111,004,916
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
ARIZONA PUBLIC SERVICE COMPANY
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	7,286
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		71,264,947
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 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 (in shares)	111,026	110,626	109,984
Weighted Average common shares outstanding — diluted (in shares)	111,552	111,178	110,806
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 3.94	$ 3.59	$ 3.69
Net income attributable to common shareholders — diluted (in dollars per share)	$ 3.92	$ 3.58	$ 3.66
ARIZONA PUBLIC SERVICE COMPANY
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
Taxes other than income taxes	171,499	171,583	163,377
Income taxes (Note 4)	260,143	245,036	256,864
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
INCOME TAXES (Note 4)	245,841	237,360	245,095
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 SHAREHOLDERS	$ 450,274	$ 421,219	$ 424,969

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
NET INCOME	$ 456,190	$ 423,696	$ 439,966
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	(957)	(810)	(213)
Reclassification of net realized loss, net of tax benefit	4,187	13,483	26,747
Pension and other postretirement benefits activity, net of tax (expense) benefit	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
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	469,207	447,320	458,861
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	(957)	(809)	(214)
Reclassification of net realized loss, net of tax benefit	4,187	13,483	26,747
Pension and other postretirement benefits activity, net of tax (expense) benefit	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 SHAREHOLDERS	$ 471,510	$ 426,258	$ 460,692

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net unrealized loss, tax benefit (expense)	$ (342)	$ (438)	$ 140
Reclassification of net realized loss, tax benefit	1,801	7,932	17,472
Pension and other postretirement benefits activity, tax (expense) benefit	(13,302)	1,307	(6,156)
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized loss, tax benefit (expense)	(342)	(438)	140
Reclassification of net realized loss, tax benefit	1,801	7,932	17,472
Pension and other postretirement benefits activity, tax (expense) benefit	$ (11,776)	$ 4,655	$ (6,003)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
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)	0	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)	0	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
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)	0	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	0
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	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
ARIZONA PUBLIC SERVICE COMPANY
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
Deferred income taxes (Note 4)	0	55,253
Assets from risk management activities (Note 16)	15,905	13,785
Deferred fuel and purchased power regulatory asset (Note 3)	0	6,926
Other regulatory assets (Note 3)	149,555	129,808
Other current assets	35,765	38,693
Total current assets	870,755	900,117
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	34,455	33,362
Total investments and other assets	781,757	764,848
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
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
CURRENT LIABILITIES
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
Short-term borrowings (Note 5)	0	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	0
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	2,764,489	2,571,365
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)	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
EQUITY
Total 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 accumulated other comprehensive loss	(27,097)	(48,333)
Total shareholders’ 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
Total Liabilities and Equity	$ 14,982,182	$ 14,190,362

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	$ 233,665	$ 229,795
Accumulated amortization on intangible assets	546,038	489,538
Accumulated amortization on nuclear fuel	$ 146,228	$ 143,554
EQUITY
Common stock, par value	$ 0	$ 0
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	111,095,402	110,649,762
Treasury stock at cost, shares	115,030	78,400
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	$ 233,665	$ 229,795
Accumulated amortization on intangible assets	546,038	489,538
Accumulated amortization on nuclear fuel	$ 146,228	$ 143,554

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
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
Change in derivative instruments fair value
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	0	0	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
Supplemental disclosure of cash flow information:
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 related to acquisition of SCE’s Four Corners’ interest	0	0	145,609
ARIZONA PUBLIC SERVICE COMPANY
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
Change in derivative instruments fair value
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	0	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 income tax receivable	0	0	137,665
Change in unrecognized tax benefits	(10,328)	2,778	(91,244)
Change in long-term regulatory liabilities	(20,535)	59,618	64,473
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)
Distributions to noncontrolling interests	(35,002)	(20,482)	(17,385)
Net cash flow provided by (used for) financing activities	(22,457)	(201,259)	(185,056)
NET INCREASE (DECREASE) 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:
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	$ 0	$ 0	$ 145,609

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands		Total	Common Stock	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANYCommon Stock	ARIZONA PUBLIC SERVICE COMPANYAdditional Paid-In Capital	ARIZONA PUBLIC SERVICE COMPANYRetained Earnings	ARIZONA PUBLIC SERVICE COMPANYAccumulated Other Comprehensive Income (Loss)	ARIZONA PUBLIC SERVICE COMPANYNoncontrolling Interests
Beginning Balance at Dec. 31, 2012		$ 4,102,289	$ 2,466,923	$ (4,211)	$ 1,624,102	$ (114,008)	$ 129,483	$ 4,222,483	$ 178,162	$ 2,379,696	$ 1,624,237	$ (89,095)	$ 129,483
Beginning Balance (in shares) at Dec. 31, 2012			109,837,957	95,192					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		439,966			406,074		33,892	458,861			424,969		33,892
Other comprehensive income		35,955				35,955		35,723				35,723
Dividends on common stock		(244,903)			(244,903)			(244,800)			(244,800)
Other								(8)			(8)
Issuance of common stock		24,635	$ 24,635
Issuance of common stock (in shares)			442,746
Purchase of treasury stock	[1]	(9,727)		$ (9,727)
Purchase of treasury stock (in shares)	[1]			(174,290)
Reissuance of treasury stock for stock-based compensation and other		9,630		$ 9,630
Reissuance of treasury stock for stock-based compensation and other (in shares)				170,538
Net capital activities by noncontrolling interests		(17,385)					(17,385)	(17,385)					(17,385)
Ending Balance at Dec. 31, 2013		4,340,460	$ 2,491,558	$ (4,308)	1,785,273	(78,053)	145,990	4,454,874	$ 178,162	2,379,696	1,804,398	(53,372)	145,990
Ending Balance (in shares) at Dec. 31, 2013			110,280,703	98,944					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		423,696			397,595		26,101	447,320			421,219		26,101
Other comprehensive income		9,912				9,912		5,039				5,039
Dividends on common stock		(256,803)			(256,803)			(256,900)			(256,900)
Other								1			1
Issuance of common stock		21,412	$ 21,412
Issuance of common stock (in shares)			369,059
Purchase of treasury stock	[1]	(7,893)		$ (7,893)
Purchase of treasury stock (in shares)	[1]			(139,746)
Reissuance of treasury stock for stock-based compensation and other		8,800		$ 8,800
Reissuance of treasury stock for stock-based compensation and other (in shares)				160,290
Net capital activities by noncontrolling interests		(20,482)					(20,482)	(20,482)					(20,482)
Ending Balance at Dec. 31, 2014		$ 4,519,102	$ 2,512,970	$ (3,401)	1,926,065	(68,141)	151,609	4,629,852	$ 178,162	2,379,696	1,968,718	(48,333)	151,609
Ending Balance (in shares) at Dec. 31, 2014		110,649,762	110,649,762	78,400					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		$ 456,190			437,257		18,933	469,207			450,274		18,933
Other comprehensive income		23,393				23,393		21,236				21,236
Dividends on common stock		(270,519)			(270,519)			(270,500)			(270,500)
Other								1			1
Issuance of common stock		28,698	$ 28,698
Issuance of common stock (in shares)			445,640
Purchase of treasury stock	[1]	(10,136)		$ (10,136)
Purchase of treasury stock (in shares)	[1]			(154,751)
Reissuance of treasury stock for stock-based compensation and other		7,731		$ 7,731
Reissuance of treasury stock for stock-based compensation and other (in shares)				118,121
Net capital activities by noncontrolling interests		(35,002)					(35,002)	(35,002)					(35,002)
Ending Balance at Dec. 31, 2015		$ 4,719,457	$ 2,541,668	$ (5,806)	$ 2,092,803	$ (44,748)	$ 135,540	$ 4,814,794	$ 178,162	$ 2,379,696	$ 2,148,493	$ (27,097)	$ 135,540
Ending Balance (in shares) at Dec. 31, 2015		111,095,402	111,095,402	115,030					71,264,947
[1]	Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

CONSOLIDATED STATEMENTS OF CHA9

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Common stock dividends declared (in dollars per share)	$ 2.44	$ 2.33	$ 2.23

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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. 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. 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. 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. 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 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). 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

New Accounting Standards	12 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	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 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

Regulatory Matters	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Regulatory Matters	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: • 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 9 0/10 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 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. 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 may not be increased or decreased more than $ 0.004 per kWh in a year without permission of the ACC. The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 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. 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. 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. 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. (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

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted income tax rates. APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit basis adjustment and tax expense of Medicare subsidy. The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates. In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income. Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18). As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. 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 ) 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. 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 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.

Lines of Credit and Short-Term

Lines of Credit and Short-Term Borrowings	12 Months Ended
	Dec. 31, 2015
Lines of Credit and Short-Term Borrowings
Lines of Credit and Short-Term Borrowings	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.

Long-Term Debt and Liquidity Ma

Long-Term Debt and Liquidity Matters	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt and Liquidity Matters	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 . 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 As of 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. 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 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 Bene

Retirement Plans and Other Benefits	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Retirement Plans and Other Benefits	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. 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 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 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. 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 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 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. 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. 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 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

Leases	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Leases	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

Jointly-Owned Facilities	12 Months Ended
	Dec. 31, 2015
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Jointly-Owned Facilities	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

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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 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. 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 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 52 nd 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. 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. 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 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 CO 2 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 CO 2 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. 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. 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 .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	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. 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 Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Line Items]
Selected Quarterly Financial Data (Unaudited)	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
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Selected Quarterly Financial Data (Unaudited)	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

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are: Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities 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 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 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. 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. 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. 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 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. December 31, 2014 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 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

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for 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

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	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 . 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. 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 performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.

Derivative Accounting

Derivative Accounting	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Accounting	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. 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. 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. 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: 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: 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 . 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.

Other Income and Other Expense

Other Income and Other Expense	12 Months Ended
	Dec. 31, 2015
Component of Other Income and Other Expense Nonoperating [Line Items]
Other Income and Other Expense	Other Income and Other Expense The following table provides detail of Pinnacle West's Consolidated other income and other expense for 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 )
ARIZONA PUBLIC SERVICE COMPANY
Component of Other Income and Other Expense Nonoperating [Line Items]
Other Income and Other Expense	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 Varia

Palo Verde Sale Leaseback Variable Interest Entities	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities [Abstract]
Palo Verde Sale Leaseback Variable Interest Entities	Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. 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 2033. 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.

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts	12 Months Ended
	Dec. 31, 2015
Investments, Debt and Equity Securities [Abstract]
Nuclear Decommissioning Trusts	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. 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 Co

Changes in Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2015
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Changes in Accumulated Other Comprehensive Loss	Changes in Accumulated Other Comprehensive Loss The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the 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.
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Changes in Accumulated Other Comprehensive Loss	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.

SCHEDULE I - CONDENSED FINANCIA

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
CONDENSED FINANCIAL INFORMATION OF REGISTRANT	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.

SCHEDULE II - RESERVE FOR UNCOL

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	12 Months Ended
	Dec. 31, 2015
Reserve for uncollectibles
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	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
Reserve for uncollectibles
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	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

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Description of Business and Basis of Presentation	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	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	Regulatory Accounting APS is regulated by the ACC and FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
Electric Revenues	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	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	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. 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.
Allowance for Funds Used During Construction	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	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	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.
Derivative Accounting	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.
Loss Contingencies and Environmental Liabilities	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	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.
Nuclear Fuel	Nuclear Fuel APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense. APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE suspended the fee. In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2016.
Income Taxes	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	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.
Intangible Assets	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.
Investments	Investments El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence). Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities.
Business Segments	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.
New Accounting Standards	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 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.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Schedule of property, plant and equipment	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
Summary of supplemental cash flow information	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

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Schedule of changes in the deferred fuel and purchased power regulatory asset	The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 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
Schedule of regulatory assets	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. (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.”
Schedule of regulatory liabilities	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 (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of unrecognized tax benefits roll forward	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
Summary of unrecognized tax benefits	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 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 ) 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
Components of income tax expense	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
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations	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
Net deferred income tax liability recognized on the Consolidated Balance Sheets	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 )
Components of the net deferred income tax liability	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 )

Lines of Credit and Short-Ter36

Lines of Credit and Short-Term Borrowings (Tables)	12 Months Ended
	Dec. 31, 2015
Lines of Credit and Short-Term Borrowings
Schedule of consolidated credit facilities and amounts available and outstanding	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%

Long-Term Debt and Liquidity 37

Long-Term Debt and Liquidity Matters (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Components of long-term debt on the Consolidated Balance Sheets	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 .
Principal payments due on Pinnacle West's and APS's total long-term debt	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
Schedule of estimated fair value of long-term debt, including current maturities	The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of As of 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

Retirement Plans and Other Be38

Retirement Plans and Other Benefits (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)	The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, 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
Schedule of changes in the benefit obligations and funded status	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
Schedule of projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets	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
Schedule of amounts recognized on the Consolidated Balance Sheets	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
Schedule of accumulated other comprehensive loss	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
Schedule of estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost	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 )
Schedule of weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs	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
Schedule of effects of one percentage point change in the assumed initial and ultimate health care cost trend rates	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 )
Schedule of fair value of pension plan and other postretirement benefit plan assets, by asset category	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. 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.
Schedule of changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3)	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
Schedule of estimated future benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter	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

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Estimated future minimum lease payments for Pinnacle West's and APS's operating leases, excluding purchased power agreements	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

Jointly-Owned Facilities (Table

Jointly-Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2015
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
APS's interests in jointly-owned facilities recorded on the Consolidated Balance Sheets	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 (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Summary of estimated coal take-or-pay commitments	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 .
Summary of actual take-or-pay commitments	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

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Change in asset retirement obligations	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

Selected Quarterly Financial 43

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Line Items]
Schedule of quarterly financial information	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
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Schedule of quarterly financial information	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 (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities that are measured at fair value on a recurring basis	The following table presents the fair value at 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. 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 purch
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments	s. 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 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. December 31, 2014 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 volatili
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs	The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the 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 $ — $ —

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of earnings per weighted average common share outstanding	The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for 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 (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Nonvested Restricted Stock, Stock Grants and Stock Units	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. 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.
Summary of Nonvested Performance Shares	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.

Derivative Accounting (Tables)

Derivative Accounting (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)	As of 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 in designated cash flow accounting hedges relationships	The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the 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.
Gains and losses from derivative instruments not designated as accounting hedges instruments	The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the 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.
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting liabilities	The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of 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: 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: 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 .
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting assets	The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of 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: 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: 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 .
Information about derivative instruments that have credit-risk-related contingent features	The following table provides information about our derivative instruments that have credit-risk-related contingent features at 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.

Other Income and Other Expense

Other Income and Other Expense (Tables)	12 Months Ended
	Dec. 31, 2015
Component of Other Income and Other Expense Nonoperating [Line Items]
Detail of 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 )
ARIZONA PUBLIC SERVICE COMPANY
Component of Other Income and Other Expense Nonoperating [Line Items]
Detail of other income and other expense	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 Var49

Palo Verde Sale Leaseback Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities [Abstract]
Amounts relating to the VIEs included in Consolidated Balance Sheets	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

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts (Tables)	12 Months Ended
	Dec. 31, 2015
Investments, Debt and Equity Securities [Abstract]
Fair value of APS's nuclear decommissioning trust fund assets	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.
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds	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.
Fair value of fixed income securities, summarized by contractual maturities	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 51

Changes in Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2015
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component	The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the 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.
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component	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.

Summary of Significant Accoun52

Summary of Significant Accounting Policies - Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended			36 Months Ended
	May. 31, 2014$ / kWh	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)$ / sharesshares
Approximate remaining average useful lives of utility property
Cost of services, depreciation		$ 430	$ 396	$ 400
Depreciation rates (as a percent)		2.74%	2.77%	3.00%
Allowance for Funds Used During Construction
Composite rate used to calculate AFUDC (as a percent)		8.02%	8.47%	8.56%
Income Taxes
Percent likelihood largest tax benefit amount is realized (greater than)		50.00%
Intangible Assets
Amortization expense		$ 58	$ 53	$ 53
Estimated amortization expense on existing intangible assets over the next five years
2,016		48			$ 48
2,017		36			36
2,018		18			18
2,019		9			9
2,020		$ 3			$ 3
Weighted average remaining amortization period for intangible assets		5 years
ARIZONA PUBLIC SERVICE COMPANY
Nuclear Fuel
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh) | $ / kWh	0.001
Preferred Stock
Preferred stock, shares authorized (in shares) | shares		15,535,000			15,535,000
Preferred stock par or stated value per share 1 (in dollars per share) | $ / shares		$ 25			$ 25
Preferred stock par or stated value per share 2 (in dollars per share) | $ / shares		50			50
Preferred stock par or stated value per share 3 (in dollars per share) | $ / shares		$ 100			$ 100
Pinnacle West
Preferred Stock
Preferred stock, shares authorized (in shares) | shares		10,000,000			10,000,000
Minimum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					0.30%
Maximum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					12.37%
Investments
Ownership percentage for classification as cost method investments by El Dorado		20.00%
Fossil plant
Approximate remaining average useful lives of utility property
Average useful life		19 years
Nuclear plant
Approximate remaining average useful lives of utility property
Average useful life		28 years
Other generation
Approximate remaining average useful lives of utility property
Average useful life		25 years
Transmission
Approximate remaining average useful lives of utility property
Average useful life		39 years
Distribution
Approximate remaining average useful lives of utility property
Average useful life		33 years
Other
Approximate remaining average useful lives of utility property
Average useful life		7 years

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Utility Plant and Depreciation [Line Items]
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
Electric Service
Utility Plant and Depreciation [Line Items]
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

Summary of Significant Accoun54

Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Income tax (benefit), net of refunds	$ 6,550	$ (102,154)	$ 18,537
Interest, net of amounts capitalized	170,209	177,074	184,010
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
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)	$ 0	$ 0	$ 145,609

New Accounting Standards - Narr

New Accounting Standards - Narrative (Details) - New Accounting Pronouncement, Early Adoption, Effect - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Long-term Debt
New Accounting Pronouncement, Early Adoption [Line Items]
Unamortized debt issue costs	$ (28)	$ (25)
Deferred Debits
New Accounting Pronouncement, Early Adoption [Line Items]
Unamortized debt issue costs	$ 28	$ 25

Regulatory Matters (Details)

Regulatory Matters (Details) - APS

Feb. 01, 2016$ / kWh

Jan. 15, 2016USD ($)

Jun. 01, 2015USD ($)

Mar. 02, 2015USD ($)

Feb. 01, 2015$ / kWh

Jun. 01, 2014USD ($)

Apr. 15, 2014CustomerMW

Mar. 01, 2014USD ($)

Jan. 01, 2014USD ($)$ / kWh

Jan. 06, 2012USD ($)$ / kWh

Jun. 01, 2011USD ($)

Apr. 30, 2014workshop

Jan. 31, 2016$ / kWh

Sep. 30, 2015$ / kWh

Dec. 31, 2015$ / kWh

Jul. 01, 2015USD ($)

Mar. 20, 2015USD ($)project

Dec. 31, 2014USD ($)

Dec. 19, 2014MW

Jul. 01, 2014USD ($)

Mar. 11, 2014USD ($)

Dec. 31, 2012USD ($)

Jun. 01, 2012

Lost Fixed Cost Recovery Mechanism

Settlement Agreement

Rate matter cap percentage of retail revenue

1.00%

ACC | Electric Energy Efficiency Standard

Settlement Agreement

Public utilities, cost effective energy efficiency programs, number of workshops | workshop

3

ACC | Net Metering

Settlement Agreement

Charge on future customers who install rooftop solar panels (in dollars per kWh) | $ / kWh

0.70

0.70

Estimated monthly collection due to charge on future customers who install rooftop solar panels

$ 4.90

Filing with the Arizona Corporation Commission | ACC | Retail rate case filing

Regulatory Matters [Line Items]

Net retail rate increase

$ 95,500,000

Approximate percentage of increase in the average retail customer bill

6.60%

Settlement Agreement

Net change in base rates

$ 0

Non-fuel base rate increase

116,300,000

Fuel-related base rate decrease

$ 153,100,000

Current base fuel rate (in dollars per kWh) | $ / kWh

0.03757

Approved base fuel rate (in dollars per kWh) | $ / kWh

0.03207

Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates

$ 36,800,000

Authorized return on common equity (as a percent)

10.00%

Percentage of debt in capital structure

46.10%

Percentage of common equity in capital structure

53.90%

Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent)

25.00%

Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent)

50.00%

Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent)

75.00%

Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent)

100.00%

Elimination of the sharing provision of fuel and purchased power costs

9

Period to process the subsequent rate cases

12 months

ACC staff sufficiency findings, general period of time

30 days

Filing with the Arizona Corporation Commission | ACC | Retail rate case filing | Maximum

Settlement Agreement

Annual cost recovery due to modifications to the Environmental Improvement Surcharge

$ 5,000,000

Cost Recovery Mechanisms | Lost Fixed Cost Recovery Mechanism

Settlement Agreement

Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh

0.031

Fixed costs recoverable per non-residential power lost (in dollars per kWh) | $ / kWh

0.023

Amount of adjustment approved representing prorated sales losses

$ 38,500,000

$ 25,300,000

Cost Recovery Mechanisms | ACC | 2013 DSMAC

Settlement Agreement

Amount of proposed budget

$ 87,600,000

Amount of approved budget

$ 68,900,000

Rate matter, cumulative energy savings for current year percentage

5.00%

Cost Recovery Mechanisms | ACC | 2014 DSMAC

Settlement Agreement

Amount of approved budget

$ 68,900,000

Cost Recovery Mechanisms | ACC | 2015 DSMAC

Settlement Agreement

Amount of proposed budget

$ 68,900,000

Rate matter number of resource savings projects | project

3

Cost Recovery Mechanisms | ACC | 2016 DSMAC

Settlement Agreement

Amount of proposed budget

$ 68,900,000

Rate matter, proposed rate reduction percentage

12.00%

Cost Recovery Mechanisms | ACC | RES

Settlement Agreement

Plan term

5 years

Cost Recovery Mechanisms | ACC | RES implementation plan covering 2014-2018 timeframe

Settlement Agreement

Amount of proposed budget

$ 154,000,000

Amount of approved budget

$ 152,000,000

Cost Recovery Mechanisms | ACC | Arizona Renewable Energy Standard and Tariff 2016

Settlement Agreement

Amount of proposed budget

$ 148,000,000

Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA)

Settlement Agreement

Maximum increase (decrease) in PSA rate (in dollars per kWh) | $ / kWh

0.004

PSA rate (in dollars per kWh) | $ / kWh

0.000887

Cost Recovery Mechanisms | FERC | Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters

Settlement Agreement

increase (decrease) in annual wholesale transmission rates

$ (17,600,000)

$ 5,900,000

AZ Sun Program | Filing with the Arizona Corporation Commission | Arizona Renewable Energy Standard and Tariff 2014

Settlement Agreement

Rate matter additional capacity from AZ Sun projects | MW

20

Alternative to AZ Sun Program | Filing with the Arizona Corporation Commission | Arizona Renewable Energy Standard and Tariff 2014

Settlement Agreement

Rate matter additional capacity from AZ Sun projects | MW

10

Request to build additional utility scale solar, number of customers | Customer

1,500

Alternative to AZ Sun Program, Phase 1 | Filing with the Arizona Corporation Commission | Arizona Renewable Energy Standard and Tariff 2014

Settlement Agreement

Rate matter additional capacity from AZ Sun projects | MW

8

Alternative to AZ Sun Program Phase 2 | Filing with the Arizona Corporation Commission | Arizona Renewable Energy Standard and Tariff 2014

Settlement Agreement

Rate matter additional capacity from AZ Sun projects | MW

2

Subsequent Event | Cost Recovery Mechanisms | Lost Fixed Cost Recovery Mechanism

Settlement Agreement

Amount of adjustment representing prorated sales losses pending approval

$ 46,400,000

Increase in Amount of Adjustment Representing Prorated Sales Losses

$ 7,900,000

Subsequent Event | Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA)

Settlement Agreement

PSA rate (in dollars per kWh) | $ / kWh

0.001678

Forward component of PSA rate (in dollars per kWh) | $ / kWh

0.001975

Historical component of PSA rate (in dollars per kWh) | $ / kWh

(0.000297)

Transition component of PSA rate (in dollars per KWh) | $ / kWh

(0.004936)

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in regulatory asset
Deferred fuel and purchased power	$ 14,997	$ (26,927)	$ 21,678
Deferred fuel and purchased power amortization	1,617	40,757	31,190
ARIZONA PUBLIC SERVICE COMPANY
Change in regulatory asset
Deferred fuel and purchased power	14,997	(26,927)	21,678
Deferred fuel and purchased power amortization	1,617	40,757	31,190
ACC | ARIZONA PUBLIC SERVICE COMPANY | Power Supply Adjustor (PSA) | Cost Recovery Mechanisms
Change in regulatory asset
Beginning balance	6,926	20,755
Deferred fuel and purchased power	(14,997)	26,927
Deferred fuel and purchased power amortization	(1,617)	(40,756)
Ending balance	$ (9,688)	$ 6,926	$ 20,755

Regulatory Matters - Four Corne

Regulatory Matters - Four Corners and Cholla (Details) $ in Millions	Dec. 23, 2014USD ($)	Dec. 30, 2013USD ($)MW	Jul. 31, 2012	Dec. 31, 2015USD ($)
Acquisition
Regulatory asset amortization period			3 years
Retired power plant costs | APS
Acquisition
Regulatory asset, net book value				$ 122
SCE | Four Corners | APS
Acquisition
Regulatory assets				12
Net receipt due to negotiation of alternate arrangement		$ 40
Capacity rights over the Arizona transmission system assign to third-parties | MW		1,555
Capacity rights related to marketing and trading group for transmission of the additional power received assign to third-parties | MW		300
Four Corners Units 4 and 5 | SCE | APS
Acquisition
Ownership interest acquired		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1
Four Corners Units 4 and 5 | SCE | Four Corners cost deferral | APS
Acquisition
Regulatory assets				$ 70
Regulatory asset amortization period				10 years

Regulatory Matters - Schedule o

Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Detail of regulatory assets
Regulatory assets, current	$ 149,555	$ 136,734
Regulatory assets, non-current	1,214,146	1,054,087
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	619,223	485,037
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	9,913	9,913
Regulatory assets, non-current	127,518	136,182
Income taxes - AFUDC equity
Detail of regulatory assets
Regulatory assets, current	5,495	4,813
Regulatory assets, non-current	133,712	118,396
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	71,852	51,209
Regulatory assets, non-current	69,697	46,233
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	6,689	6,689
Regulatory assets, non-current	63,582	70,565
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,766	1,716
Regulatory assets, non-current	48,462	46,200
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	45,507	37,612
Regulatory assets, non-current	0	0
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	18,143	34,440
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	34,751	34,162
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	50,453	30,283
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,515	1,435
Regulatory assets, non-current	16,375	16,410
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,520	1,528
Regulatory assets, non-current	12,163	13,756
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	4,543	9,086
Regulatory assets, non-current	0	4,543
Mead-Phoenix transmission line CIAC
Detail of regulatory assets
Regulatory assets, current	332	332
Regulatory assets, non-current	11,040	11,372
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	0	6,926
Regulatory assets, non-current	0	0
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	418	418
Regulatory assets, non-current	6,085	6,503
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	0	4,238
Regulatory assets, non-current	0	0
Other
Detail of regulatory assets
Regulatory assets, current	5	819
Regulatory assets, non-current	$ 2,942	$ 5

Regulatory Matters - Schedule60

Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Detail of regulatory liabilities
Regulatory liabilities, current	$ 145,766	$ 130,549
Regulatory liabilities, non-current	994,152	1,051,196
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	277,554	295,546
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	39,746	31,033
Regulatory liabilities, non-current	240,367	272,825
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	34,100	32,317
Regulatory liabilities, non-current	179,521	198,599
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	3,604	3,505
Regulatory liabilities, non-current	97,175	92,727
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	1,113	371
Regulatory liabilities, non-current	72,454	72,423
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	3,051	4,396
Regulatory liabilities, non-current	67,437	65,594
Renewable energy standard (b)
Detail of regulatory liabilities
Regulatory liabilities, current	43,773	24,596
Regulatory liabilities, non-current	4,365	22,677
Demand side management (b)
Detail of regulatory liabilities
Regulatory liabilities, current	6,079	31,335
Regulatory liabilities, non-current	19,115	0
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	13,678	12,069
Deferred fuel and purchased power (b) (c)
Detail of regulatory liabilities
Regulatory liabilities, current	9,688	0
Regulatory liabilities, non-current	0	0
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,000	2,000
Regulatory liabilities, non-current	6,000	8,000
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	8,920	1,200
Other
Detail of regulatory liabilities
Regulatory liabilities, current	2,550	934
Regulatory liabilities, non-current	$ 7,565	$ 9,535

Income Taxes (Details)

Income Taxes (Details) - USD ($)	Apr. 04, 2013	Feb. 17, 2011	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes
Decrease in prior period uncertain tax positions			$ 10,244,000	$ 2,282,000	$ 108,099,000
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less than)			1,000,000
General business tax credit carryforwards that will begin to expire in 2031			82,000,000
Amount of federal and state loss carryforwards which will begin to expire in 2019			3,000,000
Decrease in long term deferred tax liability due to adoption of regulations			26,000,000
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Decrease in prior period uncertain tax positions			10,244,000	$ 2,282,000	107,918,000
Third quarter 2009
Income Taxes
Decrease in prior period uncertain tax positions					67,000,000
Tax Years 2008 and 2009
Income Taxes
Decrease in prior period uncertain tax positions					$ 41,000,000
ARIZONA | State Jurisdiction | ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Phase-in period of corporate income tax rate reductions beginning in 2014		4 years
Decrease in long term deferred tax liability due to rate changes			75,000,000
NEW MEXICO | State Jurisdiction | ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Phase-in period of corporate income tax rate reductions beginning in 2014	5 years
Decrease in long term deferred tax liability due to rate changes			2,000,000
Palo Verde VIE
Income Taxes
Income tax expense benefit attributable to non controlling interests			$ 0

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	$ 44,775	$ 41,997	$ 133,422
Additions for tax positions of the current year	2,175	4,309	3,516
Additions for tax positions of prior years	0	751	13,158
Reductions for tax positions of prior years for:
Changes in judgment	(10,244)	(2,282)	(108,099)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	(2,259)	0	0
Total unrecognized tax benefits, end of the year	34,447	44,775	41,997
ARIZONA PUBLIC SERVICE COMPANY
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	44,775	41,997	133,241
Additions for tax positions of the current year	2,175	4,309	3,516
Additions for tax positions of prior years	0	751	13,158
Reductions for tax positions of prior years for:
Changes in judgment	(10,244)	(2,282)	(107,918)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	(2,259)	0	0
Total unrecognized tax benefits, end of the year	$ 34,447	$ 44,775	$ 41,997

Income Taxes - Summary of Unrec

Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	$ 9,523	$ 11,207	$ 9,827
Unrecognized tax benefit interest expense/(benefit) recognized	(161)	752	(3,716)
Unrecognized tax benefit interest accrued	804	965	213
ARIZONA PUBLIC SERVICE COMPANY
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	9,523	11,207	9,827
Unrecognized tax benefit interest expense/(benefit) recognized	(161)	752	(3,716)
Unrecognized tax benefit interest accrued	$ 804	$ 965	$ 213

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal									$ (12,335)	$ 25,054	$ (81,784)
State									4,763	10,382	10,537
Total current									(7,572)	35,436	(71,247)
Deferred:
Federal									221,505	167,365	279,973
State									23,787	17,904	21,865
Total deferred									245,292	185,269	301,838
Income tax expense	$ 22,847	$ 139,555	$ 67,371	$ 7,947	$ 5,007	$ 134,753	$ 74,540	$ 6,405	237,720	220,705	230,591
ARIZONA PUBLIC SERVICE COMPANY
Current:
Federal									6,485	40,115	(97,531)
State									7,813	15,598	11,983
Total current									14,298	55,713	(85,548)
Deferred:
Federal									208,326	165,027	305,389
State									23,217	16,620	25,254
Total deferred									231,543	181,647	330,643
Income tax expense									$ 245,841	$ 237,360	$ 245,095

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
Federal income tax rate (as a percent)									35.00%	35.00%	35.00%
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at 35% statutory rate									$ 242,869	$ 225,540	$ 234,695
State income tax net of federal income tax benefit									18,265	18,149	21,387
Credits and favorable adjustments related to prior years resolved in current year									(2,169)	0	(3,356)
Medicare Subsidy Part-D									837	830	823
Allowance for equity funds used during construction (see Note 1)									(9,711)	(8,523)	(6,997)
Palo Verde VIE noncontrolling interest (see Note 18)									(6,626)	(9,135)	(11,862)
Investment tax credit amortization									(5,527)	(4,928)	(3,548)
Other									(218)	(1,228)	(551)
Income tax expense	$ 22,847	$ 139,555	$ 67,371	$ 7,947	$ 5,007	$ 134,753	$ 74,540	$ 6,405	$ 237,720	$ 220,705	$ 230,591
ARIZONA PUBLIC SERVICE COMPANY
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
Federal income tax rate (as a percent)									35.00%	35.00%	35.00%
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at 35% statutory rate									$ 250,267	$ 239,638	$ 246,384
State income tax net of federal income tax benefit									20,433	21,148	23,970
Credits and favorable adjustments related to prior years resolved in current year									(1,892)	0	(3,231)
Medicare Subsidy Part-D									837	830	823
Allowance for equity funds used during construction (see Note 1)									(9,711)	(8,523)	(6,997)
Palo Verde VIE noncontrolling interest (see Note 18)									(6,626)	(9,135)	(11,862)
Investment tax credit amortization									(5,527)	(4,928)	(3,548)
Other									(1,940)	(1,670)	(444)
Income tax expense									$ 245,841	$ 237,360	$ 245,095

Income Taxes Income Taxes - Def

Income Taxes Income Taxes - Deferred Income Tax Liability Recognized on the Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Net deferred income tax liability recognized on the Consolidated Balance Sheets
Deferred tax asset, current	$ 0	$ 122,232
Long-term liability	(2,723,425)	(2,582,636)
Deferred income taxes — net	(2,723,425)	(2,460,404)
ARIZONA PUBLIC SERVICE COMPANY
Net deferred income tax liability recognized on the Consolidated Balance Sheets
Deferred tax asset, current	0	55,253
Long-term liability	(2,764,489)	(2,571,365)
Deferred income taxes — net	$ (2,764,489)	$ (2,516,112)

Income Taxes - Components of De

Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
DEFERRED TAX ASSETS
Risk management activities	$ 70,498	$ 57,505
Regulatory liabilities:
Asset retirement obligation and removal costs	216,765	229,772
Unamortized investment tax credits	100,779	96,232
Other postretirement liabilities	83,034	90,496
Other	60,707	60,409
Pension liabilities	191,028	205,227
Renewable energy incentives	60,956	65,169
Credit and loss carryforwards	59,557	68,347
Other	149,033	138,729
Total deferred tax assets	992,357	1,011,886
DEFERRED TAX LIABILITIES
Plant-related	(3,116,752)	(2,958,369)
Risk management activities	(10,626)	(12,171)
Other postretirement assets	(71,737)	(59,170)
Regulatory assets:
Allowance for equity funds used during construction	(54,110)	(48,286)
Deferred fuel and purchased power	0	(2,498)
Deferred fuel and purchased power — mark-to-market	(55,020)	(38,187)
Pension benefits	(240,692)	(191,747)
Retired power plant costs (see Note 3)	(53,420)	(57,255)
Other	(108,441)	(99,123)
Other	(4,984)	(5,484)
Total deferred tax liabilities	3,715,782	3,472,290
Deferred income taxes — net	(2,723,425)	(2,460,404)
ARIZONA PUBLIC SERVICE COMPANY
DEFERRED TAX ASSETS
Risk management activities	70,498	57,505
Regulatory liabilities:
Asset retirement obligation and removal costs	216,765	229,772
Unamortized investment tax credits	100,779	96,232
Other postretirement liabilities	83,034	90,496
Other	60,707	60,409
Pension liabilities	181,787	194,541
Renewable energy incentives	60,956	65,169
Credit and loss carryforwards	0	0
Other	176,016	161,379
Total deferred tax assets	950,542	955,503
DEFERRED TAX LIABILITIES
Plant-related	(3,116,752)	(2,958,369)
Risk management activities	(10,626)	(12,171)
Other postretirement assets	(70,986)	(58,495)
Regulatory assets:
Allowance for equity funds used during construction	(54,110)	(48,286)
Deferred fuel and purchased power	0	(2,498)
Deferred fuel and purchased power — mark-to-market	(55,020)	(38,187)
Pension benefits	(240,692)	(191,747)
Retired power plant costs (see Note 3)	(53,420)	(57,255)
Other	(108,441)	(99,123)
Other	(4,984)	(5,484)
Total deferred tax liabilities	3,715,031	3,471,615
Deferred income taxes — net	$ (2,764,489)	$ (2,516,112)

Lines of Credit and Short-Ter68

Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Lines of Credit and Short-Term Borrowings
Commercial paper	$ 0	$ (147,400)
Pinnacle West
Lines of Credit and Short-Term Borrowings
Commercial paper	$ 0	$ 0
Commitment fees (as a percent)	0.125%	0.175%
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commercial paper	$ 0	$ (147,400)
Commitment fees (as a percent)	0.10%	0.125%
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed	$ 1,200,000	$ 1,200,000
Unused amount	1,200,000	1,052,600
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Amount committed	200,000	200,000
Unused amount	200,000	200,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Amount committed	1,000,000	1,000,000
Unused amount	$ 1,000,000	$ 852,600

Lines of Credit and Short-Ter69

Lines of Credit and Short-Term Borrowings (Details)	Dec. 31, 2015USD ($)Facility	Sep. 02, 2015USD ($)	Dec. 31, 2014USD ($)	Feb. 06, 2013USD ($)
Lines of Credit and Short-Term Borrowings
Commercial paper	$ 0		$ 147,400,000
Pinnacle West
Lines of Credit and Short-Term Borrowings
Commercial paper	0		0
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commercial paper	0		147,400,000
ARIZONA PUBLIC SERVICE COMPANY | ACC
Debt Provisions
Percentage of APS's capitalization used in calculation of short-term debt authorization				7.00%
Required amount to be used in purchases of natural gas and power which is used in calculation of short-term debt authorization				$ 500,000,000
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed	1,200,000,000		1,200,000,000
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Amount committed	200,000,000		200,000,000
Revolving credit facility | Pinnacle West | Revolving credit facility maturing in 2019
Lines of Credit and Short-Term Borrowings
Amount committed	200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	300,000,000
Long-term line of credit	0
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Amount committed	1,000,000,000		$ 1,000,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facilities maturing in 2019 and 2020
Lines of Credit and Short-Term Borrowings
Amount committed	1,000,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	1,400,000,000
Long-term line of credit	$ 0
Number of credit facilities | Facility	2
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing September 2020
Lines of Credit and Short-Term Borrowings
Amount committed		$ 500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	$ 700,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing in May 2019
Lines of Credit and Short-Term Borrowings
Amount committed	500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	700,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing April 2018
Lines of Credit and Short-Term Borrowings
Amount committed		$ 500,000,000
Letter of credit | Pinnacle West | Revolving credit facility maturing in 2019
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit	0
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit	79,000,000
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facilities maturing in 2019 and 2020
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit	0
Commercial paper | Pinnacle West | Revolving credit facility maturing in 2019
Lines of Credit and Short-Term Borrowings
Commercial paper	0
Commercial paper | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Maximum commercial paper support available under credit facility	$ 250,000,000

Long-Term Debt and Liquidity 70

Long-Term Debt and Liquidity Matters (Details) - USD ($)

May. 19, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 08, 2015

Nov. 17, 2015

Nov. 06, 2015

Jun. 26, 2015

May. 28, 2015

Jan. 12, 2015

Feb. 06, 2013

Feb. 05, 2013

Long-Term Debt and Liquidity Matters [Line Items]

Repayments of long-term debt

$ 415,570,000

$ 652,578,000

$ 122,828,000

Debt Provisions

Total shareholder equity

$ 4,583,917,000

4,367,493,000

Maximum

Debt Provisions

Ratio of consolidated debt to consolidated capitalization (as a percent)

65.00%

ARIZONA PUBLIC SERVICE COMPANY

Long-Term Debt and Liquidity Matters [Line Items]

Repayments of long-term debt

$ 415,570,000

527,578,000

122,828,000

Debt Provisions

Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)

46.00%

Total shareholder equity

$ 4,679,254,000

4,478,243,000

ARIZONA PUBLIC SERVICE COMPANY | ACC

Debt Provisions

Total shareholder equity

4,700,000,000

Total capitalization

8,600,000,000

Dividend restrictions, shareholder equity required

$ 3,400,000,000

Long term debt authorization

$ 5,100,000,000

$ 4,200,000,000

ARIZONA PUBLIC SERVICE COMPANY | Minimum | ACC

Debt Provisions

Required common equity ratio ordered by ACC (as a percent) (at least)

40.00%

Pinnacle West

Long-Term Debt and Liquidity Matters [Line Items]

Repayments of long-term debt

$ 0

125,000,000

$ 0

Debt Provisions

Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)

47.00%

Total shareholder equity

$ 4,583,917,000

$ 4,367,493,000

Unsecured senior notes 2.20 percent matures on 15 January, 2020 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

$ 250,000,000

Interest rate (as a percent)

2.20%

Unsecured senior notes 3.15 percent matures on 15 May, 2025 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

$ 300,000,000

Interest rate (as a percent)

3.15%

Unsecured senior notes 4.65 percent matures on 15 May, 2015 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes

Long-Term Debt and Liquidity Matters [Line Items]

Interest rate (as a percent)

4.65%

Repayments of long-term debt

$ 300,000,000

Arizona pollution control revenue refunding bond, 2009 series B | ARIZONA PUBLIC SERVICE COMPANY

Long-Term Debt and Liquidity Matters [Line Items]

Principal balance repaid

$ 32,000,000

Arizona pollution control revenue refunding bond, 2009 series B | ARIZONA PUBLIC SERVICE COMPANY | Current maturities of long-term debt

Long-Term Debt and Liquidity Matters [Line Items]

Principal balance repaid

$ 32,000,000

Term loan facility maturing June 26, 2018 | ARIZONA PUBLIC SERVICE COMPANY | Term loan

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

$ 50,000,000

Arizona pollution control corporation revenue refunding bonds, 2009 series A | ARIZONA PUBLIC SERVICE COMPANY | Current maturities of long-term debt

Long-Term Debt and Liquidity Matters [Line Items]

Principal balance repaid

$ 38,150,000

Unsecured senior notes 4.35 percent mature on 15 November, 2020 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

$ 250,000,000

Interest rate (as a percent)

4.35%

Arizona pollution control corporation revenue refunding bonds, 2009 series C | ARIZONA PUBLIC SERVICE COMPANY | Current maturities of long-term debt

Long-Term Debt and Liquidity Matters [Line Items]

Principal balance repaid

$ 32,000,000

Long-Term Debt and Liquidity 71

Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Long-Term Debt and Liquidity Matters [Line Items]
Total long-term debt	$ 3,819,971	$ 3,390,143
Long-term debt less current maturities	3,462,391	3,006,573
APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	3,728,555
Unamortized discount	(10,374)	(9,206)
Unamortized premium	4,686	4,866
Unamortized debt issue costs	(27,896)	(24,642)
Total long-term debt	3,694,971	3,265,143
Less current maturities	(357,580)	(383,570)
Total long-term debt less current maturities	3,337,391	2,881,573
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	3,853,555
Total long-term debt	125,000	125,000
Long-term debt less current maturities	125,000	125,000
Pollution Control Bonds - Variable | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	92,405	$ 156,405
Less current maturities	$ (108,000)
Pollution Control Bonds - Variable | APS | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	0.01%	0.03%
Pollution Control Bonds - Variable | APS | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	0.24%	0.27%
Pollution Control Bonds - Fixed | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 211,150	$ 249,300
Interest Rates, low end of range (as a percent)	1.75%	1.75%
Interest Rates, high end of range (as a percent)	5.75%	5.75%
Total Pollution Control Bonds | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 303,555	$ 405,705
Senior unsecured notes | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 3,375,000	$ 2,875,000
Interest Rates, low end of range (as a percent)	2.20%	2.20%
Interest Rates, high end of range (as a percent)	8.75%	8.75%
Palo Verde sale leaseback lessor notes | APS
Long-Term Debt and Liquidity Matters [Line Items]
Palo Verde sale leaseback lessor notes	$ 0	$ 13,420
Interest rate (as a percent)	8.00%	8.00%
Term loan facility | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Total long-term debt	$ 125,000	$ 125,000
Weighted-average interest rate (as a percent)	1.174%	1.019%
Senior unsecured notes maturing through 2015 | APS
Long-Term Debt and Liquidity Matters [Line Items]
Less current maturities	$ (250,000)
Term loan | APS
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	1.024%
Term loan | Term loan facility maturing June 26, 2018 | APS
Long-Term Debt and Liquidity Matters [Line Items]
Term loan	$ 50,000	$ 0

Long-Term Debt and Liquidity 72

Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) $ in Thousands	Dec. 31, 2015USD ($)
Pinnacle West
Principal payments due on long-term debt
2,016	$ 357,580
2,017	125,000
2,018	82,000
2,019	500,000
2,020	250,000
Thereafter	2,538,975
Total	3,853,555
ARIZONA PUBLIC SERVICE COMPANY
Principal payments due on long-term debt
2,016	357,580
2,017	0
2,018	82,000
2,019	500,000
2,020	250,000
Thereafter	2,538,975
Total	$ 3,728,555

Long-Term Debt and Liquidity 73

Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 3,819,971	$ 3,390,143
Fair Value	4,106,367	3,839,108
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	125,000	125,000
Fair Value	125,000	125,000
ARIZONA PUBLIC SERVICE COMPANY
Estimated fair value of long-term debt, including current maturities
Carrying Amount	3,694,971	3,265,143
Fair Value	$ 3,981,367	$ 3,714,108

Retirement Plans and Other Be74

Retirement Plans and Other Benefits Retirement Plans and Other Benefits (Details)	1 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2011USD ($)	Jan. 01, 2015Age
Plan Design Changes [Abstract]
Assets for other postretirement benefits		$ 185,997,000	$ 152,290,000
Amount of other postretirement benefit trust assets for union employee medical costs			100,000,000
Amount of pension and other postretirement benefit costs deferred					$ 14,000,000	$ 11,000,000
Regulatory asset amortization period	3 years
Amortization of regulatory assets		5,000,000	8,000,000	$ 8,000,000	$ 4,000,000
Change in mortality assumptions impact on pension and other postretirement obligations			67,000,000
Partnership funding commitments, contribution amount (up to)		75,000,000
Partnership funding commitments, funded amount		40,000,000
Pension Benefits
Plan Design Changes [Abstract]
Assets for other postretirement benefits		$ 0	0
Expected long-term return on plan assets for next fiscal year (as a percent)		6.90%
Contributions
Employer's contributions under the plan		$ 100,000,000	175,000,000	141,000,000
Minimum contributions under MAP-21
Minimum contributions under MAP-21		0
Voluntary employer contributions over next three years (up to)		$ 300,000,000
Pension Benefits | Fixed income securities
Target asset allocation
Target allocation (as a percent)		58.00%
Target allocation, minimum (as a percent)		55.00%
Target allocation, maximum (as a percent)		61.00%
Actual asset allocation (as a percent)		60.00%
Pension Benefits | Return-generating assets
Target asset allocation
Target allocation (as a percent)		42.00%
Target allocation, minimum (as a percent)		39.00%
Target allocation, maximum (as a percent)		45.00%
Actual asset allocation (as a percent)		40.00%
Pension Benefits | Developed equities
Target asset allocation
Target allocation (as a percent)		22.00%
Pension Benefits | Emerging equities
Target asset allocation
Target allocation (as a percent)		6.00%
Pension Benefits | Alternative investments
Target asset allocation
Target allocation (as a percent)		14.00%
Other postretirement benefits
Plan Design Changes [Abstract]
Age eligible for benefit | Age							65
Effect of plan amendment on net periodic benefit cost			10,000,000
Effect of plan amendment on expense			5,000,000
Effect of plan amendment on accumulated benefit obligation			316,000,000
Assets for other postretirement benefits		$ 185,997,000	152,290,000
Expected long-term return on plan assets for next fiscal year (as a percent)		4.74%
Contributions
Employer's contributions under the plan		$ 791,000	770,000	14,000,000
Expected employer contributions
2,016		1,000,000
2,017		1,000,000
2,018		$ 1,000,000
Other postretirement benefits | Fixed income
Target asset allocation
Actual asset allocation (as a percent)		40.00%
Other postretirement benefits | Non-fixed income
Target asset allocation
Actual asset allocation (as a percent)		60.00%
Pinnacle West
Employee savings plan benefits
Expenses recorded for the defined contribution savings plan		$ 9,000,000	9,000,000	9,000,000
ARIZONA PUBLIC SERVICE COMPANY
Plan Design Changes [Abstract]
Assets for other postretirement benefits		$ 182,625,000	149,260,000
Employee savings plan benefits
APS's employees share of total cost of the plans (as a percent)		99.00%
ARIZONA PUBLIC SERVICE COMPANY | Pension Benefits
Contributions
Employer's contributions under the plan		$ 100,000,000	175,000,000	140,000,000
ARIZONA PUBLIC SERVICE COMPANY | Other postretirement benefits
Contributions
Employer's contributions under the plan		$ 1,000,000	$ 1,000,000	$ 14,000,000

Retirement Plans and Other Be75

Retirement Plans and Other Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	$ 59,627	$ 53,080	$ 64,195
Interest cost on benefit obligation	123,983	129,194	112,392
Expected return on plan assets	(179,231)	(158,998)	(146,333)
Amortization of prior service cost (credit)	594	869	1,097
Amortization of net actuarial loss	31,056	10,963	39,852
Net periodic benefit cost	36,029	35,108	71,203
Portion of cost charged to expense	20,036	21,985	38,968
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	16,827	18,139	23,597
Interest cost on benefit obligation	28,102	41,243	41,536
Expected return on plan assets	(36,855)	(46,400)	(45,717)
Amortization of prior service cost (credit)	(37,968)	(9,626)	(179)
Amortization of net actuarial loss	4,881	1,175	11,310
Net periodic benefit cost	(25,013)	4,531	30,547
Portion of cost charged to expense	$ (10,391)	$ 6,000	$ 18,469

Retirement Plans and Other Be76

Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	$ 3,078,648	$ 2,646,530
Service cost	59,627	53,080	$ 64,195
Interest cost	123,983	129,194	112,392
Benefit payments	(137,115)	(128,550)
Actuarial (gain) loss	(91,340)	378,394
Plan amendments	0	0
Benefit obligation at the end of the period	3,033,803	3,078,648	2,646,530
Change in Plan Assets
Balance at the beginning of the period	2,615,404	2,264,121
Actual return on plan assets	(44,690)	292,992
Employer's contributions under the plan	100,000	175,000	141,000
Benefit payments	(127,940)	(116,709)
Balance at the end of the period	2,542,774	2,615,404	2,264,121
Funded Status at the end of the period	(491,029)	(463,244)
Other Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	682,335	890,418
Service cost	16,827	18,139	23,597
Interest cost	28,102	41,243	41,536
Benefit payments	(24,988)	(29,054)
Actuarial (gain) loss	(55,256)	150,188
Plan amendments	0	(388,599)
Benefit obligation at the end of the period	647,020	682,335	890,418
Change in Plan Assets
Balance at the beginning of the period	834,625	748,339
Actual return on plan assets	(2,399)	105,223
Employer's contributions under the plan	791	770	14,000
Benefit payments	0	(19,707)
Balance at the end of the period	833,017	834,625	$ 748,339
Funded Status at the end of the period	$ 185,997	$ 152,290

Retirement Plans and Other Be77

Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
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

Retirement Plans and Other Be78

Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Amounts recognized on the Consolidated Balance Sheets
Assets for other postretirement benefits	$ 185,997	$ 152,290
Pension Benefits
Amounts recognized on the Consolidated Balance Sheets
Assets for other postretirement benefits	0	0
Current liability	(10,031)	(9,508)
Noncurrent liability	(480,998)	(453,736)
Net amount recognized	(491,029)	(463,244)
Other Benefits
Amounts recognized on the Consolidated Balance Sheets
Assets for other postretirement benefits	185,997	152,290
Current liability	0	0
Noncurrent liability	0	0
Net amount recognized	$ 185,997	$ 152,290

Retirement Plans and Other Be79

Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Details related to accumulated other comprehensive loss
Accumulated other comprehensive loss	$ 37,593	$ 57,756
Other Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	127,124	148,006
Prior service cost (credit)	(341,301)	(379,269)
APS's portion recorded as a regulatory asset	213,621	230,916
Income tax benefit	925	851
Accumulated other comprehensive loss	369	504
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	3,784
Prior service cost (credit)	(37,884)
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	(34,100)
Pension Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	679,501	577,976
Prior service cost (credit)	609	1,203
APS's portion recorded as a regulatory asset	(619,223)	(485,037)
Income tax benefit	(23,663)	(36,890)
Accumulated other comprehensive loss	37,224	$ 57,252
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	38,923
Prior service cost (credit)	527
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	$ 39,450

Retirement Plans and Other Be80

Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted-average assumptions used to determine benefit obligations
Rate of compensation increase (as a percent)	4.00%		4.00%	4.00%
Initial pre-65 healthcare cost trend rate (as a percent)			7.00%	7.00%
Initial post-65 healthcare cost trend rate (as a percent)			5.00%	5.00%
Ultimate health care cost trend rate (as a percent)			5.00%	5.00%
Number of years to ultimate trend rate (pre-65 participants)			4 years	4 years
Number of years to ultimate trend rate (post-65 participants)			0 years	0 years
Weighted-average assumptions used to determine net periodic benefit costs
Initial pre-65 health care cost trend rate (as a percent)	7.50%	7.50%	7.00%		7.50%
Initial post-65 health care cost trend rate (as a percent)	5.00%	7.50%	5.00%		7.50%
Ultimate healthcare cost trend rate (as a percent)	5.00%	5.00%	5.00%		5.00%
Number of years to ultimate trend rate (pre-65 participants)	4 years	4 years	4 years		4 years
Number of years to ultimate trend rate (post-65 participants)	0 years	4 years	0 years		4 years
Pension Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	4.02%		4.37%	4.02%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.88%	4.88%	4.02%		4.01%
Rate of compensation increase (as a percent)	4.00%	4.00%	4.00%		4.00%
Expected long-term return on plan assets (as a percent)	6.90%	6.90%	6.90%		7.00%
Other Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	4.14%		4.52%	4.14%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.41%	5.10%	4.14%		4.20%
Expected long-term return on plan assets (as a percent)	4.25%	6.80%	4.45%		7.00%
Effects of one percentage point change in the assumed initial and ultimate health care cost trend rates
Effect of 1% increase on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants			$ 8,834
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants			(5,890)
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs			9,069
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs			(6,949)
Effect of 1% increase on the accumulated other postretirement benefit obligation			100,322
Effect of 1% decrease on the accumulated other postretirement benefit obligation			$ (80,332)

Retirement Plans and Other Be81

Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	$ 2,542,774	$ 2,615,404	$ 2,264,121
Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	14,467	16,883
Fair value of plan assets	2,542,774	2,615,404
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	640,679	556,660
Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,845,531	2,013,932
Pension Benefits | Significant Unobservable Inputs (Level 3) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	42,097	27,929
Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	833,017	834,625	748,339
Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	3,096	4,100
Fair value of plan assets	833,017	834,625
Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	454,891	414,204
Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	375,030	416,321
Other Benefits | Significant Unobservable Inputs (Level 3) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	0	0
Cash and cash equivalents | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	1,893	387
Cash and cash equivalents | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,893	387
Cash and cash equivalents | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	240	318
Cash and cash equivalents | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	240	318
Corporate | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	1,108,736	1,162,096
Corporate | Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,108,736	1,162,096
Corporate | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	217,026	187,961
Corporate | Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	217,026	187,961
U.S. Treasury | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	274,778	291,817
U.S. Treasury | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	274,778	291,817
U.S. Treasury | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	131,435	130,967
U.S. Treasury | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	131,435	130,967
Other (a) | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	113,008	113,265
Other (a) | Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	113,008	113,265
Other (a) | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	31,106	35,291
Other (a) | Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	31,106	35,291
U.S. companies | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	233,021	246,387
U.S. companies | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	233,021	246,387
U.S. companies | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	253,193	265,106
U.S. companies | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	253,193	265,106
International companies | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	14,680	18,069
International companies | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	14,680	18,069
International companies | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	12,390	17,813
International companies | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	12,390	17,813
U.S. equities | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	130,097	127,336
U.S. equities | Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	130,097	127,336
U.S. equities | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	81,516	88,258
U.S. equities | Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	81,516	88,258
International equities | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	185,892	317,167
International equities | Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	185,892	317,167
International equities | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	28,539	85,746
International equities | Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	28,539	85,746
Real estate | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	150,359	129,715
Real estate | Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	150,359	129,715
Real estate | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	13,512	11,657
Real estate | Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	13,512	11,657
Partnerships | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	169,937	166,266
Partnerships | Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	127,840	138,337
Partnerships | Pension Benefits | Significant Unobservable Inputs (Level 3) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	42,097	27,929
Mutual funds - International equities | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	116,307
Mutual funds - International equities | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	116,307
Mutual funds - International equities | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	52,568
Mutual funds - International equities | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	52,568
Short-term investments and other | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	14,467	16,883
Fair value of plan assets	44,066	42,899
Short-term investments and other | Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	29,599	26,016
Short-term investments and other | Pension Benefits | Significant Unobservable Inputs (Level 3)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	42,097	27,929	$ 8,660
Short-term investments and other | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	3,096	4,100
Fair value of plan assets	11,492	11,508
Short-term investments and other | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	5,065
Short-term investments and other | Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	$ 3,331	$ 7,408

Retirement Plans and Other Be82

Retirement Plans and Other Benefits - Changes in Fair Value (Details) - Pension Benefits - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes in fair value for assets that are measured at fair value on a recurring basis
Balance at the beginning of the period	$ 2,615,404	$ 2,264,121
Balance at the end of the period	2,542,774	2,615,404
Short-term investments and other | Significant Unobservable Inputs (Level 3)
Changes in fair value for assets that are measured at fair value on a recurring basis
Balance at the beginning of the period	27,929	8,660
Actual return on assets still held	2,789	927
Purchases	13,187	19,984
Sales	(1,808)	(1,642)
Transfers in and/or out of Level 3	0	0
Balance at the end of the period	$ 42,097	$ 27,929

Retirement Plans and Other Be83

Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2015USD ($)
Pension Benefits
Estimated Future Benefit Payments
2,016	$ 152,146
2,017	171,005
2,018	170,534
2,019	180,700
2,020	188,988
Years 2021-2025	1,023,451
Other Benefits
Estimated Future Benefit Payments
2,016	26,468
2,017	28,444
2,018	30,490
2,019	32,438
2,020	33,982
Years 2021-2025	$ 184,335

Leases (Details)

Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Trust	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 1986Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Lease expense	$ 17,000	$ 18,000	$ 18,000
Pinnacle West
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2,016	9,182
2,017	8,557
2,018	7,045
2,019	6,121
2,020	4,835
Thereafter	61,251
Total future lease commitments	96,991
Palo Verde Lessor Trusts
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Number of VIE lessor trusts | Trust				3
APS
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2,016	8,797
2,017	8,317
2,018	6,880
2,019	5,961
2,020	4,680
Thereafter	61,101
Total future lease commitments	95,736
Lease expense	$ 14,000	$ 15,000	$ 15,000
Number of VIE lessor trusts | Trust	3			3

Jointly-Owned Facilities (Detai

Jointly-Owned Facilities (Details) - ARIZONA PUBLIC SERVICE COMPANY $ in Thousands	Dec. 31, 2015USD ($)
Palo Verde Units 1 and 3
Interests in jointly-owned facilities
Percent Owned	29.10%
Plant in Service	$ 1,744,137
Accumulated Depreciation	1,067,376
Construction Work in Progress	$ 22,228
Palo Verde Unit 2
Interests in jointly-owned facilities
Percent Owned	16.80%
Plant in Service	$ 583,633
Accumulated Depreciation	356,767
Construction Work in Progress	$ 4,142
Palo Verde Common
Interests in jointly-owned facilities
Percent Owned	28.00%
Plant in Service	$ 643,201
Accumulated Depreciation	231,609
Construction Work in Progress	64,069
Palo Verde Sale Leaseback
Interests in jointly-owned facilities
Plant in Service	351,050
Accumulated Depreciation	233,665
Construction Work in Progress	$ 0
Four Corners Units 4, 5 and Common
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	$ 857,555
Accumulated Depreciation	577,321
Construction Work in Progress	$ 77,317
Navajo Generating Station Units 1, 2 and 3
Interests in jointly-owned facilities
Percent Owned	14.00%
Plant in Service	$ 274,640
Accumulated Depreciation	168,132
Construction Work in Progress	$ 4,460
Cholla common facilities
Interests in jointly-owned facilities
Percent Owned	63.30%
Plant in Service	$ 158,623
Accumulated Depreciation	53,777
Construction Work in Progress	$ 1,390
ANPP 500kV System
Interests in jointly-owned facilities
Percent Owned	33.40%
Plant in Service	$ 109,348
Accumulated Depreciation	36,576
Construction Work in Progress	$ 1,594
Navajo Southern System
Interests in jointly-owned facilities
Percent Owned	22.70%
Plant in Service	$ 62,139
Accumulated Depreciation	19,361
Construction Work in Progress	$ 397
Palo Verde - Yuma 500kV System
Interests in jointly-owned facilities
Percent Owned	19.30%
Plant in Service	$ 14,043
Accumulated Depreciation	5,226
Construction Work in Progress	$ 133
Four Corners Switchyards
Interests in jointly-owned facilities
Percent Owned	49.80%
Plant in Service	$ 38,420
Accumulated Depreciation	9,833
Construction Work in Progress	$ 1,687
Phoenix - Mead System
Interests in jointly-owned facilities
Percent Owned	17.10%
Plant in Service	$ 39,089
Accumulated Depreciation	13,173
Construction Work in Progress	$ 151
Palo Verde - Estrella 500kV System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 89,832
Accumulated Depreciation	18,359
Construction Work in Progress	$ 1,008
Morgan-Pinnacle Peak System
Interests in jointly-owned facilities
Percent Owned	64.60%
Plant in Service	$ 129,855
Accumulated Depreciation	11,087
Construction Work in Progress	$ 2,592
Round Valley System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 703
Accumulated Depreciation	286
Construction Work in Progress	$ 0
Palo Verde - Morgan System
Interests in jointly-owned facilities
Percent Owned	87.70%
Plant in Service	$ 12
Accumulated Depreciation	0
Construction Work in Progress	$ 133,813
Hassayampa - North Gila System
Interests in jointly-owned facilities
Percent Owned	80.00%
Plant in Service	$ 164,854
Accumulated Depreciation	1,159
Construction Work in Progress	$ 0
Cholla 500 Switchyard
Interests in jointly-owned facilities
Percent Owned	85.70%
Plant in Service	$ 547
Accumulated Depreciation	15
Construction Work in Progress	$ 0
Saquaro 500 Switchyard
Interests in jointly-owned facilities
Percent Owned	75.00%
Plant in Service	$ 773
Accumulated Depreciation	26
Construction Work in Progress	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)	Jun. 01, 2015USD ($)	Aug. 18, 2014USD ($)	Dec. 31, 2015USD ($)Trust	Dec. 31, 2015USD ($)Trust	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 1986Trust
Palo Verde Nuclear Generating Station [Abstract]
Change in long-term regulatory liabilities				$ 20,535,000	$ (59,618,000)	$ (64,473,000)
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Change in long-term regulatory liabilities				20,535,000	(59,618,000)	(64,473,000)
Maximum insurance against public liability per occurrence for a nuclear incident				13,500,000,000
Maximum available nuclear liability insurance				375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program				13,100,000,000
Maximum assessment per reactor for each nuclear incident				127,300,000
Annual limit per incident with respect to maximum assessment				$ 19,000,000
Number of VIE lessor trusts | Trust			3	3			3
Maximum potential retrospective assessment per incident of APS				$ 111,000,000
Annual payment limitation with respect to maximum potential retrospective assessment				16,600,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde				2,800,000,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment				23,100,000
Collateral assurance provided based on rating triggers				$ 61,700,000
Period to provide collateral assurance based on rating triggers				20 days
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,016			$ 876,000,000	$ 876,000,000
2,017			949,000,000	949,000,000
2,018			737,000,000	737,000,000
2,019			603,000,000	603,000,000
2,020			498,000,000	498,000,000
Thereafter			7,800,000,000	7,800,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal take-or-pay commitments
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,016			170,714,000	170,714,000
2,017			195,428,000	195,428,000
2,018			189,588,000	189,588,000
2,019			193,818,000	193,818,000
2,020			198,160,000	198,160,000
Thereafter			2,270,974,000	2,270,974,000
Total obligation			3,200,000,000	3,200,000,000
Present value of commitments			2,200,000,000	2,200,000,000
Total purchases				211,327,000	236,773,000	$ 188,496,000
ARIZONA PUBLIC SERVICE COMPANY | Renewable energy credits
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,016			42,000,000	42,000,000
2,017			40,000,000	40,000,000
2,018			40,000,000	40,000,000
2,019			40,000,000	40,000,000
2,020			40,000,000	40,000,000
Thereafter			432,000,000	432,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,016			15,000,000	15,000,000
2,017			16,000,000	16,000,000
2,018			18,000,000	18,000,000
2,019			19,000,000	19,000,000
2,020			20,000,000	20,000,000
Thereafter			262,000,000	262,000,000
Total obligation			202,000,000	$ 202,000,000	$ 198,000,000
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Palo Verde Nuclear Generating Station [Abstract]
Litigation settlement, amount		$ 57,400,000
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Litigation settlement, amount		$ 16,700,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal [Member]
Palo Verde Nuclear Generating Station [Abstract]
Proceeds from legal settlements	$ 42,000,000		12,000,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal [Member] | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Proceeds from legal settlements	12,200,000		$ 3,600,000
Change in long-term regulatory liabilities	$ 12,200,000

Commitments and Contingencies87

Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) $ in Millions	Feb. 09, 2016	Aug. 17, 2015USD ($)power_plant	Aug. 06, 2013Defendant	Sep. 08, 2011kVCustomer	Dec. 31, 2015USD ($)
ARIZONA PUBLIC SERVICE COMPANY
Superfund
Costs related to investigation and study under Superfund site					$ 2
Southwest Power Outage
Power outage capacity of transmission line that tripped out of service | kV				500
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost				10 minutes
Number of customers losing service in Yuma area | Customer				69,700
ARIZONA PUBLIC SERVICE COMPANY | Natural Gas Tolling Letter of Credit
Clean Air Act Citizen Lawsuit
Outstanding letters of credit					$ 6.7
ARIZONA PUBLIC SERVICE COMPANY | Contaminated groundwater wells
Superfund
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit | Defendant			24
ARIZONA PUBLIC SERVICE COMPANY | Clean Air Act Citizen Lawsuit
Clean Air Act Citizen Lawsuit
Loss contingency, number of units | power_plant		2
Litigation settlement, percent of settlement		15.00%
Four Corners | Clean Air Act Citizen Lawsuit
Clean Air Act Citizen Lawsuit
Loss contingency, civil penalty amount		$ 1.5
Subsequent Event | Minimum | Loss of perishable inventory and sales
Southwest Power Outage
Time period a decision is reached after oral argument	30 days
Subsequent Event | Maximum | Loss of perishable inventory and sales
Southwest Power Outage
Time period a decision is reached after oral argument	60 days

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details)	Aug. 17, 2015USD ($)power_plant	May. 23, 2013USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Environmental Matters [Abstract]
Clean power plan, optional extension period				2 years
Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost				$ 15,000,000
Cholla | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost				85,000,000
Cholla Units 1-3 | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost				8,000,000
Clean Air Act Citizen Lawsuit | ARIZONA PUBLIC SERVICE COMPANY
Commitments and Contingencies [Line Items]
Loss contingency, number of units | power_plant	2
Clean Air Act Citizen Lawsuit | Four Corners
Commitments and Contingencies [Line Items]
Loss contingency, civil penalty amount	$ 1,500,000
New Mexico Tax Matter | Four Corners
Environmental Matters [Abstract]
Coal severance surtax, penalty, and interest		$ 30,000,000
New Mexico Tax Matter | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Share of the assessment		$ 12,000,000
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit				79,000,000
Equity Lessors Sale Leaseback Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit				158,000,000
Natural Gas Tolling Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit				6,700,000
Four Corners Units 4 and 5 | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost				45,000,000
Four Corners Units 4 and 5 | Navajo Plant | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost				$ 200,000,000
Four Corners Units 4 and 5 | Natural Gas Tolling Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Percentage of share of cost of control				63.00%
Additional percentage share of cost of control				7.00%
Minimum | Four Corners Units 4 and 5 | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost				$ 400,000,000
Regional Haze Rules | Cholla | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost			$ 100,000,000
Mercury and Air Toxic Standards | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost				1,000,000
Coal Combustion Waste | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost				$ 1,000,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes attributable to:
Asset retirement obligations, current	$ 28,573	$ 32,462
ARIZONA PUBLIC SERVICE COMPANY
Change in asset retirement obligations
Beginning balance	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
Ending balance	443,576	390,750
Asset retirement obligations, current	28,573	32,462
Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Settlements	(32,000)	(30,000)
Estimated cash flow revisions	24,000
Cholla | ARIZONA PUBLIC SERVICE COMPANY
Asset Retirement Obligations
Increase in plant services	23,000
Decrease in regulatory liability	16,000
Changes attributable to:
Estimated cash flow revisions	(3,000)
Newly incurred obligation	$ 39,000
Palo Verde Nuclear Facilities and Certain other Generation Transmission and Distribution Assets | ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Estimated cash flow revisions		20,000
Four Corners Units 1 Through 3 | ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Estimated cash flow revisions		24,000
Solar Facility | ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Newly incurred obligation		$ 6,000

Selected Quarterly Financial 90

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES	$ 734,430	$ 1,199,146	$ 890,648	$ 671,219	$ 726,450	$ 1,172,667	$ 906,264	$ 686,251	$ 3,495,443	$ 3,491,632	$ 3,454,628
Operations and maintenance	222,019	220,449	210,965	214,944	260,503	223,418	211,222	212,882	868,377	908,025	924,727
Operating income	109,834	445,111	231,973	67,684	60,184	421,775	254,113	75,170	854,602	811,242	846,323
INCOME TAXES (Note 4)	22,847	139,555	67,371	7,947	5,007	134,753	74,540	6,405	237,720	220,705	230,591
Net income	45,978	261,978	127,507	20,727	9,535	248,086	141,384	24,691	456,190	423,696	439,966
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 41,117	$ 257,116	$ 122,902	$ 16,122	$ 5,410	$ 243,961	$ 132,458	$ 15,766	$ 437,257	$ 397,595	$ 406,074
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.37	$ 2.32	$ 1.11	$ 0.15	$ 0.05	$ 2.20	$ 1.20	$ 0.14	$ 3.94	$ 3.59	$ 3.69
Net income attributable to common shareholders — diluted (in dollars per share)	$ 0.37	$ 2.30	$ 1.10	$ 0.14	$ 0.05	$ 2.20	$ 1.19	$ 0.14	$ 3.92	$ 3.58	$ 3.66
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Operating revenues	$ 733,586	$ 1,198,380	$ 889,723	$ 670,668	$ 725,633	$ 1,172,190	$ 905,578	$ 685,545	$ 3,492,357	$ 3,488,946	$ 3,451,251
Operations and maintenance	219,146	216,011	208,031	209,947	253,668	212,430	208,059	208,285	853,135	882,442	897,824
Operating income	86,709	301,238	162,704	61,333	54,835	287,928	180,394	69,635	611,984	592,792	621,865
INCOME TAXES (Note 4)									245,841	237,360	245,095
Net income									469,207	447,320	458,861
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 43,857	$ 261,187	$ 125,362	$ 19,868	$ 15,738	$ 251,047	$ 134,916	$ 19,518	$ 450,274	$ 421,219	$ 424,969

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets
Nuclear decommissioning trust	$ 735,196	$ 713,866
Total assets	30,364	32,598
Fair value measurement on a recurring basis
Assets
Other	(25,345)	(21,962)
Derivative assets	28,011	31,405
Other	(335)	(7,245)
Nuclear decommissioning trust	735,196	713,866
Other	(25,680)	(29,207)
Total assets	763,207	745,271
Liabilities
Other	39,698	58,767
Derivative Liability	(167,689)	(110,278)
Fair value measurement on a recurring basis | US commingled equity funds
Assets
Other	0	0
Nuclear decommissioning trust	314,957	309,620
Fair value measurement on a recurring basis | Cash and cash equivalents
Assets
Other	(335)	(7,245)
Nuclear decommissioning trust	11,925	4,208
Fair value measurement on a recurring basis | U.S. Treasury
Assets
Nuclear decommissioning trust	117,245	118,843
Fair value measurement on a recurring basis | Corporate
Assets
Nuclear decommissioning trust	96,243	109,379
Fair value measurement on a recurring basis | Mortgage-backed securities
Assets
Nuclear decommissioning trust	99,065	88,465
Fair value measurement on a recurring basis | Municipality bonds
Assets
Nuclear decommissioning trust	72,206	69,139
Fair value measurement on a recurring basis | Other (a)
Assets
Nuclear decommissioning trust	23,555	14,212
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Decommissioning fund investments, gross fair value	129,505	118,843
Gross assets, fair value disclosure	129,505	118,843
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalents
Assets
Decommissioning fund investments, gross fair value	12,260
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	117,245	118,843
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	22,992	20,769
Decommissioning fund investments, gross fair value	606,026	602,268
Gross assets, fair value disclosure	629,018	623,037
Liabilities
Gross derivative liability	(144,044)	(95,061)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Decommissioning fund investments, gross fair value	314,957	309,620
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Cash and cash equivalents
Assets
Decommissioning fund investments, gross fair value		11,453
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	0
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate
Assets
Decommissioning fund investments, gross fair value	96,243	109,379
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	99,065	88,465
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Decommissioning fund investments, gross fair value	72,206	69,139
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other (a)
Assets
Decommissioning fund investments, gross fair value	23,555	14,212
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Gross derivative assets	30,364	32,598
Gross assets, fair value disclosure	30,364	32,598
Liabilities
Gross derivative liability	$ (63,343)	$ (73,984)

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Quantative Information (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)$ / MMBTU$ / MWh	Dec. 31, 2014USD ($)$ / MMBTU$ / MWh	Dec. 31, 2013USD ($)
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 30,364				$ 32,598				$ 30,364	$ 32,598
Liabilities	63,343				73,984				63,343	73,984
Operating revenues	734,430	$ 1,199,146	$ 890,648	$ 671,219	726,450	$ 1,172,667	$ 906,264	$ 686,251	3,495,443	3,491,632	$ 3,454,628
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	24,543				29,471				24,543	29,471
Liabilities	54,679				55,894				$ 54,679	$ 55,894
Electricity forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh									15.92	19.51
Electricity forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh									40.73	56.72
Electricity forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh									26.86	35.27
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	5,628				15,035				$ 5,628	$ 15,035
Option Contracts | Minimum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh									23.87	32.14
Implied electricity price volatilities (as a percent)									40.00%	23.00%
Implied natural gas price volatilities (as a percent)									32.00%	23.00%
Natural gas forward price (per MMbtu) | $ / MMBTU										3.18
Option Contracts | Maximum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh									44.13	66.09
Implied electricity price volatilities (as a percent)									59.00%	63.00%
Implied natural gas price volatilities (as a percent)									40.00%	41.00%
Natural gas forward price (per MMbtu) | $ / MMBTU										3.29
Option Contracts | Weighted Average | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh									33.91	45.83
Implied electricity price volatilities (as a percent)									52.00%	41.00%
Implied natural gas price volatilities (as a percent)									35.00%	31.00%
Natural gas forward price (per MMbtu) | $ / MMBTU										3.25
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	5,821				3,127				$ 5,821	$ 3,127
Liabilities	$ 3,036				$ 3,055				$ 3,036	$ 3,055
Natural gas forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu) | $ / MMBTU									2.18	2.98
Natural gas forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu) | $ / MMBTU									3.14	4.13
Natural gas forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu) | $ / MMBTU										3.45
Natural gas forward contracts | Weighted Average | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh									2.61

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Total net gains (losses) realized/unrealized:
Net derivative beginning balance	$ (41,386,000)	$ (49,165,000)
Included in earnings	0	102,000
Included in OCI	(452,000)	(239,000)
Deferred as a regulatory asset or liability	(4,009,000)	(482,000)
Settlements	14,809,000	12,080,000
Transfers into Level 3 from Level 2	(6,256,000)	(2,090,000)
Transfers from Level 3 into Level 2	4,315,000	(1,592,000)
Net derivative ending balance	(32,979,000)	(41,386,000)
Net unrealized gains included in earnings related to instruments still held at end of period	0	$ 0
Significant level 1 transfers	$ 0

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 41,117	$ 257,116	$ 122,902	$ 16,122	$ 5,410	$ 243,961	$ 132,458	$ 15,766	$ 437,257	$ 397,595	$ 406,074
Weighted Average common shares outstanding — basic (in shares)									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 (in shares)									111,552	111,178	110,806
Earnings per average common share attributable to common shareholders — basic (in dollars per share)	$ 0.37	$ 2.32	$ 1.11	$ 0.15	$ 0.05	$ 2.20	$ 1.20	$ 0.14	$ 3.94	$ 3.59	$ 3.69
Earnings per average common share attributable to common shareholders — diluted (in dollars per share)	$ 0.37	$ 2.30	$ 1.10	$ 0.14	$ 0.05	$ 2.20	$ 1.19	$ 0.14	$ 3.92	$ 3.58	$ 3.66

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2012shares	Dec. 31, 2015USD ($)elementmetricshares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Stock-Based Compensation
Common shares available for issuance (in shares) | shares		2,800,000
Compensation cost that has been charged against income		$ 19	$ 33	$ 25
Total income tax benefit recognized		7	13	10
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted		$ 14
Expected weighted-average period of recognition of unrecognized compensation cost		2 years
Total fair value of shares vested		$ 21	20	20
Restricted stock unit awards
Stock-Based Compensation
Share-based liabilities paid		10	9	10
Cash flow effect, cash used to settle awards		$ 3	3	4
Restricted Stock Units, Stock Grants and Stock Units
Vesting period		4 years
Percentage of cash that the participant may elect as a dividend for the first option available under the plan		50.00%
Percentage of Fully Transferable Shares of Stock in which Election to Receive Payment May be Made by Participants for Deferrals Option Two		50.00%
Restricted Stock Units, Stock Grants, and Stock Units
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares) | shares		152,651
Performance Shares
Stock-Based Compensation
Share-based liabilities paid		$ 16	$ 12	$ 15
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares) | shares		151,430
Performance Shares
Number of performance element criteria | element		2
Performance period		3 years
Percentage of the awards that vest based on a percentile ranking of total shareholder return		50.00%
Percentage of the awards that vest based on non-financial separate performance metrics		50.00%
Number of non-financial separate performance metrics based on which awards vest | metric		6
Performance Shares | Maximum
Performance Shares
Exact number of shares issued as a percentage of the target award		200.00%
Performance Shares | Minimum
Performance Shares
Exact number of shares issued as a percentage of the target award		0.00%
Officers and Key Employees | Restricted stock unit awards
Restricted Stock Units, Stock Grants and Stock Units
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan		100.00%
Chief Executive Officer | Retention units
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares) | shares	50,617
Additional shares to be granted as retention award if performance requirements are met | shares	33,745
Non-Officer Board of Director Member | Restricted stock unit awards
Restricted Stock Units, Stock Grants and Stock Units
Percentage of cash that the participant may elect as a dividend for the first option available under the plan		50.00%
Percentage of Fully Transferable Shares of Stock in which Election to Receive Payment May be Made by Participants for Deferrals Option Two		50.00%
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan		100.00%
Percentage of cash that the participant may elect as a dividend equivalent deferral for the first option available under the plan		50.00%
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan		50.00%
2012 Plan
Stock-Based Compensation
Common shares available for grant (in shares) | shares		4,600,000

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock Units, Stock Grants, and Stock Units
Stocks granted and the weighted average fair value
Units granted (in shares)	152,651	179,291	182,240
Grant date fair value (in dollars per share)	$ 64.12	$ 54.89	$ 55.14
Number of granted awards to be settled in cash (in shares)	45,104	49,018	52,620
Performance Shares
Stocks granted and the weighted average fair value
Units granted (in shares)	151,430	166,244	176,332
Grant date fair value (in dollars per share)	$ 64.97	$ 54.86	$ 55.45

Stock-Based Compensation - Stat

Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock Units, Stock Grants, and Stock Units
Nonvested shares
Balance at the beginning of the period (in shares)	480,933
Granted (in shares)	152,651
Change in performance factor (in shares)	0
Vested (in shares)	(198,424)
Forfeited (in shares)	(6,873)
Balance at the end of the period (in shares)	428,287	480,933
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 51.27
Granted (in dollars per share)	$ 64.12	$ 54.89	$ 55.14
Change in performance factor (in dollars per share)	0
Vested (in dollars per share)	$ 49.20
Forfeited (in dollars per share)	56.78
Balance at the end of the period (in dollars per share)	$ 56.69	$ 51.27
Vested Awards Outstanding at December 31, 2015	106,712
Vested Awards Outstanding at December 31, 2015 (in shares)
Number of nonvested awards to be settled in cash (in shares)		127,634
Number of nonvested awards to be settled in shares (in shares)		353,299
Performance Shares
Nonvested shares
Balance at the beginning of the period (in shares)	324,230
Granted (in shares)	151,430
Change in performance factor (in shares)	40,496
Vested (in shares)	(202,480)
Forfeited (in shares)	(7,844)
Balance at the end of the period (in shares)	305,832	324,230
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 54.92
Granted (in dollars per share)	$ 64.97	$ 54.86	$ 55.45
Change in performance factor (in dollars per share)	54.98
Vested (in dollars per share)	$ 54.98
Forfeited (in dollars per share)	57.89
Balance at the end of the period (in dollars per share)	$ 59.78	$ 54.92
Vested Awards Outstanding at December 31, 2015	202,480
Vested Awards Outstanding at December 31, 2015 (in shares)

Derivative Accounting (Details)

Derivative Accounting (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Counterparty	Dec. 31, 2014USD ($)
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%
Designated as Hedging Instruments
Derivative Accounting
Derivative liability	$ 3,000	$ 4,000
ARIZONA PUBLIC SERVICE COMPANY
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change	100.00%
Commodity Contracts
Derivative Accounting
Derivative liability	$ 167,689	110,271
Concentration of credit risk, number of counterparties | Counterparty	1
Concentration risk	87.00%
Derivative assets	$ 28,011	$ 31,405
Additional collateral to counterparties for energy related non-derivative instrument contracts	161,000
Commodity Contracts | Designated as Hedging Instruments
Derivative Accounting
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income	$ (4,000)

Derivative Accounting - Outstan

Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts MMcf in Thousands	12 Months Ended
	Dec. 31, 2015GWhMMcf
Outstanding gross notional amount of derivatives
Power | GWh	2,487
Gas | MMcf	182

Derivative Accounting - Gains a

Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Designated as Hedging Instruments
Derivative Instruments in Designated Cash Flows Hedges
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	$ (615,000)	$ (372,000)	$ (353,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(5,988,000)	(21,415,000)	(44,219,000)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0	0	0
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	0	0	0
Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	(108,399,000)	(66,043,000)	(10,160,000)
Revenue | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	574,000	324,000	289,000
Fuel and purchased power | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	$ (108,973,000)	$ (66,367,000)	$ (10,449,000)

Derivative Accounting - Derivat

Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Commodity Contracts
Assets
Gross Recognized Derivatives	$ 53,356	$ 53,367
Amounts Offset	(26,017)	(22,317)
Net Recognized Derivatives	27,339	31,050
Other	672	355
Amount Reported on Balance Sheet	28,011	31,405
Liabilities
Gross Recognized Derivatives	(207,387)	(169,045)
Amounts Offset	44,077	66,217
Net Recognized Derivatives	(163,310)	(102,828)
Other	(4,379)	(7,443)
Amount Reported on Balance Sheet	(167,689)	(110,271)
Assets and Liabilities
Gross Recognized Derivatives	(154,031)	(115,678)
Amounts Offset	18,060	43,900
Net Recognized Derivatives	(135,971)	(71,778)
Other	(3,707)	(7,088)
Amount Reported on Balance Sheet	(139,678)	(78,866)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	37,396	28,557
Amounts Offset	(22,163)	(15,127)
Net Recognized Derivatives	15,233	13,430
Other	672	355
Amount Reported on Balance Sheet	15,905	13,785
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	15,960	24,810
Amounts Offset	(3,854)	(7,190)
Net Recognized Derivatives	12,106	17,620
Other	0	0
Amount Reported on Balance Sheet	12,106	17,620
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(113,560)	(86,055)
Amounts Offset	40,223	33,829
Net Recognized Derivatives	(73,337)	(52,226)
Other	(4,379)	(7,443)
Amount Reported on Balance Sheet	(77,716)	(59,669)
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(93,827)	(82,990)
Amounts Offset	3,854	32,388
Net Recognized Derivatives	(89,973)	(50,602)
Other	0	0
Amount Reported on Balance Sheet	(89,973)	(50,602)
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	$ (3,000)	$ (4,000)

Derivative Accounting - Credit

Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Dec. 31, 2015USD ($)
Credit Risk and Credit-Related Contingent Features
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	$ 112,301

Other Income and Other Expen103

Other Income and Other Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other income:
Interest income	$ 493	$ 1,010	$ 1,629
Debt return on the purchase of Four Corners units 4 & 5		8,386	0
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)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	163	689	1,234
Debt return on the purchase of Four Corners units 4 & 5	0	8,386	0
Investment gains - net	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	(11,648)	(10,397)	(9,626)
Asset dispositions	(2,219)	(615)	(4,992)
Miscellaneous	(5,152)	(2,391)	(5,831)
Total other expense	$ (19,019)	$ (13,403)	$ (20,449)

Palo Verde Sale Leaseback Va104

Palo Verde Sale Leaseback Variable Interest Entities (Details) $ in Thousands	Jan. 01, 2016USD ($)	Jul. 07, 2014Lease	Dec. 31, 2015USD ($)Trust	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 1986Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts			$ 18,933	$ 26,101	$ 33,892
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts | Trust			3			3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts			$ 18,933	26,101	33,892
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts			19,000	$ 26,000	$ 34,000
Period Through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease		1
Period Through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease		2
Period 2016 through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments			23,000
Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments			$ 16,000
Maximum | Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Lease period		2 years
Scenario, Forecast | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
VIE entity initial loss exposure to noncontrolling interests during lease extension period, amount	$ 288,000
VIE entity maximum loss exposure to noncontrolling interests during lease extension period, amount	$ 465,000

Palo Verde Sale Leaseback Va105

Palo Verde Sale Leaseback Variable Interest Entities Palo Verde Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	$ 117,385	$ 121,255
Current maturities of long-term debt (Note 6)	357,580	383,570
Equity - noncontrolling interests	135,540	151,609
ARIZONA PUBLIC SERVICE COMPANY
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	117,385	121,255
Current maturities of long-term debt (Note 6)	357,580	383,570
Equity - noncontrolling interests	135,540	151,609
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	117,385	121,255
Current maturities of long-term debt (Note 6)	0	13,420
Equity - noncontrolling interests	$ 135,540	$ 151,609

Nuclear Decommissioning Trus106

Nuclear Decommissioning Trusts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Nuclear decommissioning trust fund assets
Fair Value	$ 735,196	$ 713,866
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities	478,813	356,195	$ 446,025
Fair value of fixed income securities, summarized by contractual maturities
Total	735,196	713,866
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	735,196	713,866
Unrealized Gains	169,053	176,534
Unrealized Losses	(2,760)	(1,088)
Net payables for securities purchases	(335)	(7,245)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	5,189	4,725	5,459
Realized losses	(6,225)	(4,525)	(6,706)
Proceeds from the sale of securities	478,813	356,195	$ 446,025
Fair value of fixed income securities, summarized by contractual maturities
Total	735,196	713,866
ARIZONA PUBLIC SERVICE COMPANY | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	314,957	309,620
Unrealized Gains	157,098	159,274
Unrealized Losses	(115)	(15)
Fair value of fixed income securities, summarized by contractual maturities
Total	314,957	309,620
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	420,574	411,491
Unrealized Gains	11,955	17,260
Unrealized Losses	(2,645)	(1,073)
Fair value of fixed income securities, summarized by contractual maturities
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	$ 411,491

Changes in Accumulated Other107

Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (68,141)	$ (78,053)
Total other comprehensive income	23,393	9,912	$ 35,955
Ending balance	(44,748)	(68,141)	(78,053)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	(957)	(810)
Amounts reclassified from accumulated other comprehensive loss	4,187	13,483
Total other comprehensive income	3,230	12,673
Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	16,980	(5,419)
Amounts reclassified from accumulated other comprehensive loss	3,183	2,658
Total other comprehensive income	20,163	(2,761)
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(48,333)	(53,372)
Total other comprehensive income	21,236	5,039	35,723
Ending balance	(27,097)	(48,333)	$ (53,372)
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	(957)	(809)
Amounts reclassified from accumulated other comprehensive loss	4,187	13,483
Total other comprehensive income	3,230	12,674
ARIZONA PUBLIC SERVICE COMPANY | Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	14,726	(10,415)
Amounts reclassified from accumulated other comprehensive loss	3,280	2,780
Total other comprehensive income	$ 18,006	$ (7,635)

SCHEDULE I - CONDENSED FINAN108

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Statement of Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CONDENSED FINANCIAL STATEMENTS
Operating revenues	$ 734,430	$ 1,199,146	$ 890,648	$ 671,219	$ 726,450	$ 1,172,667	$ 906,264	$ 686,251	$ 3,495,443	$ 3,491,632	$ 3,454,628
Operating expenses									2,640,841	2,680,390	2,608,305
OPERATING INCOME	109,834	445,111	231,973	67,684	60,184	421,775	254,113	75,170	854,602	811,242	846,323
Other
Total									18,013	18,652	11,261
Interest expense									194,964	200,950	201,888
Income tax benefit	22,847	139,555	67,371	7,947	5,007	134,753	74,540	6,405	237,720	220,705	230,591
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 41,117	$ 257,116	$ 122,902	$ 16,122	$ 5,410	$ 243,961	$ 132,458	$ 15,766	437,257	397,595	406,074
Other comprehensive income									23,393	9,912	35,955
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									460,650	407,507	442,029
Pinnacle West
CONDENSED FINANCIAL STATEMENTS
Operating revenues									550	642	799
Operating expenses									12,733	23,507	24,930
OPERATING INCOME									(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									23,393	9,912	35,955
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ 460,650	$ 407,507	$ 442,029

SCHEDULE I - CONDENSED FINAN109

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 39,488	$ 7,604	$ 9,526	$ 26,202
Accounts receivable	274,691	297,740
Income tax receivable	589	3,098
Other current assets	37,242	38,817
Total current assets	890,516	973,435
Investments and other assets
Other assets	52,518	54,047
Total investments and other assets	799,820	785,533
Total Assets	15,028,258	14,288,890
Current liabilities
Accounts payable	297,480	295,211
Accrued taxes (Note 4)	138,600	140,613
Common dividends payable	69,363	65,790
Other current liabilities	197,861	178,962
Total current liabilities	1,442,317	1,559,143
Long-term debt less current maturities	3,462,391	3,006,573
Deferred credits and other
Deferred income taxes	2,723,425	2,582,636
Other	186,345	188,286
Total deferred credits and other	5,404,093	5,204,072
Common stock equity
Common stock	2,541,668	2,512,970
Accumulated other comprehensive loss	(44,748)	(68,141)	(78,053)
Retained earnings	2,092,803	1,926,065
Total shareholders’ equity	4,583,917	4,367,493
Noncontrolling interests	135,540	151,609
Total equity	4,719,457	4,519,102	4,340,460	4,102,289
Total Liabilities and Equity	15,028,258	14,288,890
Pinnacle West
Current assets
Cash and cash equivalents	17,432	3,088	$ 5,798	$ 22,679
Accounts receivable	93,093	99,958
Current deferred income taxes	0	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	0
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
Current liabilities
Accounts payable	5,901	5,250
Accrued taxes (Note 4)	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	0	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 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

SCHEDULE I - CONDENSED FINAN110

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Operating Activities
Net income	$ 45,978	$ 261,978	$ 127,507	$ 20,727	$ 9,535	$ 248,086	$ 141,384	$ 24,691	$ 456,190	$ 423,696	$ 439,966
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization									571,664	496,487	492,322
Deferred income taxes									236,819	159,023	249,296
Accounts receivable									(22,219)	(52,672)	(44,991)
Accounts payable									(34,266)	(353)	45,414
Net cash flow provided by operating activities									1,094,327	1,099,627	1,153,307
Cash flows from investing activities
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
Dividends paid on common stock									(260,027)	(246,671)	(235,244)
Repayment of long-term debt									(415,570)	(652,578)	(122,828)
Common stock equity issuance - net of purchases									19,373	15,288	17,319
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	7,604	9,526	26,202
CASH AND CASH EQUIVALENTS AT END OF YEAR	39,488				7,604				39,488	7,604	9,526
Pinnacle West
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 receivable - 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)	0	0
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									0	125,000	0
Dividends paid on common stock									(260,027)	(246,671)	(235,244)
Repayment of long-term debt									0	(125,000)	0
Common stock equity issuance - net of purchases									19,373	15,288	17,319
Other									0	161	298
Net cash flow provided by (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	3,088	5,798	22,679
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 17,432				$ 3,088				$ 17,432	$ 3,088	$ 5,798

SCHEDULE II - RESERVE FOR UN111

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) - Reserve for uncollectibles. - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Changes in reserve for uncollectibles
Balance at beginning of period	$ 3,094	$ 3,203	$ 3,340
Additions, Charged to cost and expenses	4,073	3,942	4,923
Additions, Charged to other accounts	0	0	0
Deductions	4,042	4,051	5,060
Balance at end of period	3,125	3,094	3,203
Pinnacle West
Changes in reserve for uncollectibles
Balance at beginning of period	3,094	3,203	3,340
Additions, Charged to cost and expenses	4,073	3,942	4,923
Additions, Charged to other accounts	0	0	0
Deductions	4,042	4,051	5,060
Balance at end of period	$ 3,125	$ 3,094	$ 3,203