Pinnacle West Capital (PNW) 10-K 24 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 17, 2017	Jun. 30, 2016
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, 2016
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			$ 8,961,361,256
Entity Common Stock, Shares Outstanding		111,340,169
Document Fiscal Year Focus	2,016
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, 2016
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	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING REVENUES	$ 3,498,682	$ 3,495,443	$ 3,491,632
OPERATING EXPENSES
Fuel and purchased power	1,075,510	1,101,298	1,179,829
Operations and maintenance	911,319	868,377	908,025
Depreciation and amortization	485,829	494,422	417,358
Taxes other than income taxes	166,499	171,812	172,295
Other expenses	3,541	4,932	2,883
Total	2,642,698	2,640,841	2,680,390
OPERATING INCOME	855,984	854,602	811,242
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	42,140	35,215	30,790
Other income (Note 17)	901	621	9,608
Other expense (Note 17)	(15,337)	(17,823)	(21,746)
Total	27,704	18,013	18,652
INTEREST EXPENSE
Interest charges	205,720	194,964	200,950
Allowance for borrowed funds used during construction (Note 1)	(19,970)	(16,259)	(15,457)
Total	185,750	178,705	185,493
INCOME BEFORE INCOME TAXES	697,938	693,910	644,401
INCOME TAXES (Note 4)	236,411	237,720	220,705
NET INCOME	461,527	456,190	423,696
Less: Net income attributable to noncontrolling interests (Note 18)	19,493	18,933	26,101
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 442,034	$ 437,257	$ 397,595
Weighted Average common shares outstanding — basic (in shares)	111,409	111,026	110,626
Weighted Average common shares outstanding — diluted (in shares)	112,046	111,552	111,178
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 3.97	$ 3.94	$ 3.59
Net income attributable to common shareholders — diluted (in dollars per share)	$ 3.95	$ 3.92	$ 3.58
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	$ 3,489,754	$ 3,492,357	$ 3,488,946
OPERATING EXPENSES
Fuel and purchased power	1,082,625	1,101,298	1,179,829
Operations and maintenance	879,108	853,135	882,442
Depreciation and amortization	484,909	494,298	417,264
Taxes other than income taxes	165,779	171,499	171,583
Income taxes (Note 4)	259,353	260,143	245,036
Total	2,871,774	2,880,373	2,896,154
OPERATING INCOME	617,980	611,984	592,792
OTHER INCOME (DEDUCTIONS)
Income taxes (Note 4)	13,511	14,302	7,676
Allowance for equity funds used during construction (Note 1)	42,140	35,215	30,790
Other income (Note 17)	8,607	2,834	11,295
Other expense (Note 17)	(17,514)	(19,019)	(13,403)
Total	46,744	33,332	36,358
INTEREST EXPENSE
Interest on long-term debt	189,828	180,123	186,323
Interest on short-term borrowings	7,983	7,376	6,796
Debt discount, premium and expense	4,760	4,793	4,168
Allowance for borrowed funds used during construction (Note 1)	(19,481)	(16,183)	(15,457)
Total	183,090	176,109	181,830
INCOME TAXES (Note 4)	245,842	245,841	237,360
NET INCOME	481,634	469,207	447,320
Less: Net income attributable to noncontrolling interests (Note 18)	19,493	18,933	26,101
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 462,141	$ 450,274	$ 421,219

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
NET INCOME	$ 461,527	$ 456,190	$ 423,696
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	(538)	(957)	(810)
Reclassification of net realized loss, net of tax benefit	2,941	4,187	13,483
Pension and other postretirement benefits activity, net of tax (expense) benefit	(1,477)	20,163	(2,761)
Total other comprehensive income	926	23,393	9,912
COMPREHENSIVE INCOME	462,453	479,583	433,608
Less: Comprehensive income attributable to noncontrolling interests	19,493	18,933	26,101
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	442,960	460,650	407,507
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	481,634	469,207	447,320
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	(538)	(957)	(809)
Reclassification of net realized loss, net of tax benefit	2,941	4,187	13,483
Pension and other postretirement benefits activity, net of tax (expense) benefit	(729)	18,006	(7,635)
Total other comprehensive income	1,674	21,236	5,039
COMPREHENSIVE INCOME	483,308	490,443	452,359
Less: Comprehensive income attributable to noncontrolling interests	19,493	18,933	26,101
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 463,815	$ 471,510	$ 426,258

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net unrealized loss, tax (expense)	$ (585)	$ (342)	$ (438)
Reclassification of net realized loss, tax benefit	985	1,801	7,932
Pension and other postretirement benefits activity, tax benefit (expense)	633	(13,302)	1,307
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized loss, tax (expense)	(585)	(342)	(438)
Reclassification of net realized loss, tax benefit	985	1,801	7,932
Pension and other postretirement benefits activity, tax benefit (expense)	$ 293	$ (11,776)	$ 4,655

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 8,881	$ 39,488
Customer and other receivables	250,491	274,691
Accrued unbilled revenues	107,949	96,240
Allowance for doubtful accounts	(3,037)	(3,125)
Materials and supplies (at average cost)	253,979	234,234
Fossil fuel (at average cost)	28,608	45,697
Income tax receivable (Note 4)	3,751	589
Assets from risk management activities (Note 16)	19,694	15,905
Deferred fuel and purchased power regulatory asset (Note 3)	12,465	0
Other regulatory assets (Note 3)	94,410	149,555
Other current assets	45,028	37,242
Total current assets	822,219	890,516
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	1	12,106
Nuclear decommissioning trust (Notes 13 and 19)	779,586	735,196
Other assets	69,063	52,518
Total investments and other assets	848,650	799,820
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	17,341,888	16,222,232
Accumulated depreciation and amortization	(5,970,100)	(5,594,094)
Net	11,371,788	10,628,138
Construction work in progress	1,019,947	816,307
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)	113,515	117,385
Intangible assets, net of accumulated amortization of $603,637 and $546,038	90,022	123,975
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228	119,004	123,139
Total property, plant and equipment	12,714,276	11,808,944
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,313,428	1,214,146
Assets for other postretirement benefits (Note 7)	166,206	185,997
Other	139,474	128,835
Total deferred debits	1,619,108	1,528,978
Total Assets	16,004,253	15,028,258
CURRENT LIABILITIES
Accounts payable	264,631	297,480
Accrued taxes (Note 4)	138,964	138,600
Accrued interest	52,835	56,305
Common dividends payable	72,926	69,363
Short-term borrowings (Note 5)	177,200	0
Current maturities of long-term debt (Note 6)	125,000	357,580
Customer deposits	82,520	73,073
Liabilities from risk management activities (Note 16)	25,836	77,716
Liabilities for asset retirements (Note 11)	9,135	28,573
Deferred fuel and purchased power regulatory liability (Note 3)	0	9,688
Other regulatory liabilities (Note 3)	99,899	136,078
Other current liabilities	244,000	197,861
Total current liabilities	1,292,946	1,442,317
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	4,021,785	3,462,391
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,945,232	2,723,425
Regulatory liabilities (Notes 1, 3, 4 and 7)	948,916	994,152
Liabilities for asset retirements (Note 11)	615,340	415,003
Liabilities for pension benefits (Note 7)	509,310	480,998
Liabilities from risk management activities (Note 16)	47,238	89,973
Customer advances	88,672	115,609
Coal mine reclamation	221,910	201,984
Deferred investment tax credit	210,162	187,080
Unrecognized tax benefits (Note 4)	10,046	9,524
Other	156,784	186,345
Total deferred credits and other	5,753,610	5,404,093
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,392,053 and 111,095,402 issued at respective dates	2,596,030	2,541,668
Treasury stock at cost; 55,317 shares at end of 2016 and 115,030 shares at end of 2015	(4,133)	(5,806)
Total common stock	2,591,897	2,535,862
Retained earnings	2,255,547	2,092,803
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 7)	(39,070)	(37,593)
Derivative instruments (Note 16)	(4,752)	(7,155)
Total accumulated other comprehensive loss	(43,822)	(44,748)
Total shareholders’ equity	4,803,622	4,583,917
Noncontrolling interests (Note 18)	132,290	135,540
Total equity	4,935,912	4,719,457
Total Liabilities and Equity	16,004,253	15,028,258
ARIZONA PUBLIC SERVICE COMPANY
CURRENT ASSETS
Cash and cash equivalents	8,840	22,056
Customer and other receivables	262,611	274,428
Accrued unbilled revenues	107,949	96,240
Allowance for doubtful accounts	(3,037)	(3,125)
Materials and supplies (at average cost)	252,777	234,234
Fossil fuel (at average cost)	28,608	45,697
Income tax receivable (Note 4)	11,174	0
Assets from risk management activities (Note 16)	19,694	15,905
Deferred fuel and purchased power regulatory asset (Note 3)	12,465	0
Other regulatory assets (Note 3)	94,410	149,555
Other current assets	41,849	35,765
Total current assets	837,340	870,755
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	1	12,106
Nuclear decommissioning trust (Notes 13 and 19)	779,586	735,196
Other assets	48,320	34,455
Total investments and other assets	827,907	781,757
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	17,228,787	16,218,724
Accumulated depreciation and amortization	(5,881,941)	(5,590,937)
Net	11,346,846	10,627,787
Construction work in progress	989,497	812,845
Palo Verde sale leaseback, net of accumulated depreciation of $237,535 and $233,665 (Note 18)	113,515	117,385
Intangible assets, net of accumulated amortization of $603,637 and $546,038	89,868	123,820
Nuclear fuel, net of accumulated amortization of $147,202 and $146,228	119,004	123,139
Total property, plant and equipment	12,658,730	11,804,976
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,313,428	1,214,146
Assets for other postretirement benefits (Note 7)	162,911	182,625
Other	130,859	127,923
Total deferred debits	1,607,198	1,524,694
Total Assets	15,931,175	14,982,182
CURRENT LIABILITIES
Accounts payable	259,161	291,574
Accrued taxes (Note 4)	130,576	144,488
Accrued interest	52,525	56,003
Common dividends payable	72,900	69,400
Short-term borrowings (Note 5)	135,500	0
Current maturities of long-term debt (Note 6)	0	357,580
Customer deposits	82,520	73,073
Liabilities from risk management activities (Note 16)	25,836	77,716
Liabilities for asset retirements (Note 11)	8,703	28,573
Deferred fuel and purchased power regulatory liability (Note 3)	0	9,688
Other regulatory liabilities (Note 3)	99,899	136,078
Other current liabilities	226,417	180,535
Total current liabilities	1,094,037	1,424,708
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,999,295	2,764,489
Regulatory liabilities (Notes 1, 3, 4 and 7)	948,916	994,152
Liabilities for asset retirements (Note 11)	607,234	415,003
Liabilities for pension benefits (Note 7)	488,253	459,065
Liabilities from risk management activities (Note 16)	47,238	89,973
Customer advances	88,672	115,609
Coal mine reclamation	206,645	201,984
Deferred investment tax credit	210,162	187,080
Unrecognized tax benefits (Note 4)	37,408	35,251
Other	143,560	142,683
Total deferred credits and other	5,777,383	5,405,289
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Total common stock	178,162	178,162
Additional paid-in capital	2,421,696	2,379,696
Retained earnings	2,331,245	2,148,493
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 7)	(20,671)	(19,942)
Derivative instruments (Note 16)	(4,752)	(7,155)
Total accumulated other comprehensive loss	(25,423)	(27,097)
Total shareholders’ equity	4,905,680	4,679,254
Noncontrolling interests (Note 18)	132,290	135,540
Total equity	5,037,970	4,814,794
Long-term debt less current maturities (Note 6)	4,021,785	3,337,391
Total capitalization	9,059,755	8,152,185
Total Liabilities and Equity	$ 15,931,175	$ 14,982,182

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	$ 237,535	$ 233,665
Accumulated amortization on intangible assets	603,637	546,038
Accumulated amortization on nuclear fuel	$ 147,202	$ 146,228
EQUITY
Common stock, par value	$ 0	$ 0
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	111,392,053	111,095,402
Treasury stock at cost, shares	55,317	115,030
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	$ 237,535	$ 233,665
Accumulated amortization on intangible assets	603,637	546,038
Accumulated amortization on nuclear fuel	$ 147,202	$ 146,228

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 461,527	$ 456,190	$ 423,696
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	565,011	571,664	496,487
Deferred fuel and purchased power	(60,303)	14,997	(26,927)
Deferred fuel and purchased power amortization	38,152	1,617	40,757
Allowance for equity funds used during construction	(42,140)	(35,215)	(30,790)
Deferred income taxes	206,870	236,819	159,023
Deferred investment tax credit	23,082	8,473	26,246
Change in derivative instruments fair value	(403)	(381)	339
Stock compensation	18,883	18,756	33,059
Change in derivative instruments fair value
Customer and other receivables	(2,489)	(22,219)	(52,672)
Accrued unbilled revenues	(11,709)	4,293	(3,737)
Materials, supplies and fossil fuel	(1,491)	(23,945)	3,724
Income tax receivable	(3,162)	2,509	132,419
Other current assets	(23,324)	3,145	4,384
Accounts payable	(66,917)	(34,266)	(353)
Accrued taxes	447	(2,013)	9,615
Other current liabilities	29,594	603	17,892
Change in margin and collateral accounts — assets	673	(324)	(343)
Change in margin and collateral accounts — liabilities	17,735	22,776	(24,975)
Change in unrecognized tax benefits	1,628	(10,328)	2,778
Change in long-term regulatory liabilities	14,682	(20,535)	59,618
Change in other long-term assets	(60,163)	2,426	(56,561)
Change in other long-term liabilities	(82,793)	(100,715)	(114,052)
Net cash flow provided by operating activities	1,023,390	1,094,327	1,099,627
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,275,472)	(1,076,087)	(910,634)
Contributions in aid of construction	64,296	46,546	20,325
Allowance for borrowed funds used during construction	(19,970)	(16,259)	(15,457)
Proceeds from nuclear decommissioning trust sales	633,410	478,813	356,195
Investment in nuclear decommissioning trust	(635,691)	(496,062)	(373,444)
Other	(18,651)	(3,184)	347
Net cash flow used for investing activities	(1,252,078)	(1,066,233)	(922,668)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151	842,415	731,126
Repayment of long-term debt	(370,430)	(415,570)	(652,578)
Short-term borrowings and payments — net	137,200	(147,400)	(5,725)
Short-term debt borrowings under revolving credit facility	40,000	0	0
Dividends paid on common stock	(274,229)	(260,027)	(246,671)
Common stock equity issuance and purchases - net	(4,867)	19,373	15,288
Distributions to noncontrolling interests	(22,744)	(35,002)	(20,482)
Other	0	1	161
Net cash flow provided by (used for) financing activities	198,081	3,790	(178,881)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(30,607)	31,884	(1,922)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	39,488	7,604	9,526
CASH AND CASH EQUIVALENTS AT END OF YEAR	8,881	39,488	7,604
Supplemental disclosure of cash flow information:
Income taxes, net of refunds	9,956	6,550	(102,154)
Interest, net of amounts capitalized	184,462	170,209	177,074
Significant non-cash investing and financing activities:
Accrued capital expenditures	114,855	83,798	44,712
Dividends declared but not paid	72,926	69,363	65,790
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	481,634	469,207	447,320
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	564,091	571,540	496,393
Deferred fuel and purchased power	(60,303)	14,997	(26,927)
Deferred fuel and purchased power amortization	38,152	1,617	40,757
Allowance for equity funds used during construction	(42,140)	(35,215)	(30,790)
Deferred income taxes	221,167	223,069	155,401
Deferred investment tax credit	23,082	8,473	26,246
Change in derivative instruments fair value	(403)	(381)	339
Change in derivative instruments fair value
Customer and other receivables	(1,601)	(21,040)	(52,466)
Accrued unbilled revenues	(11,709)	4,293	(3,737)
Materials, supplies and fossil fuel	(1,454)	(23,945)	3,724
Income tax receivable	(14,567)	0	135,179
Other current assets	(21,640)	4,498	3,766
Accounts payable	(67,543)	(34,891)	(2,355)
Accrued taxes	(13,912)	13,378	8,650
Other current liabilities	5,097	(3,718)	33,970
Change in margin and collateral accounts — assets	673	(324)	(343)
Change in margin and collateral accounts — liabilities	17,735	22,776	(24,975)
Change in unrecognized tax benefits	1,628	(10,328)	2,778
Change in long-term regulatory liabilities	14,682	(20,535)	59,618
Change in other long-term assets	(45,866)	(813)	(62,739)
Change in other long-term liabilities	(76,855)	(82,628)	(85,642)
Net cash flow provided by operating activities	1,009,948	1,100,030	1,124,167
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,248,010)	(1,072,053)	(910,084)
Contributions in aid of construction	64,296	46,546	20,325
Allowance for borrowed funds used during construction	(19,481)	(16,183)	(15,457)
Proceeds from nuclear decommissioning trust sales	633,410	478,813	356,195
Investment in nuclear decommissioning trust	(635,691)	(496,062)	(373,444)
Other	(13,865)	(1,093)	347
Net cash flow used for investing activities	(1,219,341)	(1,060,032)	(922,118)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151	842,415	606,126
Repayment of long-term debt	(370,430)	(415,570)	(527,578)
Short-term borrowings and payments — net	135,500	(147,400)	(5,725)
Dividends paid on common stock	(281,300)	(266,900)	(253,600)
Equity infusion from Pinnacle West	42,000	0	0
Distributions to noncontrolling interests	(22,744)	(35,002)	(20,482)
Net cash flow provided by (used for) financing activities	196,177	(22,457)	(201,259)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(13,216)	17,541	790
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	22,056	4,515	3,725
CASH AND CASH EQUIVALENTS AT END OF YEAR	8,840	22,056	4,515
Supplemental disclosure of cash flow information:
Income taxes, net of refunds	26,864	14,831	(86,054)
Interest, net of amounts capitalized	181,809	167,670	173,436
Significant non-cash investing and financing activities:
Accrued capital expenditures	114,874	83,798	44,712
Dividends declared but not paid	$ 72,900	$ 69,400	$ 65,800

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, 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
Beginning 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	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
Increase (Decrease) in Shareholders' Equity
Stock compensation cumulative effect adjustments		$ 45,855	$ 40,380		5,475			5,411			5,411
Net income		461,527			442,034		19,493	481,634			462,141		19,493
Other comprehensive income		926				926		1,674				1,674
Dividends on common stock		(284,765)			(284,765)			(284,800)			(284,800)
Issuance of common stock		13,982	$ 13,982
Issuance of common stock (in shares)			296,651
Purchase of treasury stock	[1]	(9,087)		$ (9,087)
Purchase of treasury stock (in shares)	[1]			(128,105)
Reissuance of treasury stock for stock-based compensation and other		10,760		$ 10,760
Equity infusion from Pinnacle West								42,000		42,000
Reissuance of treasury stock for stock-based compensation and other (in shares)				187,818
Net capital activities by noncontrolling interests		(22,743)					(22,743)	(22,743)					(22,743)
Ending balance at Dec. 31, 2016		$ 4,935,912	$ 2,596,030	$ (4,133)	$ 2,255,547	$ (43,822)	$ 132,290	$ 5,037,970	$ 178,162	$ 2,421,696	$ 2,331,245	$ (25,423)	$ 132,290
Ending Balance (in shares) at Dec. 31, 2016		111,392,053	111,392,053	55,317					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, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Common stock dividends declared (in dollars per share)	$ 2.56	$ 2.44	$ 2.33

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and 4CA. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated. We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18). Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on net cash flows provided by operating activities. The following tables show the impacts of the reclassifications of the prior years (previously reported) amounts (dollars in thousands): Statement of Cash Flows for the As previously reported Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 18,756 $ 18,756 Change in other long term liabilities (81,959 ) (18,756 ) (100,715 ) Statement of Cash Flows for the As previously reported Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 33,059 $ 33,059 Change in other long-term liabilities (80,993 ) (33,059 ) (114,052 ) Accounting Records and Use of Estimates Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulatory Accounting APS is regulated by the ACC and FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. See Note 3 for additional information. Electric Revenues We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes. Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs. Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed. Allowance for Doubtful Accounts The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment. Property, Plant and Equipment Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes: • material and labor; • contractor costs; • capitalized leases; • construction overhead costs (where applicable); and • allowance for funds used during construction. Pinnacle West’s property, plant and equipment included in the December 31, 2016 and 2015 consolidated balance sheets is composed of the following (dollars in thousands): Property, Plant and Equipment: 2016 2015 Generation $ 7,874,898 $ 7,336,902 Transmission 2,746,508 2,494,744 Distribution 5,738,801 5,543,561 General plant 981,681 847,025 Plant in service and held for future use 17,341,888 16,222,232 Accumulated depreciation and amortization (5,970,100 ) (5,594,094 ) Net 11,371,788 10,628,138 Construction work in progress 1,019,947 816,307 Palo Verde sale leaseback, net of accumulated depreciation 113,515 117,385 Intangible assets, net of accumulated amortization 90,022 123,975 Nuclear fuel, net of accumulated amortization 119,004 123,139 Total property, plant and equipment $ 12,714,276 $ 11,808,944 Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West. We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 11. APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance. We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2016 were as follows: • Fossil plant — 19 years ; • Nuclear plant — 27 years ; • Other generation — 26 years ; • Transmission — 39 years ; • Distribution — 33 years ; and • General plant — 7 years . Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS's acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. See Note 3 for further discussion. These costs were deferred and are now being amortized on the depreciation line of the Consolidated Statements of Income. Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $422 million in 2016, $430 million in 2015, and $396 million in 2014. For the years 2014 through 2016, the depreciation rates ranged from a low of 0.30% to a high of 14.12% . The weighted-average depreciation rate was 2.66% in 2016, 2.74% in 2015, and 2.77% in 2014. Allowance for Funds Used During Construction AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation. AFUDC was calculated by using a composite rate of 7.17% for 2016, 8.02% for 2015, and 8.47% for 2014. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service. Materials and Supplies APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered. 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, 2016 2015 2014 Cash paid (received) during the period for: Income taxes, net of refunds $ 9,956 $ 6,550 $ (102,154 ) Interest, net of amounts capitalized 184,462 170,209 177,074 Significant non-cash investing and financing activities: Accrued capital expenditures $ 114,855 $ 83,798 $ 44,712 Dividends declared but not paid 72,926 69,363 65,790 Intangible Assets We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $58 million in 2016 , $58 million in 2015 , and $53 million in 2014 . Estimated amortization expense on existing intangible assets over the next five years is $41 million in 2017, $23 million in 2018, $12 million in 2019, $4 million in 2020, and $1 million in 2021. At December 31, 2016 , the weighted-average remaining amortization period for intangible assets was 6 years. Investments El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence). Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments. Business Segments Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant. Preferred Stock At December 31, 2016 , Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25 , $50 and $100 par values, none of which was outstanding.

New Accounting Standards

New Accounting Standards	12 Months Ended
	Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	New Accounting Standards ASU 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting In March 2016, new stock compensation accounting guidance was issued intended to simplify the accounting for employee share-based payments. The new guidance impacts several aspects of the accounting for share-based payments including: modifies the tax withholding threshold that triggers liability classification of an award, requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, simplifies the accounting for forfeitures, and clarifies certain cash flow presentation matters. Certain aspects of the standard must be adopted using a prospective approach and other aspects must be adopted using a modified retrospective approach. During the fourth quarter of 2016, we elected to early adopt this standard, and accordingly have applied the guidance effective as of January 1, 2016. Prior to adoption of the new standard, our stock compensation awards were generally classified as liability awards and accounted for at fair value until settled because employees could withhold at more than the minimum statutory tax withholding rate. In accordance with the new guidance, certain of these stock compensation awards are now classified as equity awards and accounted for at grant date fair value. As a result of adopting the new standard, Pinnacle West recorded a cumulative effect adjustment to retained earnings of $6 million . The other provisions of the standard did not have a material impact on our consolidated financial statements. See Note 15 for additional details of the adoption impacts. ASU 2015-07, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) In May 2015, new accounting guidance was issued that removes the requirement to categorize certain investments valued using net asset value, as a practical expedient, within the fair value hierarchy. We retrospectively adopted this guidance during the first quarter of 2016. The adoption of this guidance modifies our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results. See Note 7 and Note 13. ASU 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We plan on adopting this standard on January 1, 2018, and are currently evaluating the transition method and the effect on our financial statements. As part of our evaluation we continue to actively monitor certain industry issues being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups may impact our application of the standard, specifically in regards to the treatment of contributions in aid of construction. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements. ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are evaluating the impacts of adopting this new standard, and the impacts it may have on our financial statements.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Regulatory Matters	Regulatory Matters Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million . This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96% ) . The principal provisions of the application are: • a test year ended December 31, 2015, adjusted as described below; • an original cost rate base of $6.8 billion , which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2015; • the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 44.20 % 5.13 % Common stock equity 55.80 % 10.50 % Weighted-average cost of capital 8.13 % • a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law; • a base rate for fuel and purchased power costs of $0.029882 per kWh based on estimated 2017 prices (a decrease from the current base fuel rate of $0.03207 per kWh); • authorization to defer for potential future recovery its share of the construction costs associated with installing selective catalytic reduction equipment at Four Corners (estimated at approximately $400 million in direct costs). APS proposes that the rates established in this rate case be increased through a step mechanism beginning in 2019 to reflect these deferred costs; • authorization to defer for potential future recovery in the Company’s next general rate case the construction costs APS incurs for its Ocotillo power plant modernization project, once the project reaches commercial operation. APS estimates the direct construction costs at approximately $500 million and that the new facility will be fully in service by early 2019; • authorization to defer until the Company’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated; • updates and modifications to four of APS’s adjustor mechanisms - the PSA, the LFCR, the TCA and the Environmental Improvement Surcharge (“EIS”); • a number of proposed rate design changes for residential customers, including: ◦ change the on-peak time of use period from 12 p.m. - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays; ◦ reduce the difference in the on- and off-peak energy price and lower all energy charges; ◦ offer four rate plan options, three of which have demand charges and a fourth that is available to non-partial requirements customers using less than 600 kWh on average per month; and ◦ modify the current net metering tariff to provide for a credit at the retail rate for the portion of generation by rooftop solar customers that offsets their own load, and for a credit for excess energy delivered to the grid at an export rate. • proposed rate design changes for commercial customers, including an aggregation rider that allows certain large customers to qualify for a reduced rate, an extra-high load factor rate schedule for certain customers, and an economic development rate offering for new loads meeting certain criteria. The Company requested that the increase become effective July 1, 2017. On July 22, 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months. The ACC staff and intervenors began filing their direct testimony in late December 2016 and additional filings of testimony are ongoing. On January 12, 2017, APS began settlement discussions with all parties. On January 13, 2017, the ALJ hearing the case before the ACC issued a procedural order delaying hearings on the case from the originally scheduled March 22, 2017 to April 24, 2017, to allow parties to participate in settlement discussions and prepare testimony on the distributed generation rate design issues addressed in the value and cost of DG decision. According to the procedural order, settlement discussions are to be completed and, if applicable, any related settlement must be filed by March 17, 2017. The procedural order also extended the rate case completion date as calculated by Commission rule for an additional 33 days. APS cannot predict the outcome of this case. Prior Rate Case Filing On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million . APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6% . On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications. Settlement Agreement The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million ; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million . Other key provisions of the 2012 Settlement Agreement include the following: • An authorized return on common equity of 10.0% ; • A capital structure comprised of 46.1% debt and 53.9% common equity; • 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 settlement agreement for the 2009 retail rate case (the "2009 Settlement Agreement"); • Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date; • Modification of the TCA to streamline the process for future transmission-related rate changes; and • Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS. The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms. Renewable Energy Standard . In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five -year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC. On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million . On January 12, 2016, the ACC approved APS’s plan and requested budget. On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. The ACC has not yet ruled on the Company’s 2017 RES Implementation Plan. In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically. The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the EPA. The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. APS cannot predict the outcome of this proceeding. Demand Side Management Adjustor Charge . The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism. On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million . On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program. On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Implementation Plan is $62.6 million . On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million . The ACC has not yet ruled on the Company’s 2017 DSM Plan. Electric Energy Efficiency . On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules. On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following: • APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate; • An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC; • The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point); • The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and • The PSA rate may not be increased or decreased more than $ 0.004 per kWh in a year without permission of the ACC. The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2016 and 2015 (dollars in thousands): Year Ended December 31, 2016 2015 Beginning balance $ (9,688 ) $ 6,926 Deferred fuel and purchased power costs - current period 60,303 (14,997 ) Amounts charged to customers (38,150 ) (1,617 ) Ending balance $ 12,465 $ (9,688 ) The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh . Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters . In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers ("Retail Transmission Charges"). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2015. Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2016. APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies to make changes to their protocols in the future. As a result, APS is evaluating how its formula rate protocols compare with more recently approved formula rate protocols and anticipates that it will make a filing to update its formula rate protocols in the first quarter of 2017. Lost Fixed Cost Recovery Mechanism . The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units. APS files for a LFCR adjustment every January. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million , which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two month delay in implementation did not have an adverse effect on APS. APS filed its 2017 LFCR adjustment on January 13, 2017. APS requested an adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective the first billing cycle of March 2017. Net Metering In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the ALJ issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from historical wholesale solar power costs and eventually an avoided cost methodology. As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed. The price established by this resource comparison proxy method will be updated annually (between rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by that utility for exported distributed energy. In addition, the ACC made the following determinations: • Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS' pending rate case will be grandfathered for a period of 20 years from the date of interconnection; • Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and • Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case, which is scheduled for hearing by the ACC in April 2017. APS cannot predict the outcome of this determination. The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases. On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC's request for rehearing is required for TASC to challenge this decision in court. To date, the ACC has taken no action on the rehearing request. The ACC's decision is expected to remain in effect during any legal challenge. Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB") In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case. The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision. On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor. System Benefits Charge The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016. Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge. The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer. On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff. As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. Commissioner Burns has also scheduled a workshop in this matter for March 17, 2017. APS and Pinnacle West cannot predict the outcome of this matter. Four Corners On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis. This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $64 million as of December 31, 2016 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter will be resolved. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement” that, upon closing of the acquisition, the companies would

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2014 2016 2015 2014 Total unrecognized tax benefits, January 1 $ 34,447 $ 44,775 $ 41,997 $ 34,447 $ 44,775 $ 41,997 Additions for tax positions of the current year 2,695 2,175 4,309 2,695 2,175 4,309 Additions for tax positions of prior years 886 — 751 886 — 751 Reductions for tax positions of prior years for: Changes in judgment (1,953 ) (10,244 ) (2,282 ) (1,953 ) (10,244 ) (2,282 ) Settlements with taxing authorities — — — — — — Lapses of applicable statute of limitations — (2,259 ) — — (2,259 ) — Total unrecognized tax benefits, December 31 $ 36,075 $ 34,447 $ 44,775 $ 36,075 $ 34,447 $ 44,775 Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands): Pinnacle West Consolidated APS Consolidated 2016 2015 2014 2016 2015 2014 Tax positions, that if recognized, would decrease our effective tax rate $ 11,313 $ 9,523 $ 11,207 $ 11,313 $ 9,523 $ 11,207 As of the balance sheet date, the tax year ended December 31, 2013 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2012. We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense. The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): Pinnacle West Consolidated APS Consolidated 2016 2015 2014 2016 2015 2014 Unrecognized tax benefit interest expense/(benefit) recognized $ 529 $ (161 ) $ 752 $ 529 $ (161 ) $ 752 Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands): Pinnacle West Consolidated APS Consolidated 2016 2015 2014 2016 2015 2014 Unrecognized tax benefit interest accrued $ 1,333 $ 804 $ 965 $ 1,333 $ 804 $ 965 Additionally, as of December 31, 2016 , we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS. The components of income tax expense are as follows (dollars in thousands): Pinnacle West Consolidated APS Consolidated Year Ended December 31, Year Ended December 31, 2016 2015 2014 2016 2015 2014 Current: Federal $ 8,630 $ (12,335 ) $ 25,054 $ 711 $ 6,485 $ 40,115 State 1,259 4,763 10,382 4,276 7,813 15,598 Total current 9,889 (7,572 ) 35,436 4,987 14,298 55,713 Deferred: Federal 201,743 221,505 167,365 215,178 208,326 165,027 State 24,779 23,787 17,904 25,677 23,217 16,620 Total deferred 226,522 245,292 185,269 240,855 231,543 181,647 Income tax expense $ 236,411 $ 237,720 $ 220,705 $ 245,842 $ 245,841 $ 237,360 On the APS Consolidated Statements of Income, federal and state income taxes are allocated between operating income and other income. The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): Pinnacle West Consolidated APS Consolidated Year Ended December 31, Year Ended December 31, 2016 2015 2014 2016 2015 2014 Federal income tax expense at 35% statutory rate $ 244,278 $ 242,869 $ 225,540 $ 254,617 $ 250,267 $ 239,638 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 16,311 18,265 18,149 18,750 20,433 21,148 Credits and favorable adjustments related to prior years resolved in current year — (2,169 ) — — (1,892 ) — Medicare Subsidy Part-D 844 837 830 844 837 830 Allowance for equity funds used during construction (see Note 1) (11,724 ) (9,711 ) (8,523 ) (11,724 ) (9,711 ) (8,523 ) Palo Verde VIE noncontrolling interest (see Note 18) (6,823 ) (6,626 ) (9,135 ) (6,823 ) (6,626 ) (9,135 ) Investment tax credit amortization (5,887 ) (5,527 ) (4,928 ) (5,887 ) (5,527 ) (4,928 ) Other (588 ) (218 ) (1,228 ) (3,935 ) (1,940 ) (1,670 ) Income tax expense $ 236,411 $ 237,720 $ 220,705 $ 245,842 $ 245,841 $ 237,360 On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four -year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2016 , APS has recorded a regulatory liability of $74 million , with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law. On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five -year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2016 , APS has recorded a regulatory liability of $2 million , with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law. The components of the net deferred income tax liability were as follows (dollars in thousands): Pinnacle West Consolidated APS Consolidated December 31, December 31, 2016 2015 2016 2015 DEFERRED TAX ASSETS Risk management activities $ 26,614 $ 70,498 $ 26,614 $ 70,498 Regulatory liabilities: Asset retirement obligation and removal costs 200,140 216,765 200,140 216,765 Unamortized investment tax credits 113,195 100,779 113,195 100,779 Other postretirement benefits 60,375 83,034 60,375 83,034 Other 63,311 60,707 63,311 60,707 Pension liabilities 204,436 191,028 194,981 181,787 Renewable energy incentives 56,379 60,956 56,379 60,956 Credit and loss carryforwards 75,944 59,557 1,645 — Other 158,421 149,033 187,453 176,016 Total deferred tax assets 958,815 992,357 904,093 950,542 DEFERRED TAX LIABILITIES Plant-related (3,297,989 ) (3,116,752 ) (3,297,989 ) (3,116,752 ) Risk management activities (7,594 ) (10,626 ) (7,594 ) (10,626 ) Other postretirement assets (63,477 ) (71,737 ) (62,819 ) (70,986 ) Regulatory assets: Allowance for equity funds used during construction (61,088 ) (54,110 ) (61,088 ) (54,110 ) Deferred fuel and purchased power — mark-to-market (21,396 ) (55,020 ) (21,396 ) (55,020 ) Pension benefits (274,184 ) (240,692 ) (274,184 ) (240,692 ) Retired power plant costs (see Note 3) (49,166 ) (53,420 ) (49,166 ) (53,420 ) Other (123,987 ) (108,441 ) (123,987 ) (108,441 ) Other (5,166 ) (4,984 ) (5,165 ) (4,984 ) Total deferred tax liabilities (3,904,047 ) (3,715,782 ) (3,903,388 ) (3,715,031 ) Deferred income taxes — net $ (2,945,232 ) $ (2,723,425 ) $ (2,999,295 ) $ (2,764,489 ) As of December 31, 2016 , the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $98 million , which first begin to expire in 2031, and other federal and state loss carryforwards of $5 million , which first begin to expire in 2019. The credit and loss carryforwards amount above has been reduced by $27 million of unrecognized tax benefits.

Lines of Credit and Short-Term

Lines of Credit and Short-Term Borrowings	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (dollars in thousands): December 31, 2016 December 31, 2015 Pinnacle West APS Total Pinnacle West APS Total Commitments under Credit Facilities $ 275,000 $ 1,000,000 $ 1,275,000 $ 200,000 $ 1,000,000 $ 1,200,000 Outstanding Commercial Paper and Revolving Credit Facility Borrowings (41,700 ) (135,500 ) (177,200 ) — — — Amount of Credit Facilities Available $ 233,300 $ 864,500 $ 1,097,800 $ 200,000 $ 1,000,000 $ 1,200,000 Weighted-Average Commitment Fees 0.125% 0.100% 0.125% 0.100% Pinnacle West On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $200 million facility that matures in May 2021. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2016 , Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $1.7 million commercial paper borrowings. On August 31, 2016, PNW entered into a $75 million 364 -day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At December 31, 2016, Pinnacle West had $40 million outstanding under the facility. APS During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million . On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021. At December 31, 2016 , APS had two revolving credit facilities totaling $1 billion , including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021. APS may increase the amount of each facility up to a maximum of $700 million , for a total of $1.4 billion , upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2016 , APS had $135.5 million of commercial paper outstanding and no outstanding borrowings or letters of credit 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, 2016
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, 2016 and 2015 (dollars in thousands): Maturity Interest December 31, Dates (a) Rates 2016 2015 APS Pollution control bonds: Variable 2029 (b) $ 35,975 $ 92,405 Fixed 2024-2029 1.75%-4.70% 147,150 211,150 Total pollution control bonds 183,125 303,555 Senior unsecured notes 2019-2046 2.20%-8.75% 3,725,000 3,375,000 Term loans 2018-2019 (c) 150,000 50,000 Unamortized discount (11,816 ) (10,374 ) Unamortized premium 4,506 4,686 Unamortized debt issuance cost (29,030 ) (27,896 ) Total APS long-term debt 4,021,785 3,694,971 Less current maturities — 357,580 Total APS long-term debt less current maturities 4,021,785 3,337,391 Pinnacle West Term loan 2017 (d) 125,000 125,000 Less current maturities 125,000 — Total PNW long-term debt less current maturities — 125,000 TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES $ 4,021,785 $ 3,462,391 (a) This schedule does not reflect the timing of redemptions that may occur prior to maturities. (b) The weighted-average rate for the variable rate pollution control bonds was 0.81% at December 31, 2016 and 0.01% - 0.24% at December 31, 2015 . (c) The weighted-average interest rate was 1.427% at December 31, 2016 , and 1.024% at December 31, 2015 . (d) The interest rate was 1.520% at December 31, 2016 and 1.174% at December 31, 2015 . The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands): Year Consolidated Pinnacle West Consolidated APS 2017 $ 125,000 $ — 2018 82,000 82,000 2019 600,000 600,000 2020 250,000 250,000 2021 — — Thereafter 3,126,125 3,126,125 Total $ 4,183,125 $ 4,058,125 Debt Fair Value Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of As of Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 125,000 $ 125,000 $ 125,000 $ 125,000 APS 4,021,785 4,300,789 3,694,971 3,981,367 Total $ 4,146,785 $ 4,425,789 $ 3,819,971 $ 4,106,367 Credit Facilities and Debt Issuances APS On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. Interest rates are based on APS's senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness. On May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E. On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A. On August 1, 2016, APS repaid at maturity APS's $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016. On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016. On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. On December 6, 2016, APS redeemed at par and canceled all $17 million of the Coconino County Arizona Pollution Control Corporation Revenue Bonds (Arizona Public Service Company Project), Series 1998. See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit. Debt Provisions Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65% . At December 31, 2016 , the ratio was approximately 48% for Pinnacle West and 47% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below. Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings. All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings. An existing ACC order requires APS to maintain a common equity ratio of at least 40% . As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2016 , APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.9 billion , and total capitalization was approximately $9.1 billion . APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.6 billion , assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2016. 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, 2016
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 other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries. These plans provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement (HRA). The Company is providing a subsidy allowing post- 65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The remeasurement reduced net periodic benefit costs in 2014 by $10 million ( $5 million of which reduced expense). The remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million , which was offset by the related regulatory asset and accumulated other comprehensive income. Because of the plan changes, the Company is currently in the process of seeking IRS approval to move up to $140 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to move into a new account to pay for active union employee medical costs. As of December 31, 2016, such methodology would result in an amount of approximately $140 million being transferred to the new account. Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 13 for further discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods. A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory liability. In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over three years beginning in July 2012. We amortized approximately $5 million in 2015, $8 million in 2014, $8 million in 2013 and $4 million in 2012. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands): Pension Other Benefits 2016 2015 2014 2016 2015 2014 Service cost-benefits earned during the period $ 53,792 $ 59,627 $ 53,080 $ 14,993 $ 16,827 $ 18,139 Interest cost on benefit obligation 131,647 123,983 129,194 29,721 28,102 41,243 Expected return on plan assets (173,906 ) (179,231 ) (158,998 ) (36,495 ) (36,855 ) (46,400 ) Amortization of: Prior service cost (credit) 527 594 869 (37,883 ) (37,968 ) (9,626 ) Net actuarial loss 40,717 31,056 10,963 4,589 4,881 1,175 Net periodic benefit cost $ 52,777 $ 36,029 $ 35,108 $ (25,075 ) $ (25,013 ) $ 4,531 Portion of cost charged to expense $ 26,172 $ 20,036 $ 21,985 $ (12,435 ) $ (10,391 ) $ 6,000 The following table shows the plans’ changes in the benefit obligations and funded status for the years 2016 and 2015 (dollars in thousands): Pension Other Benefits 2016 2015 2016 2015 Change in Benefit Obligation Benefit obligation at January 1 $ 3,033,803 $ 3,078,648 $ 647,020 $ 682,335 Service cost 53,792 59,627 14,993 16,827 Interest cost 131,647 123,983 29,721 28,102 Benefit payments (142,247 ) (137,115 ) (26,231 ) (24,988 ) Actuarial (gain) loss 127,467 (91,340 ) 50,942 (55,256 ) Benefit obligation at December 31 3,204,462 3,033,803 716,445 647,020 Change in Plan Assets Fair value of plan assets at January 1 2,542,774 2,615,404 833,017 834,625 Actual return on plan assets 166,408 (44,690 ) 63,463 (2,399 ) Employer contributions 100,000 100,000 819 791 Benefit payments (133,825 ) (127,940 ) (14,648 ) — Fair value of plan assets at December 31 2,675,357 2,542,774 882,651 833,017 Funded Status at December 31 $ (529,105 ) $ (491,029 ) $ 166,206 $ 185,997 The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2016 and 2015 (dollars in thousands): 2016 2015 Projected benefit obligation $ 3,204,462 $ 3,033,803 Accumulated benefit obligation 3,049,406 2,873,467 Fair value of plan assets 2,675,357 2,542,774 The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2016 and 2015 (dollars in thousands): Pension Other Benefits 2016 2015 2016 2015 Noncurrent asset $ — $ — $ 166,206 $ 185,997 Current liability (19,795 ) (10,031 ) — — Noncurrent liability (509,310 ) (480,998 ) — — Net amount recognized $ (529,105 ) $ (491,029 ) $ 166,206 $ 185,997 The following table shows the details related to accumulated other comprehensive loss as of December 31, 2016 and 2015 (dollars in thousands): Pension Other Benefits 2016 2015 2016 2015 Net actuarial loss $ 773,750 $ 679,501 $ 146,509 $ 127,124 Prior service cost (credit) 81 609 (303,417 ) (341,301 ) APS’s portion recorded as a regulatory (asset) liability (711,059 ) (619,223 ) 156,575 213,621 Income tax expense (benefit) (24,202 ) (23,663 ) 833 925 Accumulated other comprehensive loss $ 38,570 $ 37,224 $ 500 $ 369 The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2017 (dollars in thousands): Pension Other Benefits Net actuarial loss $ 46,971 $ 5,181 Prior service cost (credit) 81 (37,842 ) Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017 $ 47,052 $ (32,661 ) The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs: Benefit Obligations As of December 31, Benefit Costs For the Years Ended December 31, 2016 2015 2016 2015 2014 January - September October - December Discount rate – pension 4.08 % 4.37 % 4.37 % 4.02 % 4.88 % 4.88 % Discount rate – other benefits 4.17 % 4.52 % 4.52 % 4.14 % 5.10 % 4.41 % Rate of compensation increase 4.00 % 4.00 % 4.00 % 4.00 % 4.00 % 4.00 % Expected long-term return on plan assets - pension N/A N/A 6.90 % 6.90 % 6.90 % 6.90 % Expected long-term return on plan assets - other benefits N/A N/A 4.45 % 4.45 % 6.80 % 4.25 % Initial healthcare cost trend rate (pre-65 participants) 7.00 % 7.00 % 7.00 % 7.00 % 7.50 % 7.50 % Initial healthcare cost trend rate (post-65 participants) 5.00 % 5.00 % 5.00 % 5.00 % 7.50 % 5.00 % Ultimate healthcare cost trend rate 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % Number of years to ultimate trend rate (pre-65 participants) 4 4 4 4 4 4 Number of years to ultimate trend rate (post-65 participants) 0 0 0 0 4 0 In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2017, we are assuming a 6.55% long-term rate of return for pension assets and 6.37% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance. In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final reports on its recommended mortality basis (“RP-2014 Mortality Tables Report” and "Mortality Improvement Scale MP-2014 Report"). At December 31, 2014, we updated our mortality assumptions using the recommended basis with modifications to better reflect our plan experience and additional data regarding mortality trends. The updated mortality assumptions resulted in a $67 million increase in Pinnacle West’s pension and other postretirement obligations, which was offset by the related regulatory asset, regulatory liability and accumulated other comprehensive income. In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in thousands): 1% Increase 1% Decrease Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants $ 8,430 $ (5,455 ) Effect on service and interest cost components of net periodic other postretirement benefit costs 8,440 (6,527 ) Effect on the accumulated other postretirement benefit obligation 108,046 (86,651 ) Plan Assets The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities. The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis. Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other government agencies, U.S Treasury Futures Contracts, and fixed income debt securities issued by corporations. Long-term fixed income assets may also include interest rate swaps, and other instruments. Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments include investments in real estate, private equity and various other strategies. The plan may also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds. Based on the IPS, and given the pension plan’s funded status at year-end 2016, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 39% to 45% . The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments. The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. As of December 31, 2016 , long-term fixed income assets represented 57% of total pension plan assets, and return-generating assets represented 43% of total pension plan assets. As of December 31, 2016, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. As of December 31, 2016 , investment in fixed income assets represented 51% of the other postretirement benefit plan total assets, and non-fixed income assets represented 49% of the other postretirement benefit plan’s assets. See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income, U.S Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. U.S Treasury Future Contracts are valued using the quoted active market prices from the exchange on which they trade, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2. Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (NAV) concept or its equivalent. Mutual funds, classified as Level 1, are valued using a NAV that is observable and based on the active market in which the fund trades. Common and collective trusts, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). The trust's shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities is derived from the quoted active market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets. As of December 31, 2016 , the plans were able to transact in the common and collective trusts at NAV. Investments in partnerships are also valued using the concept of NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, 2016, approximately $54 million of these commitments have been funded. The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016 , by asset category, are as follows (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Other (a) Balance at December 31, 2016 Pension Plan: Cash and cash equivalents $ 13,995 $ — $ — $ 13,995 Fixed income securities: Corporate — 1,210,453 — 1,210,453 U.S. Treasury 112,583 — — 112,583 Other (b) — 102,170 — 102,170 Common stock equities (c) 235,109 — — 235,109 Mutual funds (d) 251,506 — — 251,506 Common and collective trusts: Equities — — 266,840 266,840 Real estate — — 161,449 161,449 Partnerships — — 208,915 208,915 Short-term investments and other (e) — — 112,337 112,337 Total $ 613,193 $ 1,312,623 $ 749,541 $ 2,675,357 Other Benefits: Cash and cash equivalents $ 304 $ — $ — $ 304 Fixed income securities: Corporate — 268,193 — 268,193 U.S. Treasury 145,255 — — 145,255 Other (b) — 34,506 — 34,506 Common stock equities (c) 243,741 — — 243,741 Mutual funds (d) 67,418 — — 67,418 Common and collective trusts: Equities — — 95,814 95,814 Real estate — — 14,509 14,509 Partnerships — — 3,060 3,060 Short-term investments and other (e) — — 9,851 9,851 Total $ 456,718 $ 302,699 $ 123,234 $ 882,651 (a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy. (b) This category consists primarily of debt securities issued by municipalities. (c) This category primarily consists of US common stock equities. (d) These funds invest in US and international common stock equities. (e) This category includes plan receivables and payables. The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2015 , by asset category, are as follows (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Other (a) Balance at December 31, 2015 Pension Plan: Cash and cash equivalents $ 1,893 $ — $ — $ 1,893 Fixed Income Securities: Corporate — 1,108,736 — 1,108,736 U.S. Treasury 274,778 — — 274,778 Other (b) — 113,008 — 113,008 Common stock equities (c) 247,701 — — 247,701 Mutual funds - International equities 116,307 — — 116,307 Common and collective trusts: Equities — — 315,989 315,989 Real Estate — — 150,359 150,359 Partnerships — — 169,937 169,937 Short-term investments and other (d) — — 44,066 44,066 Total $ 640,679 $ 1,221,744 $ 680,351 $ 2,542,774 Other Benefits: Cash and cash equivalents $ 240 $ — $ — $ 240 Fixed Income Securities: Corporate — 217,026 — 217,026 U.S. Treasury 131,435 — — 131,435 Other (b) — 31,106 — 31,106 Common stock equities (c) 265,583 — — 265,583 Mutual funds - International equities 52,568 — — 52,568 Common and collective trusts: Equities — — 110,055 110,055 Real Estate — — 13,512 13,512 Short-term investments and other (d) — — 11,492 11,492 Total $ 449,826 $ 248,132 $ 135,059 $ 833,017 (a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy. (b) This category consists primarily of debt securities issued by municipalities. (c) This category primarily consists of US common stock equities. (d) This category includes plan receivables and payables. Contributions Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2016 , $100 million in 2015 , and $175 million in 2014 . The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2017-2019 period. With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2016 , 2015 and 2014. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans. APS funds its share of the contributions. APS’s share of the pension plan contribution was approximately $100 million in 2016 , $100 million in 2015 and $175 million in 2014 . APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2016 , 2015 and 2014. Estimated Future Benefit Payments Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands): Year Pension Other Benefits 2017 $ 172,859 $ 31,126 2018 173,232 33,795 2019 182,944 36,195 2020 191,037 37,998 2021 196,292 39,368 Years 2022-2026 1,049,149 201,944 Electric plant participants contribute to the above amounts in accordance with their respective participation agreements. Employee Savings Plan Benefits Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2016, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $10 million for 2016 , $9 million for 2015 , and $9 million for 2014 .

Leases

Leases	12 Months Ended
	Dec. 31, 2016
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. See Note 2 for a discussion of the new lease accounting standard. Total lease expense recognized in the Consolidated Statements of Income was $16 million in 2016 , $17 million in 2015 , and $18 million in 2014 . APS’s lease expense was $15 million in 2016 , $14 million in 2015 , and $15 million in 2014 . Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands): Year Pinnacle West Consolidated APS 2017 $ 12,330 $ 11,919 2018 10,987 10,690 2019 9,019 8,767 2020 7,688 7,439 2021 5,266 5,020 Thereafter 59,647 57,207 Total future lease commitments $ 104,937 $ 101,042 In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. See Note 18 for a discussion of VIEs.

Jointly-Owned Facilities

Jointly-Owned Facilities	12 Months Ended
	Dec. 31, 2016
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 Statements of Income. We are also responsible for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2016 (dollars in thousands): Percent Owned Plant in Service Accumulated Depreciation Construction Work in Progress Generating facilities: Palo Verde Units 1 and 3 29.1 % $ 1,770,324 $ 1,080,072 $ 17,615 Palo Verde Unit 2 (a) 16.8 % 581,572 360,757 9,717 Palo Verde Common 28.0 % (b) 672,799 242,649 62,479 Palo Verde Sale Leaseback (a) 351,050 237,535 — Four Corners Generating Station 63.0 % 934,837 578,924 248,072 Navajo Generating Station Units 1, 2 and 3 14.0 % 279,629 176,931 5,761 Cholla common facilities (c) 63.3 % (b) 159,707 58,276 806 (d) Transmission facilities: ANPP 500kV System 33.6 % (b) 127,970 38,610 2,291 Navajo Southern System 22.5 % (b) 62,135 20,491 334 Palo Verde — Yuma 500kV System 19.0 % (b) 13,699 5,368 408 Four Corners Switchyards 51.3 % (b) 39,850 10,474 1,044 Phoenix — Mead System 17.1 % (b) 39,330 13,725 85 Palo Verde — Rudd 500kV System 50.0 % (b) 91,904 19,818 227 Morgan — Pinnacle Peak System 65.2 % (b) 140,374 13,557 — Round Valley System 50.0 % (b) 515 127 — Palo Verde — Morgan System 85.8 % (b) 125,908 1,326 28,949 Hassayampa — North Gila System 80.0 % (b) 142,541 3,231 — Cholla 500kV Switchyard 85.7 % (b) 5,078 1,201 — Saguaro 500kV Switchyard 75.0 % (b) 20,456 12,426 2 (a) See Note 18. (b) Weighted-average of interests. (c) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned. (d) Due to the closure of Cholla Unit 2 in 2015, all new Cholla common facilities construction is owned by APS at 50.5% 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. At December 31, 2016, 4CA had plant in service of $110 million , accumulated depreciation of $79 million and construction work in progress of $30 million .

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
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 the DOE in the Court of Federal Claims. The lawsuit sought to recover damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million . Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019. APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million ). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2016, and approved on February 1, 2017, in the amount of $11.3 million (APS’s share is $3.3 million ). Payment for the claim is expected in the second quarter of 2017. Nuclear Insurance Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million (on January 1, 2017 this coverage was increased to $450 million ), which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $13.1 billion (on January 1, 2017 this balance was decreased to $13.0 billion ) of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million , subject to a maximum annual premium of $18.9 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million , with a maximum annual retrospective premium of approximately $16.6 million . The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion . APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL"). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $23.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $64 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions. Fuel and Purchased Power Commitments and Purchase Obligations APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2017 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $977 million in 2017 ; $737 million in 2018 ; $598 million in 2019 ; $525 million in 2020 ; $524 million in 2021 ; and $7.3 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions. The current coal contracts with take-or-pay provisions have terms expiring through 2031. The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands): Years Ended December 31, 2017 2018 2019 2020 2021 Thereafter Coal take-or-pay commitments (a) $ 195,428 $ 189,588 $ 193,818 $ 198,160 $ 202,619 $ 2,068,355 (a) Total take-or-pay commitments are approximately $3.0 billion . The total net present value of these commitments is approximately $2.1 billion . APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands): Year Ended December 31, 2016 2015 2014 Total purchases $ 160,066 $ 211,327 $ 236,773 Renewable Energy Credits APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $40 million in 2017 ; $40 million in 2018 ; $40 million in 2019 ; $40 million in 2020 ; $40 million in 2021 ; and $420 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Coal Mine Reclamation Obligations APS and 4CA must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $207 million at December 31, 2016 and $202 million at December 31, 2015 . 4CA recorded an obligation for the coal mine final reclamation of approximately $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $17 million in 2017; $18 million in 2018; $19 million in 2019; $21 million in 2020; $22 million in 2021; and $241 million thereafter. 4CA expects to make payments for the final mine reclamation as follows: $1 million in 2017; $1 million in 2018; $1 million in 2019; $1 million in 2020; $2 million in 2021; and $17 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements. Superfund-Related Matters Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 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 RI/FS work plan. The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by June 2017. We estimate that our costs related to this investigation and study will be approximately $2 million . We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. On August 6, 2013, RID filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Southwest Power Outage On September 8, 2011 at approximately 3:30 PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision. On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016. Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS. Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. EPA recently approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the recent Cholla rule approval. Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required controls for Four Corners Units 4 and 5 would be approximately $400 million . In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest. Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP, could be up to approximately $200 million . In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant. Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014. In September 2014, APS met with EPA to propose a compromise BART strategy. Pending certain regulatory approvals, APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program. EPA signed the final rule approving the Agency's proposal on January 13, 2017. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review. Mercury and Air Toxic Standards ("MATS"). In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $8 million for Cholla. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million , the majority of which has already been incurred. Litigation concerning the rules, including supplemental analyses EPA has prepared in support of the MATS regulation, is ongoing. These proceedings do not materially impact APS. Regardless of the results from further judicial or administrative proceedings concerning the MATS rulemaking, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla. Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future. On December 16, 2016, President Obama signed the WIIN Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds. Because EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act, and Arizona has yet to determine whether it will develop a state-specific permitting program, it is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million . APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million , the majority of which has already been incurred. Additionally, the CCR rule requires ongoing groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time. Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next 3 years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings. Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for existing, new, modified, and reconstructed EGUs. EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet 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, this timing will be impacted by the court-imposed stay described below. Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ is continuing to assess alternatives while completing outreach and soliciting feedback from stakeholders. In addition to these ongoing state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation. The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such a delay. With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances. As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation. Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material. Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes. In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains ongoing, and additional information or considerations may arise that change our expectations. Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery. Federal Agency Environmental Lawsuit Related to Four Corners On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners . New Mexico Tax Matter On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million . For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment in the amount of $0.8 million and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed an appeal of the decision on August 31, 2015. On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, an

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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 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 2016, APS recognized an ARO for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million . In addition, 4CA acquired El Paso's share of Four Corners Units 4 & 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million . In addition, Four Corners spent $16 million in actual decommissioning costs. Finally, in 2016, APS received a new decommissioning study for the Palo Verde Nuclear Generating Station. This resulted in an increase to the ARO in the amount of $151 million , an increase in plant in service of $131 million , and a reduction of the regulatory liability of $20 million . In 2015, a revision to the estimated cash flows for the decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the ARO in the amount of $24 million . Also in 2015, Four Corners spent $32 million in actual decommissioning costs. In addition, APS recognized an ARO for Cholla as a result of new CCR environmental rules that were published in the Federal Register in the second quarter of 2015. See Note 10 for additional information related to the CCR environmental rules. This resulted in an increase to the ARO in the amount of $39 million , an increase in plant in service of $23 million and a reduction of the regulatory liability of $16 million . Finally, in 2015 there was a revision in estimated cash flows for the Cholla decommissioning, which resulted in a decrease of the ARO in the amount of $3 million . The following table shows the change in our asset retirement obligations for 2016 and 2015 (dollars in thousands): 2016 2015 Asset retirement obligations at the beginning of year $ 443,576 $ 390,750 Changes attributable to: Accretion expense 26,656 25,163 Settlements (15,732 ) (32,048 ) Estimated cash flow revisions 151,046 17,556 Newly incurred or acquired obligations 18,929 42,155 Asset retirement obligations at the end of year $ 624,475 $ 443,576 Decommissioning activities for Four Corners Units 1-3 began in January 2014. Thus, $9 million of the total ARO of $624 million at December 31, 2016 , is classified as a current liability on the balance sheet. At December 31, 2015, $29 million of the total ARO of $444 million was classified as a current liability on the balance sheet. In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 3.

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Selected Quarterly Financial Information [Line Items]
Selected Quarterly Financial Data (Unaudited)	Selected Quarterly Financial Data (Unaudited) Consolidated quarterly financial information for 2016 and 2015 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year. 2016 Quarter Ended 2016 March 31, June 30, September 30, December 31, Total Operating revenues $ 677,167 $ 915,394 $ 1,166,922 $ 739,199 $ 3,498,682 Operations and maintenance 243,195 242,279 217,568 208,277 911,319 Operating income 50,162 231,748 451,258 122,816 855,984 Income taxes 1,914 65,742 141,446 27,309 236,411 Net income 9,326 126,182 267,900 58,119 461,527 Net income attributable to common shareholders 4,453 121,308 263,027 53,246 442,034 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.04 $ 1.09 $ 2.36 $ 0.48 $ 3.97 Net income attributable to common shareholders — Diluted 0.04 1.08 2.35 0.47 3.95 2015 Quarter Ended 2015 March 31, June 30, September 30, December 31, Total Operating revenues $ 671,219 $ 890,648 $ 1,199,146 $ 734,430 $ 3,495,443 Operations and maintenance 214,944 210,965 220,449 222,019 868,377 Operating income 67,684 231,973 445,111 109,834 854,602 Income taxes 7,947 67,371 139,555 22,847 237,720 Net income 20,727 127,507 261,978 45,978 456,190 Net income attributable to common shareholders 16,122 122,902 257,116 41,117 437,257 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.15 $ 1.11 $ 2.32 $ 0.37 $ 3.94 Net income attributable to common shareholders — Diluted 0.14 1.10 2.30 0.37 3.92
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 2016 and 2015 is as follows (dollars in thousands): 2016 Quarter Ended, 2016 March 31, June 30, September 30, December 31, Total Operating revenues $ 676,632 $ 909,757 $ 1,166,359 $ 737,006 $ 3,489,754 Operations and maintenance 238,711 233,712 209,366 197,319 879,108 Operating income 48,930 165,684 307,601 95,765 617,980 Net income attributable to common shareholder 7,253 127,188 269,220 58,480 462,141 2015 Quarter Ended, 2015 March 31, June 30, September 30, December 31, Total Operating revenues $ 670,668 $ 889,723 $ 1,198,380 $ 733,586 $ 3,492,357 Operations and maintenance 209,947 208,031 216,011 219,146 853,135 Operating income 61,333 162,704 301,238 86,709 611,984 Net income attributable to common shareholder 19,868 125,362 261,187 43,857 450,274

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
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. Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires certain instruments valued using NAV to no longer be classified within the fair value hierarchy. As such, certain instruments valued using NAV are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments. See Note 7 for the fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets. Coal Reclamation Trust Investments The coal reclamation trust holds cash equivalent investments in money market funds that are valued using quoted prices in active markets, and are reported within Level 1. Risk Management Activities — Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk. Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs. Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization. Investments Held in our Nuclear Decommissioning Trust The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy. Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper. Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities. 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, 2016 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2016 Assets Coal reclamation trust - cash equivalents (b) $ 14,521 $ — $ — $ — $ 14,521 Risk management activities — derivative instruments: Commodity contracts — 43,722 11,076 (35,103 ) (c) 19,695 Nuclear decommissioning trust: U.S. commingled equity funds — — — 353,261 (d) 353,261 Fixed income securities: Cash and cash equivalent funds — — — 795 (e) 795 U.S. Treasury 95,441 — — — 95,441 Corporate debt — 111,623 — — 111,623 Mortgage-backed securities — 115,337 — — 115,337 Municipal bonds — 80,997 — — 80,997 Other — 22,132 — — 22,132 Subtotal nuclear decommissioning trust 95,441 330,089 — 354,056 779,586 Total $ 109,962 $ 373,811 $ 11,076 $ 318,953 $ 813,802 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (45,641 ) $ (58,482 ) $ 31,049 (c) $ (73,074 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. (c) Represents counterparty netting, margin and collateral. See Note 16. (d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (e) Represents nuclear decommissioning trust net pending securities sales and purchases. The following table presents the fair value at December 31, 2015 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2015 Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 22,992 $ 30,364 $ (25,345 ) (b) $ 28,011 Nuclear decommissioning trust: U.S. commingled equity funds — — — 314,957 (c) 314,957 Fixed income securities: Cash and cash equivalent funds 12,260 — — (335 ) (d) 11,925 U.S. Treasury 117,245 — — — 117,245 Corporate debt — 96,243 — — 96,243 Mortgage-backed securities — 99,065 — — 99,065 Municipal bonds — 72,206 — — 72,206 Other — 23,555 — — 23,555 Subtotal nuclear decommissioning trust 129,505 291,069 — 314,622 735,196 Total $ 129,505 $ 314,061 $ 30,364 $ 289,277 $ 763,207 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (144,044 ) $ (63,343 ) $ 39,698 (b) $ (167,689 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 16. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (d) Represents nuclear decommissioning trust net pending securities sales and purchases. Fair Value Measurements Classified as Level 3 The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3). Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease. Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The remaining option contract expired on October 1, 2016. The significant unobservable inputs at December 31, 2015 for these instruments include electricity prices, and volatilities. If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease. If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase. The commodity prices and volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs. Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements. The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2016 and December 31, 2015 : December 31, 2016 Valuation Technique Significant Unobservable Input Range Weighted-Average Commodity Contracts Assets Liabilities Electricity: Forward Contracts (a) $ 10,648 $ 32,042 Discounted cash flows Electricity forward price (per MWh) $16.43 - $41.07 $ 29.86 Natural Gas: Forward Contracts (a) 428 26,440 Discounted cash flows Natural gas forward price (per MMBtu) $2.32 - $3.60 $ 2.81 Total $ 11,076 $ 58,482 (a) Includes swaps and physical and financial contracts. 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. The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2016 and 2015 (dollars in thousands): Year Ended December 31, Commodity Contracts 2016 2015 Net derivative balance at beginning of period $ (32,979 ) $ (41,386 ) Total net gains (losses) realized/unrealized: Included in earnings — — Included in OCI 88 (452 ) Deferred as a regulatory asset or liability (37,543 ) (4,009 ) Settlements 15,146 14,809 Transfers into Level 3 from Level 2 1,900 (6,256 ) Transfers from Level 3 into Level 2 5,982 4,315 Net derivative balance at end of period $ (47,406 ) $ (32,979 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ — Amounts included in earnings are recorded in either operating revenues or fuel and purchased power depending on the nature of the underlying contract. Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods. 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, 2016
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, 2016 , 2015 and 2014 (in thousands, except per share amounts): 2016 2015 2014 Net income attributable to common shareholders $ 442,034 $ 437,257 $ 397,595 Weighted average common shares outstanding — basic 111,409 111,026 110,626 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 637 526 552 Weighted average common shares outstanding — diluted 112,046 111,552 111,178 Earnings per weighted-average common share outstanding Net income attributable to common shareholders - basic $ 3.97 $ 3.94 $ 3.59 Net Income attributable to common shareholders - diluted $ 3.95 $ 3.92 $ 3.58

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2.5 million common shares were available for issuance under the 2012 Plan. During 2016, 2015, and 2014, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan. Stock-Based Compensation Expense and Activity During the fourth quarter of 2016, we adopted new stock-based compensation accounting guidance prescribed by ASU 2016-09, see Note 2. Prior to the adoption of this guidance we had certain awards that were accounted for as liability awards due to the ability of the employee to withhold taxes beyond the minimum statutory tax withholding rate. Under the new standard, the tax withholding terms of our awards no longer trigger liability treatment. Accordingly, effective, January 1, 2016 certain awards that were previously classified as liability awards are now accounted for as equity awards. The impacts of this accounting change relating to prior years have been applied using a modified retrospective approach, resulting in a $6 million cumulative-effect adjustment, net of income tax expense of $3 million , to increase Retained Earnings as of January 1, 2016. The impacts of this accounting change relating to the current year, resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. Due to this transition approach, the following discussion reflects this change in the 2016 expense and activity; however, expense and activities relating to 2015 and 2014 reflect the historical treatment. The new standard also requires excess income tax benefits and deficiencies arising from stock based compensation to now be recognized in the period incurred, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. These other provisions of the standard did not have a material impact on our consolidated financial statements. Compensation cost included in net income for stock-based compensation plans was $19 million in 2016 , $19 million in 2015 , and $33 million in 2014 . The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $10 million in 2016 , $7 million in 2015 , and $13 million in 2014 . As of December 31, 2016 , there were approximately $13 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years. The total fair value of shares vested was $22 million in 2016 , $21 million in 2015 and $22 million in 2014 . The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2016 , 2015 and 2014 . Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b) 2016 2015 2014 2016 2015 2014 Units granted 141,811 152,651 179,291 166,666 151,430 166,244 Weighted-average grant date fair value $ 67.34 $ 64.12 $ 54.89 $ 66.60 $ 64.97 $ 54.86 (a) Units granted includes awards that will be cash settled of 43,952 in 2016, 45,104 in 2015, and 49,018 in 2014. (b) Reflects the target payout level. The following table is a summary of the status of non-vested awards as of December 31, 2016 and changes during the year. Restricted Stock Units, Stock Grants, and Stock Units Performance Shares Shares Weighted-Average Grant Date Fair Value Shares (b) Weighted-Average Grant Date Fair Value Nonvested at January 1, 2016 428,287 $ 56.69 305,832 $ 58.86 Granted 141,811 67.34 166,666 66.60 Change in performance factor — — 15,573 54.09 Vested (230,881 ) 55.07 (171,303 ) 54.09 Forfeited (c) (3,958 ) 62.86 (4,044 ) 62.34 Nonvested at December 31, 2016 335,259 (a) 62.04 312,724 65.32 Vested Awards Outstanding at December 31, 2016 174,201 171,303 (a) Includes 112,554 of awards that will be cash settled. (b) The nonvested performance shares are reflected at target payout level. The performance metric component increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests. (c) We account for forfeitures as they occur. Share-based liabilities paid relating to restricted stock units were $3 million , $10 million and $9 million in 2016, 2015 and 2014, respectively. This includes cash used to settle restricted stock units of $3 million for each of the years 2016, 2015 and 2014. Restricted stock units that are cash settled are classified as liability awards. Share-based liabilities paid relating to performance shares were $16 million in 2015 and $12 million in 2014. In 2016, performance shares were classified as equity awards. Restricted Stock Units, Stock Grants, and Stock Units Restricted stock units are granted to officers and key employees. Restricted stock units typically vest and settle in equal annual installments over a 4 -year period after the grant date. Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares. In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West. This award vested on December 31, 2016, because he remained employed with the Company through that date. The Board can increase the number of awards that vest, up to an additional 33,745 restricted stock units, payable in stock, if certain performance requirements are met. Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company's closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award. Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, or 50% in cash and 50% in stock. Each stock unit is convertible to one share of stock. The stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment, plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock. Performance Share Awards Performance share awards are granted to officers and key employees. The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3 -year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based upon six non-financial separate performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West's total shareholder return (TSR) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited or if the performance criteria are not achieved the employee is not entitled to the dividends on those shares. Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

Derivative Accounting

Derivative Accounting	12 Months Ended
	Dec. 31, 2016
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. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. See Note 13 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts. For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals. As of December 31, 2016 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 1,314 GWh Gas 194 Billion cubic feet Gains and Losses from Derivative Instruments The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2016 2015 2014 Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ 47 $ (615 ) $ (372 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (3,926 ) (5,988 ) (21,415 ) (a) During the years ended December 31, 2016 , 2015 , and 2014 , we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals. During the next twelve months, we estimate that a net loss of $3 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2016 2015 2014 Net Gain Recognized in Income Operating revenues $ 771 $ 574 $ 324 Net Gain (Loss) Recognized in Income Fuel and purchased power (a) 25,711 (108,973 ) (66,367 ) Total $ 26,482 $ (108,399 ) $ (66,043 ) (a) Amounts are before the effect of PSA deferrals. Derivative Instruments in the Consolidated Balance Sheets Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets. We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below. The significant majority of our derivative instruments are not currently designated as hedging instruments. The Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015 , include gross liabilities of $2 million and $3 million , respectively, of derivative instruments designated as hedging instruments. The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2016 and 2015 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets. As of December 31, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 48,094 $ (28,400 ) $ 19,694 $ — $ 19,694 Investments and other assets 6,704 (6,703 ) 1 — 1 Total assets 54,798 (35,103 ) 19,695 — 19,695 Current liabilities (50,182 ) 28,400 (21,782 ) (4,054 ) (25,836 ) Deferred credits and other (53,941 ) 6,703 (47,238 ) — (47,238 ) Total liabilities (104,123 ) 35,103 (69,020 ) (4,054 ) (73,074 ) Total $ (49,325 ) $ — $ (49,325 ) $ (4,054 ) $ (53,379 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . 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 . Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2016, we have no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2016 (dollars in thousands): December 31, 2016 Aggregate fair value of derivative instruments in a net liability position $ 104,123 Cash collateral posted — Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) 23,914 (a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above. We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $144 million if our debt credit ratings were to fall below investment grade.

Other Income and Other Expense

Other Income and Other Expense	12 Months Ended
	Dec. 31, 2016
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 2016 , 2015 and 2014 (dollars in thousands): 2016 2015 2014 Other income: Interest income $ 884 $ 493 $ 1,010 Debt return on the purchase of Four Corners units 4 & 5 — — 8,386 Miscellaneous 17 128 212 Total other income $ 901 $ 621 $ 9,608 Other expense: Non-operating costs $ (9,235 ) $ (11,292 ) $ (9,657 ) Investment losses — net (1,747 ) (2,080 ) (9,426 ) Miscellaneous (4,355 ) (4,451 ) (2,663 ) Total other expense $ (15,337 ) $ (17,823 ) $ (21,746 )
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 2016 , 2015 and 2014 (dollars in thousands): 2016 2015 2014 Other income: Interest income $ 261 $ 163 $ 689 Debt return on the purchase of Four Corners units 4 & 5 — — 8,386 Gain on disposition of property 5,745 716 1,197 Miscellaneous 2,601 1,955 1,023 Total other income $ 8,607 $ 2,834 $ 11,295 Other expense: Non-operating costs (a) $ (11,034 ) $ (11,648 ) $ (10,397 ) Loss on disposition of property (1,246 ) (2,219 ) (615 ) Miscellaneous (5,234 ) (5,152 ) (2,391 ) Total other expense $ (17,514 ) $ (19,019 ) $ (13,403 ) (a) As defined by FERC, includes non-operating utility income and expense (items excluded from utility rate recovery).

Palo Verde Sale Leaseback Varia

Palo Verde Sale Leaseback Variable Interest Entities	12 Months Ended
	Dec. 31, 2016
Variable Interest Entities [Abstract]
Palo Verde Sale Leaseback Variable Interest Entities	Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2017 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years , or return the assets to the lessors. The leases' terms give APS the ability to utilize the assets for a significant portion of the assets' economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs' economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs. As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for 2016 , 2015 and 2014 of $19 million , $19 million and $26 million , respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation. Our Consolidated Balance Sheets at December 31, 2016 and December 31, 2015 include the following amounts relating to the VIEs (dollars in thousands): December 31, 2016 December 31, 2015 Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 113,515 $ 117,385 Equity-Noncontrolling interests 132,290 135,540 Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our consolidated financial statements. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 million over the lease extension term. For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts	12 Months Ended
	Dec. 31, 2016
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, 2016 and December 31, 2015 (dollars in thousands): Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2016 Equity securities $ 353,261 $ 188,091 $ — Fixed income securities 425,530 9,820 (4,962 ) Net receivables (a) 795 — — Total $ 779,586 $ 197,911 $ (4,962 ) Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2015 Equity securities $ 314,957 $ 157,098 $ (115 ) Fixed income securities 420,574 11,955 (2,645 ) Net payables (a) (335 ) — — Total $ 735,196 $ 169,053 $ (2,760 ) (a) Net receivables/(payables) relate to pending purchases and sales of securities. The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands): Year Ended December 31, 2016 2015 2014 Realized gains $ 11,213 $ 5,189 $ 4,725 Realized losses (10,106 ) (6,225 ) (4,525 ) Proceeds from the sale of securities (a) 633,410 478,813 356,195 (a) Proceeds are reinvested in the trust. The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2016 is as follows (dollars in thousands): Fair Value Less than one year $ 13,063 1 year – 5 years 119,292 5 years – 10 years 105,612 Greater than 10 years 187,563 Total $ 425,530

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (dollars in thousands): Year Ended December 31, 2016 2015 Balance at beginning of period $ (44,748 ) $ (68,141 ) Derivative Instruments OCI (loss) before reclassifications (538 ) (957 ) Amounts reclassified from accumulated other comprehensive loss (a) 2,941 4,187 Net current period OCI (loss) 2,403 3,230 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (4,509 ) 16,980 Amounts reclassified from accumulated other comprehensive loss (b) 3,032 3,183 Net current period OCI (loss) (1,477 ) 20,163 Balance at end of period $ (43,822 ) $ (44,748 ) (a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 16. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.
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, 2016 and 2015 (dollars in thousands): Year Ended December 31, 2016 2015 Balance at beginning of period $ (27,097 ) $ (48,333 ) Derivative Instruments OCI (loss) before reclassifications (538 ) (957 ) Amounts reclassified from accumulated other comprehensive loss (a) 2,941 4,187 Net current period OCI (loss) 2,403 3,230 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (3,821 ) 14,726 Amounts reclassified from accumulated other comprehensive loss (b) 3,092 3,280 Net current period OCI (loss) (729 ) 18,006 Balance at end of period $ (25,423 ) $ (27,097 ) (a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 16. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.

SCHEDULE I - CONDENSED FINANCIA

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Operating revenues $ 370 $ 550 $ 642 Operating expenses 26,424 12,733 23,507 Operating loss (26,054 ) (12,183 ) (22,865 ) Other Equity in earnings of subsidiaries 462,027 446,508 411,528 Other expense (1,771 ) (3,302 ) (3,276 ) Total 460,256 443,206 408,252 Interest expense 3,151 2,672 3,663 Income before income taxes 431,051 428,351 381,724 Income tax benefit (10,983 ) (8,906 ) (15,871 ) Net income attributable to common shareholders 442,034 437,257 397,595 Other comprehensive income — attributable to common shareholders 926 23,393 9,912 Total comprehensive income — attributable to common shareholders $ 442,960 $ 460,650 $ 407,507 See Combined Notes to Consolidated Financial Statements. PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (dollars in thousands) December 31, 2016 2015 ASSETS Current assets Cash and cash equivalents $ 41 $ 17,432 Accounts receivable 81,751 93,093 Income tax receivable — 14,895 Other current assets 340 197 Total current assets 82,132 125,617 Investments and other assets Investments in subsidiaries 5,084,035 4,815,236 Deferred income taxes 53,805 41,065 Other assets 38,500 43,422 Total investments and other assets 5,176,340 4,899,723 Total Assets $ 5,258,472 $ 5,025,340 LIABILITIES AND EQUITY Current liabilities Accounts payable $ 5,421 $ 5,901 Accrued taxes 12,050 6,904 Common dividends payable 72,926 69,363 Short-term borrowings 41,700 — Current maturities of long-term debt 125,000 — Other current liabilities 31,182 33,120 Total current liabilities 288,279 115,288 Long-term debt less current maturities — 125,000 Pension liabilities 21,057 21,933 Other 13,224 43,662 Total deferred credits and other 34,281 65,595 Common stock equity Common stock 2,591,897 2,535,862 Accumulated other comprehensive loss (43,822 ) (44,748 ) Retained earnings 2,255,547 2,092,803 Total Pinnacle West Shareholders’ equity 4,803,622 4,583,917 Noncontrolling interests 132,290 135,540 Total Equity 4,935,912 4,719,457 Total Liabilities and Equity $ 5,258,472 $ 5,025,340 See Combined Notes to Consolidated Financial Statements. PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (dollars in thousands) Year Ended December 31, 2016 2015 2014 Cash flows from operating activities Net income $ 442,034 $ 437,257 $ 397,595 Adjustments to reconcile net income to net cash provided by operating activities: Equity in earnings of subsidiaries — net (462,027 ) (446,508 ) (411,528 ) Depreciation and amortization 85 92 94 Deferred income taxes (12,402 ) 12,967 4,406 Accounts receivable 15,823 11,336 (22,945 ) Accounts payable 10,402 637 2,017 Accrued taxes and income tax receivables — net 20,041 (12,882 ) (1,795 ) Dividends received from subsidiaries 239,300 266,900 253,600 Other 5,514 (6,995 ) 18,432 Net cash flow provided by operating activities 258,770 262,804 239,876 Cash flows from investing activities Construction work in progress (18,457 ) (3,462 ) — Investments in subsidiaries (19,242 ) (3,491 ) (10,236 ) Repayments of loans from subsidiaries 1,026 157 322 Advances of loans to subsidiaries (2,092 ) (1,010 ) (1,450 ) Net cash flow used for investing activities (38,765 ) (7,806 ) (11,364 ) Cash flows from financing activities Issuance of long-term debt — — 125,000 Short-term debt borrowings under revolving credit facility 40,000 — — Commercial Paper - net 1,700 — — Dividends paid on common stock (274,229 ) (260,027 ) (246,671 ) Repayment of long-term debt — — (125,000 ) Common stock equity issuance - net of purchases (4,867 ) 19,373 15,288 Other — — 161 Net cash flow used for financing activities (237,396 ) (240,654 ) (231,222 ) Net increase (decrease) in cash and cash equivalents (17,391 ) 14,344 (2,710 ) Cash and cash equivalents at beginning of year 17,432 3,088 5,798 Cash and cash equivalents at end of year $ 41 $ 17,432 $ 3,088 See Combined Notes to Consolidated Financial Statements. PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements. The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of the Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

SCHEDULE II - RESERVE FOR UNCOL

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	12 Months Ended
	Dec. 31, 2016
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: 2016 $ 3,125 $ 4,025 $ — $ 4,113 $ 3,037 2015 3,094 4,073 — 4,042 3,125 2014 3,203 3,942 — 4,051 3,094
ARIZONA PUBLIC SERVICE COMPANY
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: 2016 $ 3,125 $ 4,025 $ — $ 4,113 $ 3,037 2015 3,094 4,073 — 4,042 3,125 2014 3,203 3,942 — 4,051 3,094

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and 4CA. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated. We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18). Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on net cash flows provided by operating activities. The following tables show the impacts of the reclassifications of the prior years (previously reported) amounts (dollars in thousands): Statement of Cash Flows for the As previously reported Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 18,756 $ 18,756 Change in other long term liabilities (81,959 ) (18,756 ) (100,715 ) Statement of Cash Flows for the As previously reported Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 33,059 $ 33,059 Change in other long-term liabilities (80,993 ) (33,059 ) (114,052 )
Accounting Records and Use of Estimates	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 7.17% for 2016, 8.02% for 2015, and 8.47% for 2014. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Materials and Supplies	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 ASU 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting In March 2016, new stock compensation accounting guidance was issued intended to simplify the accounting for employee share-based payments. The new guidance impacts several aspects of the accounting for share-based payments including: modifies the tax withholding threshold that triggers liability classification of an award, requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, simplifies the accounting for forfeitures, and clarifies certain cash flow presentation matters. Certain aspects of the standard must be adopted using a prospective approach and other aspects must be adopted using a modified retrospective approach. During the fourth quarter of 2016, we elected to early adopt this standard, and accordingly have applied the guidance effective as of January 1, 2016. Prior to adoption of the new standard, our stock compensation awards were generally classified as liability awards and accounted for at fair value until settled because employees could withhold at more than the minimum statutory tax withholding rate. In accordance with the new guidance, certain of these stock compensation awards are now classified as equity awards and accounted for at grant date fair value. As a result of adopting the new standard, Pinnacle West recorded a cumulative effect adjustment to retained earnings of $6 million . The other provisions of the standard did not have a material impact on our consolidated financial statements. See Note 15 for additional details of the adoption impacts. ASU 2015-07, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) In May 2015, new accounting guidance was issued that removes the requirement to categorize certain investments valued using net asset value, as a practical expedient, within the fair value hierarchy. We retrospectively adopted this guidance during the first quarter of 2016. The adoption of this guidance modifies our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results. See Note 7 and Note 13. ASU 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We plan on adopting this standard on January 1, 2018, and are currently evaluating the transition method and the effect on our financial statements. As part of our evaluation we continue to actively monitor certain industry issues being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups may impact our application of the standard, specifically in regards to the treatment of contributions in aid of construction. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements. ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are evaluating the impacts of adopting this new standard, and the impacts it may have on our financial statements.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule of reclassifications of the prior year	The following tables show the impacts of the reclassifications of the prior years (previously reported) amounts (dollars in thousands): Statement of Cash Flows for the As previously reported Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 18,756 $ 18,756 Change in other long term liabilities (81,959 ) (18,756 ) (100,715 ) Statement of Cash Flows for the As previously reported Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 33,059 $ 33,059 Change in other long-term liabilities (80,993 ) (33,059 ) (114,052 )
Schedule of property, plant and equipment	Pinnacle West’s property, plant and equipment included in the December 31, 2016 and 2015 consolidated balance sheets is composed of the following (dollars in thousands): Property, Plant and Equipment: 2016 2015 Generation $ 7,874,898 $ 7,336,902 Transmission 2,746,508 2,494,744 Distribution 5,738,801 5,543,561 General plant 981,681 847,025 Plant in service and held for future use 17,341,888 16,222,232 Accumulated depreciation and amortization (5,970,100 ) (5,594,094 ) Net 11,371,788 10,628,138 Construction work in progress 1,019,947 816,307 Palo Verde sale leaseback, net of accumulated depreciation 113,515 117,385 Intangible assets, net of accumulated amortization 90,022 123,975 Nuclear fuel, net of accumulated amortization 119,004 123,139 Total property, plant and equipment $ 12,714,276 $ 11,808,944
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, 2016 2015 2014 Cash paid (received) during the period for: Income taxes, net of refunds $ 9,956 $ 6,550 $ (102,154 ) Interest, net of amounts capitalized 184,462 170,209 177,074 Significant non-cash investing and financing activities: Accrued capital expenditures $ 114,855 $ 83,798 $ 44,712 Dividends declared but not paid 72,926 69,363 65,790

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 and 2015 (dollars in thousands): Year Ended December 31, 2016 2015 Beginning balance $ (9,688 ) $ 6,926 Deferred fuel and purchased power costs - current period 60,303 (14,997 ) Amounts charged to customers (38,150 ) (1,617 ) Ending balance $ 12,465 $ (9,688 )
Schedule of regulatory assets	The detail of regulatory assets is as follows (dollars in thousands): S Amortization Through December 31, 2016 December 31, 2015 Current Non-Current Current Non-Current Pension (a) $ — $ 711,059 $ — $ 619,223 Retired power plant costs 2033 9,913 117,591 9,913 127,518 Income taxes - AFUDC equity 2046 6,305 152,118 5,495 133,712 Deferred fuel and purchased power — mark-to-market (Note 16) 2020 — 42,963 71,852 69,697 Four Corners cost deferral 2024 6,689 56,894 6,689 63,582 Income taxes — investment tax credit basis adjustment 2046 2,120 54,356 1,766 48,462 Lost fixed cost recovery 2017 61,307 — 45,507 — Palo Verde VIEs (Note 18) 2046 — 18,775 — 18,143 Deferred compensation 2036 — 35,595 — 34,751 Deferred property taxes (d) — 73,200 — 50,453 Loss on reacquired debt 2038 1,637 16,942 1,515 16,375 AG-1 deferral 2018 — 5,868 — — Demand side management (b) 2017 3,744 — — — Tax expense of Medicare subsidy 2024 1,513 10,589 1,520 12,163 Transmission vegetation management 2016 — — 4,543 — Mead-Phoenix transmission line CIAC 2050 332 10,708 332 11,040 Deferred fuel and purchased power (b) (c) 2017 12,465 — — — Coal reclamation 2026 418 5,182 418 6,085 Other Various 432 1,588 5 2,942 Total regulatory assets (e) $ 106,875 $ 1,313,428 $ 149,555 $ 1,214,146 (a) This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. See Note 7 for further discussion. (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. (d) Per the provision of the 2012 Settlement Agreement. (e) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
Schedule of regulatory liabilities	The detail of regulatory liabilities is as follows (dollars in thousands): Amortization Through December 31, 2016 December 31, 2015 Current Non-Current Current Non-Current Asset retirement obligations 2057 $ — $ 279,976 $ — $ 277,554 Removal costs (a) 29,899 223,145 39,746 240,367 Other postretirement benefits (d) 32,662 123,913 34,100 179,521 Income taxes — deferred investment tax credit 2046 4,368 108,827 3,604 97,175 Income taxes - change in rates 2045 1,771 70,898 1,113 72,454 Spent nuclear fuel 2047 — 71,726 3,051 67,437 Renewable energy standard (b) 2017 26,809 — 43,773 4,365 Demand side management (b) 2019 — 20,472 6,079 19,115 Sundance maintenance 2030 — 15,287 — 13,678 Deferred fuel and purchased power (b) (c) 2016 — — 9,688 — Deferred gains on utility property 2018 2,063 8,895 2,062 6,001 Four Corners coal reclamation 2031 — 18,248 — 8,920 Other Various 2,327 7,529 2,550 7,565 Total regulatory liabilities $ 99,899 $ 948,916 $ 145,766 $ 994,152 (a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal (see Note 11). (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. (d) See Note 7.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2014 2016 2015 2014 Total unrecognized tax benefits, January 1 $ 34,447 $ 44,775 $ 41,997 $ 34,447 $ 44,775 $ 41,997 Additions for tax positions of the current year 2,695 2,175 4,309 2,695 2,175 4,309 Additions for tax positions of prior years 886 — 751 886 — 751 Reductions for tax positions of prior years for: Changes in judgment (1,953 ) (10,244 ) (2,282 ) (1,953 ) (10,244 ) (2,282 ) Settlements with taxing authorities — — — — — — Lapses of applicable statute of limitations — (2,259 ) — — (2,259 ) — Total unrecognized tax benefits, December 31 $ 36,075 $ 34,447 $ 44,775 $ 36,075 $ 34,447 $ 44,775
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 2016 2015 2014 2016 2015 2014 Tax positions, that if recognized, would decrease our effective tax rate $ 11,313 $ 9,523 $ 11,207 $ 11,313 $ 9,523 $ 11,207 The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): Pinnacle West Consolidated APS Consolidated 2016 2015 2014 2016 2015 2014 Unrecognized tax benefit interest expense/(benefit) recognized $ 529 $ (161 ) $ 752 $ 529 $ (161 ) $ 752 Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands): Pinnacle West Consolidated APS Consolidated 2016 2015 2014 2016 2015 2014 Unrecognized tax benefit interest accrued $ 1,333 $ 804 $ 965 $ 1,333 $ 804 $ 965
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, 2016 2015 2014 2016 2015 2014 Current: Federal $ 8,630 $ (12,335 ) $ 25,054 $ 711 $ 6,485 $ 40,115 State 1,259 4,763 10,382 4,276 7,813 15,598 Total current 9,889 (7,572 ) 35,436 4,987 14,298 55,713 Deferred: Federal 201,743 221,505 167,365 215,178 208,326 165,027 State 24,779 23,787 17,904 25,677 23,217 16,620 Total deferred 226,522 245,292 185,269 240,855 231,543 181,647 Income tax expense $ 236,411 $ 237,720 $ 220,705 $ 245,842 $ 245,841 $ 237,360
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, 2016 2015 2014 2016 2015 2014 Federal income tax expense at 35% statutory rate $ 244,278 $ 242,869 $ 225,540 $ 254,617 $ 250,267 $ 239,638 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 16,311 18,265 18,149 18,750 20,433 21,148 Credits and favorable adjustments related to prior years resolved in current year — (2,169 ) — — (1,892 ) — Medicare Subsidy Part-D 844 837 830 844 837 830 Allowance for equity funds used during construction (see Note 1) (11,724 ) (9,711 ) (8,523 ) (11,724 ) (9,711 ) (8,523 ) Palo Verde VIE noncontrolling interest (see Note 18) (6,823 ) (6,626 ) (9,135 ) (6,823 ) (6,626 ) (9,135 ) Investment tax credit amortization (5,887 ) (5,527 ) (4,928 ) (5,887 ) (5,527 ) (4,928 ) Other (588 ) (218 ) (1,228 ) (3,935 ) (1,940 ) (1,670 ) Income tax expense $ 236,411 $ 237,720 $ 220,705 $ 245,842 $ 245,841 $ 237,360
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, 2016 2015 2016 2015 DEFERRED TAX ASSETS Risk management activities $ 26,614 $ 70,498 $ 26,614 $ 70,498 Regulatory liabilities: Asset retirement obligation and removal costs 200,140 216,765 200,140 216,765 Unamortized investment tax credits 113,195 100,779 113,195 100,779 Other postretirement benefits 60,375 83,034 60,375 83,034 Other 63,311 60,707 63,311 60,707 Pension liabilities 204,436 191,028 194,981 181,787 Renewable energy incentives 56,379 60,956 56,379 60,956 Credit and loss carryforwards 75,944 59,557 1,645 — Other 158,421 149,033 187,453 176,016 Total deferred tax assets 958,815 992,357 904,093 950,542 DEFERRED TAX LIABILITIES Plant-related (3,297,989 ) (3,116,752 ) (3,297,989 ) (3,116,752 ) Risk management activities (7,594 ) (10,626 ) (7,594 ) (10,626 ) Other postretirement assets (63,477 ) (71,737 ) (62,819 ) (70,986 ) Regulatory assets: Allowance for equity funds used during construction (61,088 ) (54,110 ) (61,088 ) (54,110 ) Deferred fuel and purchased power — mark-to-market (21,396 ) (55,020 ) (21,396 ) (55,020 ) Pension benefits (274,184 ) (240,692 ) (274,184 ) (240,692 ) Retired power plant costs (see Note 3) (49,166 ) (53,420 ) (49,166 ) (53,420 ) Other (123,987 ) (108,441 ) (123,987 ) (108,441 ) Other (5,166 ) (4,984 ) (5,165 ) (4,984 ) Total deferred tax liabilities (3,904,047 ) (3,715,782 ) (3,903,388 ) (3,715,031 ) Deferred income taxes — net $ (2,945,232 ) $ (2,723,425 ) $ (2,999,295 ) $ (2,764,489 )

Lines of Credit and Short-Ter36

Lines of Credit and Short-Term Borrowings (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (dollars in thousands): December 31, 2016 December 31, 2015 Pinnacle West APS Total Pinnacle West APS Total Commitments under Credit Facilities $ 275,000 $ 1,000,000 $ 1,275,000 $ 200,000 $ 1,000,000 $ 1,200,000 Outstanding Commercial Paper and Revolving Credit Facility Borrowings (41,700 ) (135,500 ) (177,200 ) — — — Amount of Credit Facilities Available $ 233,300 $ 864,500 $ 1,097,800 $ 200,000 $ 1,000,000 $ 1,200,000 Weighted-Average Commitment Fees 0.125% 0.100% 0.125% 0.100%

Long-Term Debt and Liquidity 37

Long-Term Debt and Liquidity Matters (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (dollars in thousands): Maturity Interest December 31, Dates (a) Rates 2016 2015 APS Pollution control bonds: Variable 2029 (b) $ 35,975 $ 92,405 Fixed 2024-2029 1.75%-4.70% 147,150 211,150 Total pollution control bonds 183,125 303,555 Senior unsecured notes 2019-2046 2.20%-8.75% 3,725,000 3,375,000 Term loans 2018-2019 (c) 150,000 50,000 Unamortized discount (11,816 ) (10,374 ) Unamortized premium 4,506 4,686 Unamortized debt issuance cost (29,030 ) (27,896 ) Total APS long-term debt 4,021,785 3,694,971 Less current maturities — 357,580 Total APS long-term debt less current maturities 4,021,785 3,337,391 Pinnacle West Term loan 2017 (d) 125,000 125,000 Less current maturities 125,000 — Total PNW long-term debt less current maturities — 125,000 TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES $ 4,021,785 $ 3,462,391 (a) This schedule does not reflect the timing of redemptions that may occur prior to maturities. (b) The weighted-average rate for the variable rate pollution control bonds was 0.81% at December 31, 2016 and 0.01% - 0.24% at December 31, 2015 . (c) The weighted-average interest rate was 1.427% at December 31, 2016 , and 1.024% at December 31, 2015 . (d) The interest rate was 1.520% at December 31, 2016 and 1.174% at December 31, 2015 .
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 2017 $ 125,000 $ — 2018 82,000 82,000 2019 600,000 600,000 2020 250,000 250,000 2021 — — Thereafter 3,126,125 3,126,125 Total $ 4,183,125 $ 4,058,125
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 4,021,785 4,300,789 3,694,971 3,981,367 Total $ 4,146,785 $ 4,425,789 $ 3,819,971 $ 4,106,367

Retirement Plans and Other Be38

Retirement Plans and Other Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2014 2016 2015 2014 Service cost-benefits earned during the period $ 53,792 $ 59,627 $ 53,080 $ 14,993 $ 16,827 $ 18,139 Interest cost on benefit obligation 131,647 123,983 129,194 29,721 28,102 41,243 Expected return on plan assets (173,906 ) (179,231 ) (158,998 ) (36,495 ) (36,855 ) (46,400 ) Amortization of: Prior service cost (credit) 527 594 869 (37,883 ) (37,968 ) (9,626 ) Net actuarial loss 40,717 31,056 10,963 4,589 4,881 1,175 Net periodic benefit cost $ 52,777 $ 36,029 $ 35,108 $ (25,075 ) $ (25,013 ) $ 4,531 Portion of cost charged to expense $ 26,172 $ 20,036 $ 21,985 $ (12,435 ) $ (10,391 ) $ 6,000
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 2016 and 2015 (dollars in thousands): Pension Other Benefits 2016 2015 2016 2015 Change in Benefit Obligation Benefit obligation at January 1 $ 3,033,803 $ 3,078,648 $ 647,020 $ 682,335 Service cost 53,792 59,627 14,993 16,827 Interest cost 131,647 123,983 29,721 28,102 Benefit payments (142,247 ) (137,115 ) (26,231 ) (24,988 ) Actuarial (gain) loss 127,467 (91,340 ) 50,942 (55,256 ) Benefit obligation at December 31 3,204,462 3,033,803 716,445 647,020 Change in Plan Assets Fair value of plan assets at January 1 2,542,774 2,615,404 833,017 834,625 Actual return on plan assets 166,408 (44,690 ) 63,463 (2,399 ) Employer contributions 100,000 100,000 819 791 Benefit payments (133,825 ) (127,940 ) (14,648 ) — Fair value of plan assets at December 31 2,675,357 2,542,774 882,651 833,017 Funded Status at December 31 $ (529,105 ) $ (491,029 ) $ 166,206 $ 185,997
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, 2016 and 2015 (dollars in thousands): 2016 2015 Projected benefit obligation $ 3,204,462 $ 3,033,803 Accumulated benefit obligation 3,049,406 2,873,467 Fair value of plan assets 2,675,357 2,542,774
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, 2016 and 2015 (dollars in thousands): Pension Other Benefits 2016 2015 2016 2015 Noncurrent asset $ — $ — $ 166,206 $ 185,997 Current liability (19,795 ) (10,031 ) — — Noncurrent liability (509,310 ) (480,998 ) — — Net amount recognized $ (529,105 ) $ (491,029 ) $ 166,206 $ 185,997
Schedule of accumulated other comprehensive loss	The following table shows the details related to accumulated other comprehensive loss as of December 31, 2016 and 2015 (dollars in thousands): Pension Other Benefits 2016 2015 2016 2015 Net actuarial loss $ 773,750 $ 679,501 $ 146,509 $ 127,124 Prior service cost (credit) 81 609 (303,417 ) (341,301 ) APS’s portion recorded as a regulatory (asset) liability (711,059 ) (619,223 ) 156,575 213,621 Income tax expense (benefit) (24,202 ) (23,663 ) 833 925 Accumulated other comprehensive loss $ 38,570 $ 37,224 $ 500 $ 369
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 2017 (dollars in thousands): Pension Other Benefits Net actuarial loss $ 46,971 $ 5,181 Prior service cost (credit) 81 (37,842 ) Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017 $ 47,052 $ (32,661 )
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, 2016 2015 2016 2015 2014 January - September October - December Discount rate – pension 4.08 % 4.37 % 4.37 % 4.02 % 4.88 % 4.88 % Discount rate – other benefits 4.17 % 4.52 % 4.52 % 4.14 % 5.10 % 4.41 % Rate of compensation increase 4.00 % 4.00 % 4.00 % 4.00 % 4.00 % 4.00 % Expected long-term return on plan assets - pension N/A N/A 6.90 % 6.90 % 6.90 % 6.90 % Expected long-term return on plan assets - other benefits N/A N/A 4.45 % 4.45 % 6.80 % 4.25 % Initial healthcare cost trend rate (pre-65 participants) 7.00 % 7.00 % 7.00 % 7.00 % 7.50 % 7.50 % Initial healthcare cost trend rate (post-65 participants) 5.00 % 5.00 % 5.00 % 5.00 % 7.50 % 5.00 % Ultimate healthcare cost trend rate 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % Number of years to ultimate trend rate (pre-65 participants) 4 4 4 4 4 4 Number of years to ultimate trend rate (post-65 participants) 0 0 0 0 4 0
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 $ 8,430 $ (5,455 ) Effect on service and interest cost components of net periodic other postretirement benefit costs 8,440 (6,527 ) Effect on the accumulated other postretirement benefit obligation 108,046 (86,651 )
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, 2015 , by asset category, are as follows (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Other (a) Balance at December 31, 2015 Pension Plan: Cash and cash equivalents $ 1,893 $ — $ — $ 1,893 Fixed Income Securities: Corporate — 1,108,736 — 1,108,736 U.S. Treasury 274,778 — — 274,778 Other (b) — 113,008 — 113,008 Common stock equities (c) 247,701 — — 247,701 Mutual funds - International equities 116,307 — — 116,307 Common and collective trusts: Equities — — 315,989 315,989 Real Estate — — 150,359 150,359 Partnerships — — 169,937 169,937 Short-term investments and other (d) — — 44,066 44,066 Total $ 640,679 $ 1,221,744 $ 680,351 $ 2,542,774 Other Benefits: Cash and cash equivalents $ 240 $ — $ — $ 240 Fixed Income Securities: Corporate — 217,026 — 217,026 U.S. Treasury 131,435 — — 131,435 Other (b) — 31,106 — 31,106 Common stock equities (c) 265,583 — — 265,583 Mutual funds - International equities 52,568 — — 52,568 Common and collective trusts: Equities — — 110,055 110,055 Real Estate — — 13,512 13,512 Short-term investments and other (d) — — 11,492 11,492 Total $ 449,826 $ 248,132 $ 135,059 $ 833,017 (a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy. (b) This category consists primarily of debt securities issued by municipalities. (c) This category primarily consists of US common stock equities. (d) This category includes plan receivables and payables. The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016 , by asset category, are as follows (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Other (a) Balance at December 31, 2016 Pension Plan: Cash and cash equivalents $ 13,995 $ — $ — $ 13,995 Fixed income securities: Corporate — 1,210,453 — 1,210,453 U.S. Treasury 112,583 — — 112,583 Other (b) — 102,170 — 102,170 Common stock equities (c) 235,109 — — 235,109 Mutual funds (d) 251,506 — — 251,506 Common and collective trusts: Equities — — 266,840 266,840 Real estate — — 161,449 161,449 Partnerships — — 208,915 208,915 Short-term investments and other (e) — — 112,337 112,337 Total $ 613,193 $ 1,312,623 $ 749,541 $ 2,675,357 Other Benefits: Cash and cash equivalents $ 304 $ — $ — $ 304 Fixed income securities: Corporate — 268,193 — 268,193 U.S. Treasury 145,255 — — 145,255 Other (b) — 34,506 — 34,506 Common stock equities (c) 243,741 — — 243,741 Mutual funds (d) 67,418 — — 67,418 Common and collective trusts: Equities — — 95,814 95,814 Real estate — — 14,509 14,509 Partnerships — — 3,060 3,060 Short-term investments and other (e) — — 9,851 9,851 Total $ 456,718 $ 302,699 $ 123,234 $ 882,651 (a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy. (b) This category consists primarily of debt securities issued by municipalities. (c) This category primarily consists of US common stock equities. (d) These funds invest in US and international common stock equities. (e) This category includes plan receivables and payables.
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 2017 $ 172,859 $ 31,126 2018 173,232 33,795 2019 182,944 36,195 2020 191,037 37,998 2021 196,292 39,368 Years 2022-2026 1,049,149 201,944

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2016
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 2017 $ 12,330 $ 11,919 2018 10,987 10,690 2019 9,019 8,767 2020 7,688 7,439 2021 5,266 5,020 Thereafter 59,647 57,207 Total future lease commitments $ 104,937 $ 101,042

Jointly-Owned Facilities (Table

Jointly-Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 (dollars in thousands): Percent Owned Plant in Service Accumulated Depreciation Construction Work in Progress Generating facilities: Palo Verde Units 1 and 3 29.1 % $ 1,770,324 $ 1,080,072 $ 17,615 Palo Verde Unit 2 (a) 16.8 % 581,572 360,757 9,717 Palo Verde Common 28.0 % (b) 672,799 242,649 62,479 Palo Verde Sale Leaseback (a) 351,050 237,535 — Four Corners Generating Station 63.0 % 934,837 578,924 248,072 Navajo Generating Station Units 1, 2 and 3 14.0 % 279,629 176,931 5,761 Cholla common facilities (c) 63.3 % (b) 159,707 58,276 806 (d) Transmission facilities: ANPP 500kV System 33.6 % (b) 127,970 38,610 2,291 Navajo Southern System 22.5 % (b) 62,135 20,491 334 Palo Verde — Yuma 500kV System 19.0 % (b) 13,699 5,368 408 Four Corners Switchyards 51.3 % (b) 39,850 10,474 1,044 Phoenix — Mead System 17.1 % (b) 39,330 13,725 85 Palo Verde — Rudd 500kV System 50.0 % (b) 91,904 19,818 227 Morgan — Pinnacle Peak System 65.2 % (b) 140,374 13,557 — Round Valley System 50.0 % (b) 515 127 — Palo Verde — Morgan System 85.8 % (b) 125,908 1,326 28,949 Hassayampa — North Gila System 80.0 % (b) 142,541 3,231 — Cholla 500kV Switchyard 85.7 % (b) 5,078 1,201 — Saguaro 500kV Switchyard 75.0 % (b) 20,456 12,426 2 (a) See Note 18. (b) Weighted-average of interests. (c) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned. (d) Due to the closure of Cholla Unit 2 in 2015, all new Cholla common facilities construction is owned by APS at 50.5%

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2017 2018 2019 2020 2021 Thereafter Coal take-or-pay commitments (a) $ 195,428 $ 189,588 $ 193,818 $ 198,160 $ 202,619 $ 2,068,355 (a) Total take-or-pay commitments are approximately $3.0 billion . The total net present value of these commitments is approximately $2.1 billion .
Summary of actual take-or-pay commitments	Year Ended December 31, 2016 2015 2014 Total purchases $ 160,066 $ 211,327 $ 236,773

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Change in asset retirement obligations	The following table shows the change in our asset retirement obligations for 2016 and 2015 (dollars in thousands): 2016 2015 Asset retirement obligations at the beginning of year $ 443,576 $ 390,750 Changes attributable to: Accretion expense 26,656 25,163 Settlements (15,732 ) (32,048 ) Estimated cash flow revisions 151,046 17,556 Newly incurred or acquired obligations 18,929 42,155 Asset retirement obligations at the end of year $ 624,475 $ 443,576

Selected Quarterly Financial 43

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Selected Quarterly Financial Information [Line Items]
Schedule of quarterly financial information	Consolidated quarterly financial information for 2016 and 2015 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year. 2016 Quarter Ended 2016 March 31, June 30, September 30, December 31, Total Operating revenues $ 677,167 $ 915,394 $ 1,166,922 $ 739,199 $ 3,498,682 Operations and maintenance 243,195 242,279 217,568 208,277 911,319 Operating income 50,162 231,748 451,258 122,816 855,984 Income taxes 1,914 65,742 141,446 27,309 236,411 Net income 9,326 126,182 267,900 58,119 461,527 Net income attributable to common shareholders 4,453 121,308 263,027 53,246 442,034 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.04 $ 1.09 $ 2.36 $ 0.48 $ 3.97 Net income attributable to common shareholders — Diluted 0.04 1.08 2.35 0.47 3.95 2015 Quarter Ended 2015 March 31, June 30, September 30, December 31, Total Operating revenues $ 671,219 $ 890,648 $ 1,199,146 $ 734,430 $ 3,495,443 Operations and maintenance 214,944 210,965 220,449 222,019 868,377 Operating income 67,684 231,973 445,111 109,834 854,602 Income taxes 7,947 67,371 139,555 22,847 237,720 Net income 20,727 127,507 261,978 45,978 456,190 Net income attributable to common shareholders 16,122 122,902 257,116 41,117 437,257 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.15 $ 1.11 $ 2.32 $ 0.37 $ 3.94 Net income attributable to common shareholders — Diluted 0.14 1.10 2.30 0.37 3.92
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Schedule of quarterly financial information	APS's quarterly financial information for 2016 and 2015 is as follows (dollars in thousands): 2016 Quarter Ended, 2016 March 31, June 30, September 30, December 31, Total Operating revenues $ 676,632 $ 909,757 $ 1,166,359 $ 737,006 $ 3,489,754 Operations and maintenance 238,711 233,712 209,366 197,319 879,108 Operating income 48,930 165,684 307,601 95,765 617,980 Net income attributable to common shareholder 7,253 127,188 269,220 58,480 462,141 2015 Quarter Ended, 2015 March 31, June 30, September 30, December 31, Total Operating revenues $ 670,668 $ 889,723 $ 1,198,380 $ 733,586 $ 3,492,357 Operations and maintenance 209,947 208,031 216,011 219,146 853,135 Operating income 61,333 162,704 301,238 86,709 611,984 Net income attributable to common shareholder 19,868 125,362 261,187 43,857 450,274

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2016 Assets Coal reclamation trust - cash equivalents (b) $ 14,521 $ — $ — $ — $ 14,521 Risk management activities — derivative instruments: Commodity contracts — 43,722 11,076 (35,103 ) (c) 19,695 Nuclear decommissioning trust: U.S. commingled equity funds — — — 353,261 (d) 353,261 Fixed income securities: Cash and cash equivalent funds — — — 795 (e) 795 U.S. Treasury 95,441 — — — 95,441 Corporate debt — 111,623 — — 111,623 Mortgage-backed securities — 115,337 — — 115,337 Municipal bonds — 80,997 — — 80,997 Other — 22,132 — — 22,132 Subtotal nuclear decommissioning trust 95,441 330,089 — 354,056 779,586 Total $ 109,962 $ 373,811 $ 11,076 $ 318,953 $ 813,802 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (45,641 ) $ (58,482 ) $ 31,049 (c) $ (73,074 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. (c) Represents counterparty netting, margin and collateral. See Note 16. (d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (e) Represents nuclear decommissioning trust net pending securities sales and purchases. The following table presents the fair value at December 31, 2015 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2015 Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 22,992 $ 30,364 $ (25,345 ) (b) $ 28,011 Nuclear decommissioning trust: U.S. commingled equity funds — — — 314,957 (c) 314,957 Fixed income securities: Cash and cash equivalent funds 12,260 — — (335 ) (d) 11,925 U.S. Treasury 117,245 — — — 117,245 Corporate debt — 96,243 — — 96,243 Mortgage-backed securities — 99,065 — — 99,065 Municipal bonds — 72,206 — — 72,206 Other — 23,555 — — 23,555 Subtotal nuclear decommissioning trust 129,505 291,069 — 314,622 735,196 Total $ 129,505 $ 314,061 $ 30,364 $ 289,277 $ 763,207 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (144,044 ) $ (63,343 ) $ 39,698 (b) $ (167,689 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 16. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (d) Represents nuclear decommissioning trust net pending securities sales and purchases.
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, 2016 and December 31, 2015 : December 31, 2016 Valuation Technique Significant Unobservable Input Range Weighted-Average Commodity Contracts Assets Liabilities Electricity: Forward Contracts (a) $ 10,648 $ 32,042 Discounted cash flows Electricity forward price (per MWh) $16.43 - $41.07 $ 29.86 Natural Gas: Forward Contracts (a) 428 26,440 Discounted cash flows Natural gas forward price (per MMBtu) $2.32 - $3.60 $ 2.81 Total $ 11,076 $ 58,482 (a) Includes swaps and physical and financial contracts. 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 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, 2016 and 2015 (dollars in thousands): Year Ended December 31, Commodity Contracts 2016 2015 Net derivative balance at beginning of period $ (32,979 ) $ (41,386 ) Total net gains (losses) realized/unrealized: Included in earnings — — Included in OCI 88 (452 ) Deferred as a regulatory asset or liability (37,543 ) (4,009 ) Settlements 15,146 14,809 Transfers into Level 3 from Level 2 1,900 (6,256 ) Transfers from Level 3 into Level 2 5,982 4,315 Net derivative balance at end of period $ (47,406 ) $ (32,979 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ —

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 (in thousands, except per share amounts): 2016 2015 2014 Net income attributable to common shareholders $ 442,034 $ 437,257 $ 397,595 Weighted average common shares outstanding — basic 111,409 111,026 110,626 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 637 526 552 Weighted average common shares outstanding — diluted 112,046 111,552 111,178 Earnings per weighted-average common share outstanding Net income attributable to common shareholders - basic $ 3.97 $ 3.94 $ 3.59 Net Income attributable to common shareholders - diluted $ 3.95 $ 3.92 $ 3.58

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
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 awards granted and the weighted-average grant date fair value for the three years ended 2016 , 2015 and 2014 . Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b) 2016 2015 2014 2016 2015 2014 Units granted 141,811 152,651 179,291 166,666 151,430 166,244 Weighted-average grant date fair value $ 67.34 $ 64.12 $ 54.89 $ 66.60 $ 64.97 $ 54.86 (a) Units granted includes awards that will be cash settled of 43,952 in 2016, 45,104 in 2015, and 49,018 in 2014. (b) Reflects the target payout level. The following table is a summary of the status of non-vested awards as of December 31, 2016 and changes during the year. Restricted Stock Units, Stock Grants, and Stock Units Performance Shares Shares Weighted-Average Grant Date Fair Value Shares (b) Weighted-Average Grant Date Fair Value Nonvested at January 1, 2016 428,287 $ 56.69 305,832 $ 58.86 Granted 141,811 67.34 166,666 66.60 Change in performance factor — — 15,573 54.09 Vested (230,881 ) 55.07 (171,303 ) 54.09 Forfeited (c) (3,958 ) 62.86 (4,044 ) 62.34 Nonvested at December 31, 2016 335,259 (a) 62.04 312,724 65.32 Vested Awards Outstanding at December 31, 2016 174,201 171,303 (a) Includes 112,554 of awards that will be cash settled. (b) The nonvested performance shares are reflected at target payout level. The performance metric component increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests. (c) We account for forfeitures as they occur.
Summary of Nonvested Performance Shares	The following table is a summary of the status of non-vested awards as of December 31, 2016 and changes during the year. Restricted Stock Units, Stock Grants, and Stock Units Performance Shares Shares Weighted-Average Grant Date Fair Value Shares (b) Weighted-Average Grant Date Fair Value Nonvested at January 1, 2016 428,287 $ 56.69 305,832 $ 58.86 Granted 141,811 67.34 166,666 66.60 Change in performance factor — — 15,573 54.09 Vested (230,881 ) 55.07 (171,303 ) 54.09 Forfeited (c) (3,958 ) 62.86 (4,044 ) 62.34 Nonvested at December 31, 2016 335,259 (a) 62.04 312,724 65.32 Vested Awards Outstanding at December 31, 2016 174,201 171,303 (a) Includes 112,554 of awards that will be cash settled. (b) The nonvested performance shares are reflected at target payout level. The performance metric component increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests. (c) We account for forfeitures as they occur. The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2016 , 2015 and 2014 . Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b) 2016 2015 2014 2016 2015 2014 Units granted 141,811 152,651 179,291 166,666 151,430 166,244 Weighted-average grant date fair value $ 67.34 $ 64.12 $ 54.89 $ 66.60 $ 64.97 $ 54.86 (a) Units granted includes awards that will be cash settled of 43,952 in 2016, 45,104 in 2015, and 49,018 in 2014. (b) Reflects the target payout level.

Derivative Accounting (Tables)

Derivative Accounting (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 1,314 GWh Gas 194 Billion cubic feet
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, 2016 , 2015 and 2014 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2016 2015 2014 Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ 47 $ (615 ) $ (372 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (3,926 ) (5,988 ) (21,415 ) (a) During the years ended December 31, 2016 , 2015 , and 2014 , we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals.
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, 2016 , 2015 and 2014 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2016 2015 2014 Net Gain Recognized in Income Operating revenues $ 771 $ 574 $ 324 Net Gain (Loss) Recognized in Income Fuel and purchased power (a) 25,711 (108,973 ) (66,367 ) Total $ 26,482 $ (108,399 ) $ (66,043 ) (a) Amounts are before the effect of PSA deferrals.
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, 2016 and 2015 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets. As of December 31, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 48,094 $ (28,400 ) $ 19,694 $ — $ 19,694 Investments and other assets 6,704 (6,703 ) 1 — 1 Total assets 54,798 (35,103 ) 19,695 — 19,695 Current liabilities (50,182 ) 28,400 (21,782 ) (4,054 ) (25,836 ) Deferred credits and other (53,941 ) 6,703 (47,238 ) — (47,238 ) Total liabilities (104,123 ) 35,103 (69,020 ) (4,054 ) (73,074 ) Total $ (49,325 ) $ — $ (49,325 ) $ (4,054 ) $ (53,379 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . 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 .
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, 2016 and 2015 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets. As of December 31, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 48,094 $ (28,400 ) $ 19,694 $ — $ 19,694 Investments and other assets 6,704 (6,703 ) 1 — 1 Total assets 54,798 (35,103 ) 19,695 — 19,695 Current liabilities (50,182 ) 28,400 (21,782 ) (4,054 ) (25,836 ) Deferred credits and other (53,941 ) 6,703 (47,238 ) — (47,238 ) Total liabilities (104,123 ) 35,103 (69,020 ) (4,054 ) (73,074 ) Total $ (49,325 ) $ — $ (49,325 ) $ (4,054 ) $ (53,379 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . 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 .
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, 2016 (dollars in thousands): December 31, 2016 Aggregate fair value of derivative instruments in a net liability position $ 104,123 Cash collateral posted — Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) 23,914 (a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

Other Income and Other Expense

Other Income and Other Expense (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 , 2015 and 2014 (dollars in thousands): 2016 2015 2014 Other income: Interest income $ 884 $ 493 $ 1,010 Debt return on the purchase of Four Corners units 4 & 5 — — 8,386 Miscellaneous 17 128 212 Total other income $ 901 $ 621 $ 9,608 Other expense: Non-operating costs $ (9,235 ) $ (11,292 ) $ (9,657 ) Investment losses — net (1,747 ) (2,080 ) (9,426 ) Miscellaneous (4,355 ) (4,451 ) (2,663 ) Total other expense $ (15,337 ) $ (17,823 ) $ (21,746 )
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 2016 , 2015 and 2014 (dollars in thousands): 2016 2015 2014 Other income: Interest income $ 261 $ 163 $ 689 Debt return on the purchase of Four Corners units 4 & 5 — — 8,386 Gain on disposition of property 5,745 716 1,197 Miscellaneous 2,601 1,955 1,023 Total other income $ 8,607 $ 2,834 $ 11,295 Other expense: Non-operating costs (a) $ (11,034 ) $ (11,648 ) $ (10,397 ) Loss on disposition of property (1,246 ) (2,219 ) (615 ) Miscellaneous (5,234 ) (5,152 ) (2,391 ) Total other expense $ (17,514 ) $ (19,019 ) $ (13,403 ) (a) As defined by FERC, includes non-operating utility income and expense (items excluded from utility rate recovery).

Palo Verde Sale Leaseback Var49

Palo Verde Sale Leaseback Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2016
Variable Interest Entities [Abstract]
Amounts relating to the VIEs included in Consolidated Balance Sheets	Our Consolidated Balance Sheets at December 31, 2016 and December 31, 2015 include the following amounts relating to the VIEs (dollars in thousands): December 31, 2016 December 31, 2015 Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 113,515 $ 117,385 Equity-Noncontrolling interests 132,290 135,540

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and December 31, 2015 (dollars in thousands): Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2016 Equity securities $ 353,261 $ 188,091 $ — Fixed income securities 425,530 9,820 (4,962 ) Net receivables (a) 795 — — Total $ 779,586 $ 197,911 $ (4,962 ) Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2015 Equity securities $ 314,957 $ 157,098 $ (115 ) Fixed income securities 420,574 11,955 (2,645 ) Net payables (a) (335 ) — — Total $ 735,196 $ 169,053 $ (2,760 ) (a) Net receivables/(payables) relate to pending purchases and sales of securities.
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, 2016 2015 2014 Realized gains $ 11,213 $ 5,189 $ 4,725 Realized losses (10,106 ) (6,225 ) (4,525 ) Proceeds from the sale of securities (a) 633,410 478,813 356,195 (a) Proceeds are reinvested in the trust.
Fair value of fixed income securities, summarized by contractual maturities	The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2016 is as follows (dollars in thousands): Fair Value Less than one year $ 13,063 1 year – 5 years 119,292 5 years – 10 years 105,612 Greater than 10 years 187,563 Total $ 425,530

Changes in Accumulated Other 51

Changes in Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (dollars in thousands): Year Ended December 31, 2016 2015 Balance at beginning of period $ (44,748 ) $ (68,141 ) Derivative Instruments OCI (loss) before reclassifications (538 ) (957 ) Amounts reclassified from accumulated other comprehensive loss (a) 2,941 4,187 Net current period OCI (loss) 2,403 3,230 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (4,509 ) 16,980 Amounts reclassified from accumulated other comprehensive loss (b) 3,032 3,183 Net current period OCI (loss) (1,477 ) 20,163 Balance at end of period $ (43,822 ) $ (44,748 ) (a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 16. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.
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, 2016 and 2015 (dollars in thousands): Year Ended December 31, 2016 2015 Balance at beginning of period $ (27,097 ) $ (48,333 ) Derivative Instruments OCI (loss) before reclassifications (538 ) (957 ) Amounts reclassified from accumulated other comprehensive loss (a) 2,941 4,187 Net current period OCI (loss) 2,403 3,230 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (3,821 ) 14,726 Amounts reclassified from accumulated other comprehensive loss (b) 3,092 3,280 Net current period OCI (loss) (729 ) 18,006 Balance at end of period $ (25,423 ) $ (27,097 ) (a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 16. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.

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, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2016USD ($)$ / sharesshares	Jul. 06, 2016
Approximate remaining average useful lives of utility property
Cost of services, depreciation		$ 422	$ 430	$ 396
Depreciation rates (as a percent)		2.66%	2.74%	2.77%
Allowance for Funds Used During Construction
Composite rate used to calculate AFUDC (as a percent)		7.17%	8.02%	8.47%
Income Taxes
Percent likelihood largest tax benefit amount is realized (greater than)		50.00%
Intangible Assets
Amortization expense		$ 58	$ 58	$ 53
Estimated amortization expense on existing intangible assets over the next five years
2,017		41			$ 41
2,018		23			23
2,019		12			12
2,020		4			4
2,021		$ 1			$ 1
Remaining amortization period for intangible assets		6 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)					14.12%
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		27 years
Other generation
Approximate remaining average useful lives of utility property
Average useful life		26 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
General plant
Approximate remaining average useful lives of utility property
Average useful life		7 years
El Paso's Interest in Four Corners | 4CA
Utility Plant and Depreciation [Line Items]
Ownership interest acquired		7.00%			7.00%	7.00%

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Schedule of Reclassification of Prior Period Adjustments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Stock compensation	$ 18,883	$ 18,756	$ 33,059
Change in other long-term liabilities	$ (82,793)	(100,715)	(114,052)
As previously reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Stock compensation		0	0
Change in other long-term liabilities		(81,959)	(80,993)
Reclassifications to conform to current year presentation
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Stock compensation		18,756	33,059
Change in other long-term liabilities		$ (18,756)	$ (33,059)

Summary of Significant Accoun54

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Utility Plant and Depreciation [Line Items]
Net	$ 11,371,788	$ 10,628,138
Construction work in progress	1,019,947	816,307
Palo Verde sale leaseback, net of accumulated depreciation	113,515	117,385
Intangible assets, net of accumulated amortization	90,022	123,975
Nuclear fuel, net of accumulated amortization	119,004	123,139
Total property, plant and equipment	12,714,276	11,808,944
Electric Service
Utility Plant and Depreciation [Line Items]
Generation	7,874,898	7,336,902
Transmission	2,746,508	2,494,744
Distribution	5,738,801	5,543,561
General plant	981,681	847,025
Plant in service and held for future use	17,341,888	16,222,232
Accumulated depreciation and amortization	(5,970,100)	(5,594,094)
Net	11,371,788	10,628,138
Construction work in progress	1,019,947	816,307
Palo Verde sale leaseback, net of accumulated depreciation	113,515	117,385
Intangible assets, net of accumulated amortization	90,022	123,975
Nuclear fuel, net of accumulated amortization	119,004	123,139
Total property, plant and equipment	$ 12,714,276	$ 11,808,944

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Income tax (benefit), net of refunds	$ 9,956	$ 6,550	$ (102,154)
Interest, net of amounts capitalized	184,462	170,209	177,074
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Accrued capital expenditures	114,855	83,798	44,712
Dividends declared but not paid	$ 72,926	$ 69,363	$ 65,790

New Accounting Standards - Narr

New Accounting Standards - Narrative (Details) $ in Thousands	Dec. 31, 2015USD ($)
New Accounting Pronouncement, Early Adoption [Line Items]
Stock compensation cumulative effect adjustments	$ 45,855
Retained Earnings
New Accounting Pronouncement, Early Adoption [Line Items]
Stock compensation cumulative effect adjustments	5,475
Retained Earnings | Accountings Standards Update 2016-09 | New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncement, Early Adoption [Line Items]
Stock compensation cumulative effect adjustments	$ 6,000

Regulatory Matters (Details)

Regulatory Matters (Details) - APS

Feb. 01, 2017$ / kWh

Jan. 13, 2017USD ($)

Dec. 20, 2016

Jul. 12, 2016USD ($)

Jun. 01, 2016USD ($)kWh$ / kWh

Feb. 01, 2016$ / kWh

Jan. 15, 2016USD ($)

Jan. 01, 2016USD ($)

Dec. 31, 2015USD ($)

Jun. 01, 2015USD ($)

Mar. 02, 2015USD ($)

Feb. 01, 2015$ / kWh

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

Jun. 01, 2011USD ($)

Sep. 30, 2016

Dec. 31, 2014storage_systempenetration_feederMW

Apr. 30, 2014workshop

Dec. 31, 2016$ / kWh

Jan. 27, 2017USD ($)

Dec. 05, 2016USD ($)

Jul. 01, 2016USD ($)

Apr. 01, 2016USD ($)

Jul. 01, 2015USD ($)

Mar. 20, 2015USD ($)project

Lost Fixed Cost Recovery Mechanism

Settlement Agreement

Rate matter cap percentage of retail revenue

1.00%

ACC | 2016 DSMAC

Settlement Agreement

Amount of approved budget

$ 68,900,000

$ 68,900,000

Additional approved budget

$ 4,000,000

ACC | 2017 DSMAC

Settlement Agreement

Amount of proposed budget

$ 62,600,000

ACC | Residential demand response, energy storage and load management program

Settlement Agreement

Additional approved budget

$ 4,000,000

ACC | Electric Energy Efficiency Standard

Settlement Agreement

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

3

Public utilities, cost effective efficiency programs, number of days to convene a workshop

120 days

ACC | Modernization and Expansion of the Renewal Energy Standard

Settlement Agreement

Proposed renewal energy standard, percent of retail sales

30.00%

Current renewal energy standard, percent of retail sales

15.00%

ACC | Net Metering

Settlement Agreement

Cost of service, resource comparison proxy method, maximum annual percentage decrease

10.00%

Cost of service for interconnected DG system customers, grandfathered period

20 years

Rate matters, cost of service for new customers, guaranteed export price period

10 years

ACC | Retail Rate Case Filing with Arizona Corporation Commission

Regulatory Matters [Line Items]

Net retail rate increase

$ 165,900,000

Adjuster account balance transferred into base rates

$ 267,600,000

Approximate percentage of increase in average customer bill

5.74%

Approximate percentage of increase in average residential customer bill

7.96%

original cost rate base

$ 6,800,000,000

Required return on incremental fair value rate base above original cost rate base

1.00%

Base rate for fuel and purchased power costs | $ / kWh

0.029882

Decrease in base rate for fuel and purchased power costs | $ / kWh

0.03207

Plan option, non-partial requirements customers, maximum average monthly energy usage | kWh

600

Case completion term

12 months

Settlement Agreement

Reduced system benefits charge, amount

$ 14,600,000

FERC | Transmission rates, transmission cost adjustor and other transmission matters

Settlement Agreement

Increase (decrease) in annual wholesale transmission rates

$ 24,900,000

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

Amount of adjustment representing prorated sales losses pending approval

$ 46,400,000

Increase in amount of adjustment representing prorated sales losses

$ 7,900,000

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 | RES

Settlement Agreement

Plan term

5 years

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

Settlement Agreement

Amount of proposed budget

$ 148,000,000

Cost Recovery Mechanisms | ACC | Arizona Renewable Energy Standard and Tariff 2017

Settlement Agreement

Amount of proposed budget

$ 150,000,000

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

0.001678

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)

Subsequent Event | ACC | 2017 DSMAC

Settlement Agreement

Amount of proposed budget

$ 66,600,000

Subsequent Event | ACC | Power Supply Adjustor (PSA)

Settlement Agreement

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

(0.001348)

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

(0.001027)

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

(0.000321)

Subsequent Event | ACC | Retail Rate Case Filing with Arizona Corporation Commission

Regulatory Matters [Line Items]

Case completion extension term

33 days

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

Settlement Agreement

Amount of adjustment representing prorated sales losses pending approval

$ 63,700,000

Increase in amount of adjustment representing prorated sales losses

$ 17,300,000

Four Corners Power Plant | ACC | Retail Rate Case Filing with Arizona Corporation Commission

Regulatory Matters [Line Items]

Authorization to defer for potential future recovery of construction costs

400,000,000

Ocotillo Plant | ACC | Retail Rate Case Filing with Arizona Corporation Commission

Regulatory Matters [Line Items]

Authorization to defer for potential future recovery of construction costs

$ 500,000,000

Alternative to AZ Sun Program, Phase 1 | 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 | Arizona Renewable Energy Standard and Tariff 2014

Settlement Agreement

Rate matter additional capacity from AZ Sun projects | MW

2

Number of energy storage systems | storage_system

2

Number of high solar penetration feeders | penetration_feeder

2

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - ARIZONA PUBLIC SERVICE COMPANY	Jun. 01, 2016
Proposed Capital Structure and Costs of Capital
Requested debt capital structure (as a percent)	44.20%
Requested debt cost of capital (as a percent)	5.13%
Requested equity capital structure (as a percent)	55.80%
Requested equity cost of capital (as a percent)	10.50%
Requested weighted-average cost of capital (as a percent)	8.13%

Regulatory Matters Regulatory59

Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Change in regulatory asset
Deferred fuel and purchased power	$ (60,303)	$ 14,997	$ (26,927)
Deferred fuel and purchased power amortization	38,152	1,617	40,757
ARIZONA PUBLIC SERVICE COMPANY
Change in regulatory asset
Deferred fuel and purchased power	(60,303)	14,997	(26,927)
Deferred fuel and purchased power amortization	38,152	1,617	40,757
ACC | ARIZONA PUBLIC SERVICE COMPANY | Power Supply Adjustor (PSA) | Cost Recovery Mechanisms
Change in regulatory asset
Beginning balance	(9,688)	6,926
Deferred fuel and purchased power	60,303	(14,997)
Deferred fuel and purchased power amortization	(38,150)	(1,617)
Ending balance	$ 12,465	$ (9,688)	$ 6,926

Regulatory Matters - Four Corne

Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - USD ($) $ in Millions	Jan. 13, 2017	Dec. 23, 2014	Dec. 30, 2013	Jul. 31, 2012	Jun. 30, 2016	Dec. 31, 2016	Feb. 13, 2017	Dec. 31, 2015
Acquisition
Regulatory asset amortization period				3 years
Retired power plant costs | APS
Acquisition
Regulatory asset, net book value						$ 116
SCE | Four Corners | APS
Acquisition
Regulatory assets								$ 12
Transmission termination agreement net receipt due to negotiation of alternate arrangement			$ 40
Regulatory assets, write of amount					$ 12
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						$ 64
Regulatory asset amortization period						10 years
Subsequent Event | Navajo Plant | APS
Acquisition
Asset net book value							$ 108
Subsequent Event | Compromise Proposal to meet Environmental and Emissions Standards and Rules | ACC | APS
Acquisition
Number of days to file a petition	60 days

Regulatory Matters - Schedule o

Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Detail of regulatory assets
Regulatory assets, current	$ 106,875	$ 149,555
Regulatory assets, non-current	1,313,428	1,214,146
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	711,059	619,223
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	9,913	9,913
Regulatory assets, non-current	117,591	127,518
Income taxes - AFUDC equity
Detail of regulatory assets
Regulatory assets, current	6,305	5,495
Regulatory assets, non-current	152,118	133,712
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	0	71,852
Regulatory assets, non-current	42,963	69,697
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	6,689	6,689
Regulatory assets, non-current	56,894	63,582
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	2,120	1,766
Regulatory assets, non-current	54,356	48,462
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	61,307	45,507
Regulatory assets, non-current	0	0
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	18,775	18,143
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	35,595	34,751
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	73,200	50,453
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,637	1,515
Regulatory assets, non-current	16,942	16,375
AG-1 deferral
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	5,868	0
Demand side management (b)
Detail of regulatory assets
Regulatory assets, current	3,744	0
Regulatory assets, non-current	0	0
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,513	1,520
Regulatory assets, non-current	10,589	12,163
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	0	4,543
Regulatory assets, non-current	0	0
Mead-Phoenix transmission line CIAC
Detail of regulatory assets
Regulatory assets, current	332	332
Regulatory assets, non-current	10,708	11,040
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	12,465	0
Regulatory assets, non-current	0	0
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	418	418
Regulatory assets, non-current	5,182	6,085
Other
Detail of regulatory assets
Regulatory assets, current	432	5
Regulatory assets, non-current	$ 1,588	$ 2,942

Regulatory Matters - Schedule62

Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Detail of regulatory liabilities
Regulatory liabilities, current	$ 99,899	$ 145,766
Regulatory liabilities, non-current	948,916	994,152
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	279,976	277,554
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	29,899	39,746
Regulatory liabilities, non-current	223,145	240,367
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	32,662	34,100
Regulatory liabilities, non-current	123,913	179,521
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	4,368	3,604
Regulatory liabilities, non-current	108,827	97,175
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	1,771	1,113
Regulatory liabilities, non-current	70,898	72,454
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	0	3,051
Regulatory liabilities, non-current	71,726	67,437
Renewable energy standard (b)
Detail of regulatory liabilities
Regulatory liabilities, current	26,809	43,773
Regulatory liabilities, non-current	0	4,365
Demand side management (b)
Detail of regulatory liabilities
Regulatory liabilities, current	0	6,079
Regulatory liabilities, non-current	20,472	19,115
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	15,287	13,678
Deferred fuel and purchased power (b) (c)
Detail of regulatory liabilities
Regulatory liabilities, current	0	9,688
Regulatory liabilities, non-current	0	0
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,063	2,062
Regulatory liabilities, non-current	8,895	6,001
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	18,248	8,920
Other
Detail of regulatory liabilities
Regulatory liabilities, current	2,327	2,550
Regulatory liabilities, non-current	$ 7,529	$ 7,565

Income Taxes (Details)

Income Taxes (Details) - USD ($)	Apr. 04, 2013	Feb. 17, 2011	Dec. 31, 2016
Income Taxes
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			98,000,000
Amount of federal and state loss carryforwards which will begin to expire in 2019			5,000,000
increase (decrease) in deferred income taxes due to regulation adoption			27,000,000
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			74,000,000
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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 34,447	$ 44,775	$ 41,997
Additions for tax positions of the current year	2,695	2,175	4,309
Additions for tax positions of prior years	886	0	751
Reductions for tax positions of prior years for:
Changes in judgment	(1,953)	(10,244)	(2,282)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	0	(2,259)	0
Total unrecognized tax benefits, end of the year	36,075	34,447	44,775
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	34,447	44,775	41,997
Additions for tax positions of the current year	2,695	2,175	4,309
Additions for tax positions of prior years	886	0	751
Reductions for tax positions of prior years for:
Changes in judgment	(1,953)	(10,244)	(2,282)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	0	(2,259)	0
Total unrecognized tax benefits, end of the year	$ 36,075	$ 34,447	$ 44,775

Income Taxes - Summary of Unrec

Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	$ 11,313	$ 9,523	$ 11,207
Unrecognized tax benefit interest expense/(benefit) recognized	529	(161)	752
Unrecognized tax benefit interest accrued	1,333	804	965
ARIZONA PUBLIC SERVICE COMPANY
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	11,313	9,523	11,207
Unrecognized tax benefit interest expense/(benefit) recognized	529	(161)	752
Unrecognized tax benefit interest accrued	$ 1,333	$ 804	$ 965

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
Federal									$ 8,630	$ (12,335)	$ 25,054
State									1,259	4,763	10,382
Total current									9,889	(7,572)	35,436
Deferred:
Federal									201,743	221,505	167,365
State									24,779	23,787	17,904
Total deferred									226,522	245,292	185,269
Income tax expense	$ 27,309	$ 141,446	$ 65,742	$ 1,914	$ 22,847	$ 139,555	$ 67,371	$ 7,947	236,411	237,720	220,705
ARIZONA PUBLIC SERVICE COMPANY
Current:
Federal									711	6,485	40,115
State									4,276	7,813	15,598
Total current									4,987	14,298	55,713
Deferred:
Federal									215,178	208,326	165,027
State									25,677	23,217	16,620
Total deferred									240,855	231,543	181,647
Income tax expense									$ 245,842	$ 245,841	$ 237,360

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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									$ 244,278	$ 242,869	$ 225,540
State income tax net of federal income tax benefit									16,311	18,265	18,149
Credits and favorable adjustments related to prior years resolved in current year									0	(2,169)	0
Medicare Subsidy Part-D									844	837	830
Allowance for equity funds used during construction (see Note 1)									(11,724)	(9,711)	(8,523)
Palo Verde VIE noncontrolling interest (see Note 18)									(6,823)	(6,626)	(9,135)
Investment tax credit amortization									(5,887)	(5,527)	(4,928)
Other									(588)	(218)	(1,228)
Income tax expense	$ 27,309	$ 141,446	$ 65,742	$ 1,914	$ 22,847	$ 139,555	$ 67,371	$ 7,947	$ 236,411	$ 237,720	$ 220,705
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									$ 254,617	$ 250,267	$ 239,638
State income tax net of federal income tax benefit									18,750	20,433	21,148
Credits and favorable adjustments related to prior years resolved in current year									0	(1,892)	0
Medicare Subsidy Part-D									844	837	830
Allowance for equity funds used during construction (see Note 1)									(11,724)	(9,711)	(8,523)
Palo Verde VIE noncontrolling interest (see Note 18)									(6,823)	(6,626)	(9,135)
Investment tax credit amortization									(5,887)	(5,527)	(4,928)
Other									(3,935)	(1,940)	(1,670)
Income tax expense									$ 245,842	$ 245,841	$ 237,360

Income Taxes - Components of De

Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
DEFERRED TAX ASSETS
Risk management activities	$ 26,614	$ 70,498
Regulatory liabilities:
Asset retirement obligation and removal costs	200,140	216,765
Unamortized investment tax credits	113,195	100,779
Other postretirement liabilities	60,375	83,034
Other	63,311	60,707
Pension liabilities	204,436	191,028
Renewable energy incentives	56,379	60,956
Credit and loss carryforwards	75,944	59,557
Other	158,421	149,033
Total deferred tax assets	958,815	992,357
DEFERRED TAX LIABILITIES
Plant-related	(3,297,989)	(3,116,752)
Risk management activities	(7,594)	(10,626)
Other postretirement assets	(63,477)	(71,737)
Regulatory assets:
Allowance for equity funds used during construction	(61,088)	(54,110)
Deferred fuel and purchased power — mark-to-market	(21,396)	(55,020)
Pension benefits	(274,184)	(240,692)
Retired power plant costs (see Note 3)	(49,166)	(53,420)
Other	(123,987)	(108,441)
Other	(5,166)	(4,984)
Total deferred tax liabilities	(3,904,047)	(3,715,782)
Deferred income taxes — net	(2,945,232)	(2,723,425)
ARIZONA PUBLIC SERVICE COMPANY
DEFERRED TAX ASSETS
Risk management activities	26,614	70,498
Regulatory liabilities:
Asset retirement obligation and removal costs	200,140	216,765
Unamortized investment tax credits	113,195	100,779
Other postretirement liabilities	60,375	83,034
Other	63,311	60,707
Pension liabilities	194,981	181,787
Renewable energy incentives	56,379	60,956
Credit and loss carryforwards	1,645	0
Other	187,453	176,016
Total deferred tax assets	904,093	950,542
DEFERRED TAX LIABILITIES
Plant-related	(3,297,989)	(3,116,752)
Risk management activities	(7,594)	(10,626)
Other postretirement assets	(62,819)	(70,986)
Regulatory assets:
Allowance for equity funds used during construction	(61,088)	(54,110)
Deferred fuel and purchased power — mark-to-market	(21,396)	(55,020)
Pension benefits	(274,184)	(240,692)
Retired power plant costs (see Note 3)	(49,166)	(53,420)
Other	(123,987)	(108,441)
Other	(5,165)	(4,984)
Total deferred tax liabilities	(3,903,388)	(3,715,031)
Deferred income taxes — net	$ (2,999,295)	$ (2,764,489)

Lines of Credit and Short-Ter69

Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pinnacle West
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.125%	0.125%
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.10%	0.10%
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed	$ 1,275,000	$ 1,200,000
Commercial paper	(177,200)	0
Unused amount	1,097,800	1,200,000
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Amount committed	275,000	200,000
Commercial paper	(41,700)	0
Unused amount	233,300	200,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Amount committed	1,000,000	1,000,000
Commercial paper	(135,500)	0
Unused amount	$ 864,500	$ 1,000,000

Lines of Credit and Short-Ter70

Lines of Credit and Short-Term Borrowings (Details)	Aug. 31, 2016USD ($)	Dec. 31, 2016USD ($)Facility	May 13, 2016USD ($)	May 12, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 02, 2015USD ($)	Feb. 06, 2013USD ($)
Lines of Credit and Short-Term Borrowings
Short-term borrowings		$ 177,200,000				$ 0
Pinnacle West
Lines of Credit and Short-Term Borrowings
Short-term borrowings		41,700,000				0
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Short-term borrowings		135,500,000				0
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		1,275,000,000				1,200,000,000
Long-term line of credit		177,200,000				0
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Amount committed		275,000,000				200,000,000
Long-term line of credit		41,700,000				0
Revolving credit facility | Pinnacle West | Revolving credit facility maturing August 2017
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	$ 75,000,000
Debt instrument, term	364 days
Short-term borrowings		40,000,000
Revolving credit facility | Pinnacle West | Revolving credit facility maturing in May 2019
Lines of Credit and Short-Term Borrowings
Amount committed				$ 200,000,000
Revolving credit facility | Pinnacle West | Revolving credit facility maturing May 2021
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
Long-term line of credit		135,500,000				0
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
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Amount committed		500,000,000	$ 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 facilities maturing in 2020 and 2021
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
Letter of credit | Pinnacle West | Revolving credit facility maturing May 2021
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		35,000,000
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facilities maturing in 2020 and 2021
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit		0
Commercial paper | Pinnacle West | Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Commercial paper		1,700,000
Commercial paper | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Maximum commercial paper support available under credit facility		500,000,000			$ 500,000,000	$ 250,000,000
Commercial paper | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facilities maturing in 2020 and 2021
Lines of Credit and Short-Term Borrowings
Long-term line of credit		$ 135,500,000
London Interbank Offered Rate (LIBOR) [Member] | Revolving credit facility | Pinnacle West | Revolving credit facility maturing August 2017
Lines of Credit and Short-Term Borrowings
Debt instrument, basis spread on variable rate	0.80%

Long-Term Debt and Liquidity 71

Long-Term Debt and Liquidity Matters (Details) - USD ($)	Aug. 01, 2016	Dec. 31, 2016	Dec. 06, 2016	Sep. 20, 2016	Jun. 01, 2016	May 06, 2016	Apr. 22, 2016	Dec. 31, 2015	Feb. 06, 2013	Feb. 05, 2013
Debt Provisions
Total shareholder equity		$ 4,803,622,000						$ 4,583,917,000
Maximum
Debt Provisions
Ratio of consolidated debt to consolidated capitalization (as a percent)		65.00%
ARIZONA PUBLIC SERVICE COMPANY
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		$ 4,905,680,000						4,679,254,000
ARIZONA PUBLIC SERVICE COMPANY | ACC
Debt Provisions
Total shareholder equity		4,900,000,000
Total capitalization		9,100,000,000
Dividend restrictions, shareholder equity required		$ 3,600,000,000
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
Debt Provisions
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)		48.00%
Total shareholder equity		$ 4,803,622,000						$ 4,583,917,000
Term Loan Facility Maturing April 22, 2019 | ARIZONA PUBLIC SERVICE COMPANY | Term loan
Long-Term Debt and Liquidity Matters [Line Items]
Notes issued							$ 100,000,000
Unsecured Senior Notes 3.75 Percent Mature on 15 May, 2046 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Notes issued						$ 350,000,000
Interest rate (as a percent)						3.75%
Arizona Pollution Control Corporation Revenue Refunding Bonds, 2009 Series D and E | ARIZONA PUBLIC SERVICE COMPANY | Current maturities of long-term debt
Long-Term Debt and Liquidity Matters [Line Items]
Principal balance repaid					$ 64,000,000
Arizona pollution control corporation revenue refunding bonds, 2009 series A | ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Principal balance repaid					$ 13,000,000
Unsecured Senior Notes 6.25 Percent Mature on 01 August, 2016 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	6.25%
Repayments of debt	$ 250,000,000
Unsecured Senior Notes 2.55 Percent Mature on 15 September, 2026 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Notes issued				$ 250,000,000
Interest rate (as a percent)				2.55%
Arizona Pollution Control Corporation 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				$ 27,000,000
Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds | ARIZONA PUBLIC SERVICE COMPANY | Current maturities of long-term debt
Long-Term Debt and Liquidity Matters [Line Items]
Principal balance repaid			$ 17,000,000

Long-Term Debt and Liquidity 72

Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Long-Term Debt and Liquidity Matters [Line Items]
Total long-term debt	$ 4,146,785	$ 3,819,971
Long-term debt less current maturities	4,021,785	3,462,391
APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	4,058,125
Unamortized discount	(11,816)	(10,374)
Unamortized premium	4,506	4,686
Unamortized debt issue costs	(29,030)	(27,896)
Total long-term debt	4,021,785	3,694,971
Less current maturities	0	(357,580)
Total long-term debt less current maturities	4,021,785	3,337,391
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	4,183,125
Total long-term debt	125,000	125,000
Long-term debt less current maturities	0	125,000
Pollution Control Bonds - Variable | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 35,975	$ 92,405
Pollution Control Bonds - Variable | APS | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	0.81%	0.01%
Pollution Control Bonds - Variable | APS | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)		0.24%
Pollution Control Bonds - Fixed | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 147,150	$ 211,150
Pollution Control Bonds - Fixed | APS | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	1.75%	1.75%
Pollution Control Bonds - Fixed | APS | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	4.70%	4.70%
Total Pollution Control Bonds | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 183,125	$ 303,555
Senior unsecured notes | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 3,725,000	$ 3,375,000
Senior unsecured notes | APS | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	2.20%	2.20%
Senior unsecured notes | APS | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	8.75%	8.75%
Term loan facility | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Total long-term debt	$ 125,000	$ 125,000
Less current maturities	(125,000)	0
Total long-term debt less current maturities	$ 0	$ 125,000
Weighted-average interest rate (as a percent)	1.52%	1.174%
Term loan | APS
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	1.427%	1.024%
Term loan | Term loan facility maturing June 26, 2018 | APS
Long-Term Debt and Liquidity Matters [Line Items]
Term loans	$ 150,000	$ 50,000

Long-Term Debt and Liquidity 73

Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Pinnacle West
Principal payments due on long-term debt
2,017	$ 125,000
2,018	82,000
2,019	600,000
2,020	250,000
2,021	0
Thereafter	3,126,125
Total	4,183,125
ARIZONA PUBLIC SERVICE COMPANY
Principal payments due on long-term debt
2,017	0
2,018	82,000
2,019	600,000
2,020	250,000
2,021	0
Thereafter	3,126,125
Total	$ 4,058,125

Long-Term Debt and Liquidity 74

Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 4,146,785	$ 3,819,971
Fair Value	4,425,789	4,106,367
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	4,021,785	3,694,971
Fair Value	$ 4,300,789	$ 3,981,367

Retirement Plans and Other Be75

Retirement Plans and Other Benefits Retirement Plans and Other Benefits (Details)	1 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2011USD ($)	Jan. 01, 2015Age
Plan Design Changes [Abstract]
Noncurrent asset		$ 166,206,000	$ 185,997,000
Amount of other postretirement benefit trust assets for union employee medical costs		140,000,000
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		54,000,000
Pension Benefits
Plan Design Changes [Abstract]
Noncurrent asset		$ 0	0
Expected long-term return on plan assets for next fiscal year (as a percent)		6.55%
Contributions
Employer's contributions under the plan		$ 100,000,000	100,000,000	175,000,000
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)		57.00%
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)		43.00%
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
Noncurrent asset		$ 166,206,000	185,997,000
Expected long-term return on plan assets for next fiscal year (as a percent)		6.37%
Contributions
Employer's contributions under the plan		$ 819,000	791,000	1,000,000
Expected employer contributions
2017 (less than)		1,000,000
2018 (less than)		1,000,000
2019 (less than)		$ 1,000,000
Other postretirement benefits | Fixed income
Target asset allocation
Actual asset allocation (as a percent)		51.00%
Other postretirement benefits | Non-fixed income
Target asset allocation
Actual asset allocation (as a percent)		49.00%
Pinnacle West
Employee savings plan benefits
Expenses recorded for the defined contribution savings plan		$ 10,000,000	9,000,000	9,000,000
ARIZONA PUBLIC SERVICE COMPANY
Plan Design Changes [Abstract]
Noncurrent asset		$ 162,911,000	182,625,000
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	100,000,000	175,000,000
ARIZONA PUBLIC SERVICE COMPANY | Other postretirement benefits
Contributions
Employer's contributions under the plan		$ 1,000,000	$ 1,000,000	$ 1,000,000

Retirement Plans and Other Be76

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

Retirement Plans and Other Be77

Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	$ 3,033,803	$ 3,078,648
Service cost	53,792	59,627	$ 53,080
Interest cost	131,647	123,983	129,194
Benefit payments	(142,247)	(137,115)
Actuarial (gain) loss	127,467	(91,340)
Benefit obligation at the end of the period	3,204,462	3,033,803	3,078,648
Change in Plan Assets
Balance at the beginning of the period	2,542,774	2,615,404
Actual return on plan assets	166,408	(44,690)
Employer's contributions under the plan	100,000	100,000	175,000
Benefit payments	(133,825)	(127,940)
Balance at the end of the period	2,675,357	2,542,774	2,615,404
Funded Status at the end of the period	(529,105)	(491,029)
Other Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	647,020	682,335
Service cost	14,993	16,827	18,139
Interest cost	29,721	28,102	41,243
Benefit payments	(26,231)	(24,988)
Actuarial (gain) loss	50,942	(55,256)
Benefit obligation at the end of the period	716,445	647,020	682,335
Change in Plan Assets
Balance at the beginning of the period	833,017	834,625
Actual return on plan assets	63,463	(2,399)
Employer's contributions under the plan	819	791	1,000
Benefit payments	(14,648)	0
Balance at the end of the period	882,651	833,017	$ 834,625
Funded Status at the end of the period	$ 166,206	$ 185,997

Retirement Plans and Other Be78

Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
Projected benefit obligation	$ 3,204,462	$ 3,033,803
Accumulated benefit obligation	3,049,406	2,873,467
Fair value of plan assets	$ 2,675,357	$ 2,542,774

Retirement Plans and Other Be79

Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	$ 166,206	$ 185,997
Pension Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	0	0
Current liability	(19,795)	(10,031)
Noncurrent liability	(509,310)	(480,998)
Net amount recognized	(529,105)	(491,029)
Other Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	166,206	185,997
Current liability	0	0
Noncurrent liability	0	0
Net amount recognized	$ 166,206	$ 185,997

Retirement Plans and Other Be80

Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Details related to accumulated other comprehensive loss
Accumulated other comprehensive loss	$ 39,070	$ 37,593
Other Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	146,509	127,124
Prior service cost (credit)	(303,417)	(341,301)
APS’s portion recorded as a regulatory (asset) liability	156,575	213,621
Income tax expense (benefit)	833	925
Accumulated other comprehensive loss	500	369
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	5,181
Prior service cost (credit)	(37,842)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017	(32,661)
Pension Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	773,750	679,501
Prior service cost (credit)	81	609
APS’s portion recorded as a regulatory (asset) liability	(711,059)	(619,223)
Income tax expense (benefit)	(24,202)	(23,663)
Accumulated other comprehensive loss	38,570	$ 37,224
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	46,971
Prior service cost (credit)	81
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017	$ 47,052

Retirement Plans and Other Be81

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, 2016	Dec. 31, 2015
Weighted-average assumptions used to determine benefit obligations
Rate of compensation increase (as a percent)			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%	7.00%
Initial post-65 health care cost trend rate (as a percent)	5.00%	7.50%	5.00%	5.00%
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	0 years
Pension Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)			4.08%	4.37%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.88%	4.88%	4.37%	4.02%
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%	6.90%
Other Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)			4.17%	4.52%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.41%	5.10%	4.52%	4.14%
Expected long-term return on plan assets (as a percent)	4.25%	6.80%	4.45%	4.45%
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			$ 8,430
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants			(5,455)
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs			8,440
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs			(6,527)
Effect of 1% increase on the accumulated other postretirement benefit obligation			108,046
Effect of 1% decrease on the accumulated other postretirement benefit obligation			$ (86,651)

Retirement Plans and Other Be82

Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	$ 2,675,357	$ 2,542,774	$ 2,615,404
Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	749,541	680,351
Fair value of plan assets	2,675,357	2,542,774
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	613,193	640,679
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	1,312,623	1,221,744
Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	882,651	833,017	$ 834,625
Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	123,234	135,059
Fair value of plan assets	882,651	833,017
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	456,718	449,826
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	302,699	248,132
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	13,995	1,893
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	13,995	1,893
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	304	240
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	304	240
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	1,210,453	1,108,736
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	1,210,453	1,108,736
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	268,193	217,026
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	268,193	217,026
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	112,583	274,778
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	112,583	274,778
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	145,255	131,435
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	145,255	131,435
Other | 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	102,170	113,008
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	102,170	113,008
Other | 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	34,506	31,106
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	34,506	31,106
Common stock 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	235,109	247,701
Common stock 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	235,109	247,701
Common stock 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	243,741	265,583
Common stock 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	243,741	265,583
Mutual fund | 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	251,506
Mutual fund | 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	251,506
Mutual fund | 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	67,418
Mutual fund | 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	67,418
Equities | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	266,840	315,989
Fair value of plan assets	266,840	315,989
Equities | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	95,814	110,055
Fair value of plan assets	95,814	110,055
Real estate | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	161,449	150,359
Fair value of plan assets	161,449	150,359
Real estate | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	14,509	13,512
Fair value of plan assets	14,509	13,512
Partnerships | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	208,915	169,937
Fair value of plan assets	208,915	169,937
Partnerships | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	3,060
Fair value of plan assets	3,060
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
Other	112,337	44,066
Fair value of plan assets	112,337	44,066
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
Other	9,851	11,492
Fair value of plan assets	$ 9,851	11,492
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

Retirement Plans and Other Be83

Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Pension Benefits
Estimated Future Benefit Payments
2,017	$ 172,859
2,018	173,232
2,019	182,944
2,020	191,037
2,021	196,292
Years 2022-2026	1,049,149
Other Benefits
Estimated Future Benefit Payments
2,017	31,126
2,018	33,795
2,019	36,195
2,020	37,998
2,021	39,368
Years 2022-2026	$ 201,944

Leases (Details)

Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)Trust	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 1986Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Lease expense	$ 16,000	$ 17,000	$ 18,000
Pinnacle West
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2,017	12,330
2,018	10,987
2,019	9,019
2,020	7,688
2,021	5,266
Thereafter	59,647
Total future lease commitments	104,937
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
2,017	11,919
2,018	10,690
2,019	8,767
2,020	7,439
2,021	5,020
Thereafter	57,207
Total future lease commitments	101,042
Lease expense	$ 15,000	$ 14,000	$ 15,000
Number of VIE lessor trusts | Trust	3			3

Jointly-Owned Facilities (Detai

Jointly-Owned Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Jul. 06, 2016
4CA
Interests in jointly-owned facilities
Plant in Service	$ 110,000
Accumulated Depreciation	79,000
Construction work in progress	$ 30,000
Palo Verde Units 1 and 3 | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	29.10%
Plant in Service	$ 1,770,324
Accumulated Depreciation	1,080,072
Construction work in progress	$ 17,615
Palo Verde Unit 2 | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	16.80%
Plant in Service	$ 581,572
Accumulated Depreciation	360,757
Construction work in progress	$ 9,717
Palo Verde Common | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	28.00%
Plant in Service	$ 672,799
Accumulated Depreciation	242,649
Construction work in progress	62,479
Palo Verde Sale Leaseback | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Plant in Service	351,050
Accumulated Depreciation	237,535
Construction work in progress	$ 0
Four Corners Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	$ 934,837
Accumulated Depreciation	578,924
Construction work in progress	$ 248,072
Navajo Generating Station Units 1, 2 and 3 | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	14.00%
Plant in Service	$ 279,629
Accumulated Depreciation	176,931
Construction work in progress	$ 5,761
Cholla Common Facilities | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	63.30%
Plant in Service	$ 159,707
Accumulated Depreciation	58,276
Construction work in progress	$ 806
ANPP 500kV System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	33.60%
Plant in Service	$ 127,970
Accumulated Depreciation	38,610
Construction work in progress	$ 2,291
Navajo Southern System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	22.50%
Plant in Service	$ 62,135
Accumulated Depreciation	20,491
Construction work in progress	$ 334
Palo Verde — Yuma 500kV System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	19.00%
Plant in Service	$ 13,699
Accumulated Depreciation	5,368
Construction work in progress	$ 408
Four Corners Switchyards | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	51.30%
Plant in Service	$ 39,850
Accumulated Depreciation	10,474
Construction work in progress	$ 1,044
Phoenix — Mead System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	17.10%
Plant in Service	$ 39,330
Accumulated Depreciation	13,725
Construction work in progress	$ 85
Palo Verde — Rudd 500kV System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 91,904
Accumulated Depreciation	19,818
Construction work in progress	$ 227
Morgan — Pinnacle Peak System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	65.20%
Plant in Service	$ 140,374
Accumulated Depreciation	13,557
Construction work in progress	$ 0
Round Valley System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 515
Accumulated Depreciation	127
Construction work in progress	$ 0
Palo Verde — Morgan System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	85.80%
Plant in Service	$ 125,908
Accumulated Depreciation	1,326
Construction work in progress	$ 28,949
Hassayampa — North Gila System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	80.00%
Plant in Service	$ 142,541
Accumulated Depreciation	3,231
Construction work in progress	$ 0
Cholla 500kV Switchyard | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	85.70%
Plant in Service	$ 5,078
Accumulated Depreciation	1,201
Construction work in progress	$ 0
Saguaro 500kV Switchyard | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	75.00%
Plant in Service	$ 20,456
Accumulated Depreciation	12,426
Construction work in progress	$ 2
Cholla common construction facilities | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	50.50%
El Paso's Interest in Four Corners | 4CA
Interests in jointly-owned facilities
Ownership interest acquired	7.00%	7.00%

Commitments and Contingencies -

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)	Feb. 01, 2017USD ($)	Jan. 01, 2017USD ($)	Aug. 18, 2014USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)Trusttime_periodclaim	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 1986Trust
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Maximum insurance against public liability per occurrence for a nuclear incident					$ 13,400,000,000
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					$ 18,900,000
Number of VIE lessor trusts | Trust					3			3
Maximum potential retrospective assessment per incident of APS					$ 111,100,000
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					23,800,000
Collateral assurance provided based on rating triggers					$ 64,000,000
Period to provide collateral assurance based on rating triggers					20 days
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,017					$ 977,000,000
2,018					737,000,000
2,019					598,000,000
2,020					525,000,000
2,021					524,000,000
Thereafter					7,300,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal take-or-pay commitments
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,017					195,428,000
2,018					189,588,000
2,019					193,818,000
2,020					198,160,000
2,021					202,619,000
Thereafter					2,068,355,000
Total obligation					3,047,968,000
Present value of commitments					2,100,000,000
Total purchases					160,066,000	$ 211,327,000	$ 236,773,000
ARIZONA PUBLIC SERVICE COMPANY | Renewable energy credits
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,017					40,000,000
2,018					40,000,000
2,019					40,000,000
2,020					40,000,000
2,021					40,000,000
Thereafter					420,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,017					17,000,000
2,018					18,000,000
2,019					19,000,000
2,020					21,000,000
2,021					22,000,000
Thereafter					241,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Balance Sheet Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
Total obligation					207,000,000	$ 202,000,000
4CA | Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2,017					1,000,000
2,018					1,000,000
2,019					1,000,000
2,020					1,000,000
2,021					2,000,000
Thereafter					17,000,000
4CA | Coal Mine Reclamation Balance Sheet Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
Total obligation					15,000,000
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
Palo Verde Nuclear Generating Station [Abstract]
Proceeds from legal settlements					$ 53,900,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
New claims filed | claim					2
Number of settlement agreement time periods | time_period					2
Proceeds from legal settlements					$ 15,700,000
Subsequent Event | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Maximum available nuclear liability insurance		$ 450,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program		$ 13,000,000,000
Subsequent Event | Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Palo Verde Nuclear Generating Station [Abstract]
Litigation settlement, amount	$ 11,300,000
Subsequent Event | Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Litigation settlement, amount	$ 3,300,000

Commitments and Contingencies87

Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) - ARIZONA PUBLIC SERVICE COMPANY $ in Millions	Aug. 06, 2013Defendant	Sep. 08, 2011kVCustomer	Dec. 31, 2016USD ($)
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
Contaminated groundwater wells
Superfund
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit | Defendant	24

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details)	Jul. 06, 2016guarantee	Jun. 24, 2016	Mar. 16, 2016USD ($)	May 23, 2013USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2016USD ($)
Environmental Matters [Abstract]
Clean power plan, optional extension period						2 years
Payment Guarantee
Financial Assurances
Number of parental guarantees | guarantee	2
Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost						$ 15,000,000
Cholla Units 1-3 | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost						8,000,000
New Mexico Tax Matter | Four Corners
Environmental Matters [Abstract]
Coal severance surtax, penalty, and interest				$ 30,000,000
Litigation settlement, amount			$ 1,000,000
New Mexico Tax Matter | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Share of the assessment				12,000,000
Partial payment assessment				$ 800,000
Litigation settlement, amount			$ 800,000
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit						35,000,000
Equity Lessors Sale Leaseback Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit						53,000,000
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 share 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
Coal Combustion Waste | Boron Inclusion on List of Groundwater Constituents | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Period to complete rulemaking proceeding		3 years
Coal Combustion Waste | Minimum | Cholla | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost						5,000,000
Coal Combustion Waste | Maximum | Cholla | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost						$ 40,000,000
El Paso's Interest in Four Corners | 4CA
Financial Assurances
Ownership interest acquired	7.00%					7.00%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)turbine_unit	Dec. 31, 2015USD ($)
Changes attributable to:
Asset retirement obligations, current	$ 9,135	$ 28,573
ARIZONA PUBLIC SERVICE COMPANY
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	443,576	390,750
Changes attributable to:
Accretion expense	26,656	25,163
Settlements	(15,732)	(32,048)
Estimated cash flow revisions	151,046	17,556
Newly incurred or acquired obligations	18,929	42,155
Asset retirement obligations at the end of year	624,475	443,576
Asset retirement obligations, current	$ 8,703	28,573
Ocotillo Steam Units | ARIZONA PUBLIC SERVICE COMPANY
Asset Retirement Obligations
Number of constructed turbine units | turbine_unit	5
Changes attributable to:
Newly incurred or acquired obligations	$ 10,000
El Paso's Share of Four Corners Units 4 & 5 [Member] | 4CA
Changes attributable to:
Newly incurred or acquired obligations	9,000
Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Settlements	(16,000)	(32,000)
Estimated cash flow revisions		24,000
Palo Verde Nuclear Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Asset Retirement Obligations
Increase in plant services	131,000
Decrease in regulatory liability	20,000
Changes attributable to:
Estimated cash flow revisions	$ 151,000
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 or acquired obligations		$ 39,000

Selected Quarterly Financial 90

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES	$ 739,199	$ 1,166,922	$ 915,394	$ 677,167	$ 734,430	$ 1,199,146	$ 890,648	$ 671,219	$ 3,498,682	$ 3,495,443	$ 3,491,632
Operations and maintenance	208,277	217,568	242,279	243,195	222,019	220,449	210,965	214,944	911,319	868,377	908,025
Operating income	122,816	451,258	231,748	50,162	109,834	445,111	231,973	67,684	855,984	854,602	811,242
INCOME TAXES (Note 4)	27,309	141,446	65,742	1,914	22,847	139,555	67,371	7,947	236,411	237,720	220,705
Net income	58,119	267,900	126,182	9,326	45,978	261,978	127,507	20,727	461,527	456,190	423,696
Net income attributable to common shareholders	$ 53,246	$ 263,027	$ 121,308	$ 4,453	$ 41,117	$ 257,116	$ 122,902	$ 16,122	$ 442,034	$ 437,257	$ 397,595
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.48	$ 2.36	$ 1.09	$ 0.04	$ 0.37	$ 2.32	$ 1.11	$ 0.15	$ 3.97	$ 3.94	$ 3.59
Net income attributable to common shareholders — diluted (in dollars per share)	$ 0.47	$ 2.35	$ 1.08	$ 0.04	$ 0.37	$ 2.30	$ 1.10	$ 0.14	$ 3.95	$ 3.92	$ 3.58
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Operating revenues	$ 737,006	$ 1,166,359	$ 909,757	$ 676,632	$ 733,586	$ 1,198,380	$ 889,723	$ 670,668	$ 3,489,754	$ 3,492,357	$ 3,488,946
Operations and maintenance	197,319	209,366	233,712	238,711	219,146	216,011	208,031	209,947	879,108	853,135	882,442
Operating income	95,765	307,601	165,684	48,930	86,709	301,238	162,704	61,333	617,980	611,984	592,792
INCOME TAXES (Note 4)									245,842	245,841	237,360
Net income									481,634	469,207	447,320
Net income attributable to common shareholders	$ 58,480	$ 269,220	$ 127,188	$ 7,253	$ 43,857	$ 261,187	$ 125,362	$ 19,868	$ 462,141	$ 450,274	$ 421,219

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets
Nuclear decommissioning trust	$ 779,586	$ 735,196
Total assets	11,076	30,364
Fair value measurement on a recurring basis
Assets
Coal reclamation trust - Cash equivalents	14,521
Other	(35,103)	(25,345)
Derivative assets	19,695	28,011
Other	354,056	314,622
Nuclear decommissioning trust	779,586	735,196
Other	318,953	289,277
Total assets	813,802	763,207
Liabilities
Other	31,049	39,698
Derivative Liability	(73,074)	(167,689)
Fair value measurement on a recurring basis | US commingled equity funds
Assets
Other	353,261	314,957
Nuclear decommissioning trust	353,261	314,957
Fair value measurement on a recurring basis | Cash and cash equivalents
Assets
Other	795	(335)
Nuclear decommissioning trust	795	11,925
Fair value measurement on a recurring basis | U.S. Treasury
Assets
Nuclear decommissioning trust	95,441	117,245
Fair value measurement on a recurring basis | Corporate
Assets
Nuclear decommissioning trust	111,623	96,243
Fair value measurement on a recurring basis | Mortgage-backed securities
Assets
Nuclear decommissioning trust	115,337	99,065
Fair value measurement on a recurring basis | Municipality bonds
Assets
Nuclear decommissioning trust	80,997	72,206
Fair value measurement on a recurring basis | Other
Assets
Nuclear decommissioning trust	22,132	23,555
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Coal reclamation trust - Cash equivalents	14,521
Decommissioning fund investments, gross fair value	95,441	129,505
Gross assets, fair value disclosure	109,962	129,505
Liabilities
Gross derivative liability	0	0
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	95,441	117,245
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	43,722	22,992
Decommissioning fund investments, gross fair value	330,089	291,069
Gross assets, fair value disclosure	373,811	314,061
Liabilities
Gross derivative liability	(45,641)	(144,044)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate
Assets
Decommissioning fund investments, gross fair value	111,623	96,243
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	115,337	99,065
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Decommissioning fund investments, gross fair value	80,997	72,206
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Decommissioning fund investments, gross fair value	22,132	23,555
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Gross derivative assets	11,076	30,364
Gross assets, fair value disclosure	11,076	30,364
Liabilities
Gross derivative liability	$ (58,482)	$ (63,343)

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Quantitative Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / MMBTU$ / MWh	Dec. 31, 2015USD ($)$ / MMBTU$ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	$ 11,076	$ 30,364
Liabilities | $	58,482	63,343
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	10,648	24,543
Liabilities | $	$ 32,042	$ 54,679
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	16.43	15.92
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	41.07	40.73
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	29.86	26.86
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities | $		$ 5,628
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
Implied electricity price volatilities (as a percent)		40.00%
Implied natural gas price volatilities (as a percent)		32.00%
Natural gas forward price (per MMbtu) | $ / MMBTU
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
Implied electricity price volatilities (as a percent)		59.00%
Implied natural gas price volatilities (as a percent)		40.00%
Natural gas forward price (per MMbtu) | $ / MMBTU
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
Implied electricity price volatilities (as a percent)		52.00%
Implied natural gas price volatilities (as a percent)		35.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	$ 428	$ 5,821
Liabilities | $	$ 26,440	$ 3,036
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	2.32	2.18
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	3.60	3.14
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		2.61
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	2.81

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, 2016	Dec. 31, 2015
Total net gains (losses) realized/unrealized:
Net derivative beginning balance	$ (32,979,000)	$ (41,386,000)
Included in earnings	0	0
Included in OCI	88,000	(452,000)
Deferred as a regulatory asset or liability	(37,543,000)	(4,009,000)
Settlements	15,146,000	14,809,000
Transfers into Level 3 from Level 2	1,900,000	(6,256,000)
Transfers from Level 3 into Level 2	5,982,000	4,315,000
Net derivative ending balance	(47,406,000)	(32,979,000)
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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 53,246	$ 263,027	$ 121,308	$ 4,453	$ 41,117	$ 257,116	$ 122,902	$ 16,122	$ 442,034	$ 437,257	$ 397,595
Weighted Average common shares outstanding — basic (in shares)									111,409	111,026	110,626
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units									637	526	552
Weighted average common shares outstanding — diluted (in shares)									112,046	111,552	111,178
Earnings per average common share attributable to common shareholders — basic (in dollars per share)	$ 0.48	$ 2.36	$ 1.09	$ 0.04	$ 0.37	$ 2.32	$ 1.11	$ 0.15	$ 3.97	$ 3.94	$ 3.59
Earnings per average common share attributable to common shareholders — diluted (in dollars per share)	$ 0.47	$ 2.35	$ 1.08	$ 0.04	$ 0.37	$ 2.30	$ 1.10	$ 0.14	$ 3.95	$ 3.92	$ 3.58

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) $ in Thousands	1 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2012shares	Dec. 31, 2016USD ($)shares	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)performance_criterianon_financial_seperate_performance_metricshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Stock-Based Compensation
Common shares available for issuance (in shares) | shares		2,500,000								2,500,000
Stock compensation cumulative effect adjustments						$ 45,855					$ 45,855
Operations and maintenance		$ (208,277)	$ (217,568)	$ (242,279)	$ (243,195)	(222,019)	$ (220,449)	$ (210,965)	$ (214,944)	$ (911,319)	(868,377)	$ (908,025)
Compensation cost that has been charged against income										19,000	19,000	33,000
Total income tax benefit recognized										10,000	7,000	13,000
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted		$ 13,000								$ 13,000
Expected weighted-average period of recognition of unrecognized compensation cost										2 years
Total fair value of shares vested										$ 22,000	21,000	22,000
Performance Shares
Number of performance element criteria | performance_criteria										2
Performance period										3 years
Number of non-financial separate performance metrics based on which awards vest | non_financial_seperate_performance_metric										6
Restricted stock unit awards
Stock-Based Compensation
Share-based liabilities paid										$ 3,000	10,000	9,000
Cash flow effect, cash used to settle awards										$ 3,000	3,000	3,000
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										141,811
Performance Shares
Stock-Based Compensation
Share-based liabilities paid											16,000	$ 12,000
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares) | shares										166,666
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								4,600,000
Accountings Standards Update 2016-09 | New Accounting Pronouncement, Early Adoption, Effect
Stock-Based Compensation
Operations and maintenance		$ 12,000
Retained Earnings
Stock-Based Compensation
Stock compensation cumulative effect adjustments						5,475					5,475
Retained Earnings | Accountings Standards Update 2016-09 | New Accounting Pronouncement, Early Adoption, Effect
Stock-Based Compensation
Stock compensation cumulative effect adjustments						6,000					6,000
Retained Earnings | Accountings Standards Update 2016-09, Income Tax Expense Component | New Accounting Pronouncement, Early Adoption, Effect
Stock-Based Compensation
Stock compensation cumulative effect adjustments						$ 3,000					$ 3,000

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock Units, Stock Grants, and Stock Units
Stocks granted and the weighted average fair value
Units granted (in shares)	141,811	152,651	179,291
Grant date fair value (in dollars per share)	$ 67.34	$ 64.12	$ 54.89
Number of granted awards to be settled in cash (in shares)	43,952	45,104	49,018
Performance Shares
Stocks granted and the weighted average fair value
Units granted (in shares)	166,666	151,430	166,244
Grant date fair value (in dollars per share)	$ 66.60	$ 64.97	$ 54.86

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock Units, Stock Grants, and Stock Units
Nonvested shares
Balance at the beginning of the period (in shares)	428,287
Granted (in shares)	141,811
Change in performance factor (in shares)	0
Vested (in shares)	(230,881)
Forfeited (in shares)	(3,958)
Balance at the end of the period (in shares)	335,259	428,287
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 56.69
Granted (in dollars per share)	67.34	$ 64.12	$ 54.89
Change in performance factor (in dollars per share)	0
Vested (in dollars per share)	55.07
Forfeited (in dollars per share)	62.86
Balance at the end of the period (in dollars per share)	$ 62.04	$ 56.69
Vested Awards Outstanding at December 31, 2016	174,201
Vested Awards Outstanding at December 31, 2015 (in shares)
Number of nonvested awards to be settled in cash (in shares)	112,554
Performance Shares
Nonvested shares
Balance at the beginning of the period (in shares)	305,832
Granted (in shares)	166,666
Change in performance factor (in shares)	15,573
Vested (in shares)	(171,303)
Forfeited (in shares)	(4,044)
Balance at the end of the period (in shares)	312,724	305,832
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 58.86
Granted (in dollars per share)	66.60	$ 64.97	$ 54.86
Change in performance factor (in dollars per share)	54.09
Vested (in dollars per share)	54.09
Forfeited (in dollars per share)	62.34
Balance at the end of the period (in dollars per share)	$ 65.32	$ 58.86
Vested Awards Outstanding at December 31, 2016	171,303
Vested Awards Outstanding at December 31, 2015 (in shares)

Derivative Accounting (Details)

Derivative Accounting (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Designated as Hedging Instruments
Derivative [Line Items]
Derivative liability	$ 2,000	$ 3,000
ARIZONA PUBLIC SERVICE COMPANY
Derivative [Line Items]
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change	100.00%
Commodity Contracts
Derivative [Line Items]
Derivative liability	$ 73,074	$ 167,689
Additional collateral to counterparties for energy related non-derivative instrument contracts	144,000
Commodity Contracts | Designated as Hedging Instruments
Derivative [Line Items]
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income	$ (3,000)

Derivative Accounting - Outstan

Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts MMcf in Thousands	12 Months Ended
	Dec. 31, 2016GWhMMcf
Outstanding gross notional amount of derivatives
Power | GWh	1,314
Gas | MMcf	194

Derivative Accounting - Gains a

Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Designated as Hedging Instruments
Derivative Instruments in Designated Cash Flows Hedges
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	$ 47,000	$ (615,000)	$ (372,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(3,926,000)	(5,988,000)	(21,415,000)
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	26,482,000	(108,399,000)	(66,043,000)
Revenue | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	771,000	574,000	324,000
Fuel and purchased power | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	$ 25,711,000	$ (108,973,000)	$ (66,367,000)

Derivative Accounting - Derivat

Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Commodity Contracts
Assets
Gross Recognized Derivatives	$ 54,798,000	$ 53,356,000
Amounts Offset	(35,103,000)	(26,017,000)
Net Recognized Derivatives	19,695,000	27,339,000
Other	0	672,000
Amount Reported on Balance Sheet	19,695,000	28,011,000
Liabilities
Gross Recognized Derivatives	(104,123,000)	(207,387,000)
Amounts Offset	35,103,000	44,077,000
Net Recognized Derivatives	(69,020,000)	(163,310,000)
Other	(4,054,000)	(4,379,000)
Amount Reported on Balance Sheet	(73,074,000)	(167,689,000)
Assets and Liabilities
Gross Recognized Derivatives	(49,325,000)	(154,031,000)
Amounts Offset	0	18,060,000
Net Recognized Derivatives	(49,325,000)	(135,971,000)
Other	(4,054,000)	(3,707,000)
Amount Reported on Balance Sheet	(53,379,000)	(139,678,000)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	48,094,000	37,396,000
Amounts Offset	(28,400,000)	(22,163,000)
Net Recognized Derivatives	19,694,000	15,233,000
Other	0	672,000
Amount Reported on Balance Sheet	19,694,000	15,905,000
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	6,704,000	15,960,000
Amounts Offset	(6,703,000)	(3,854,000)
Net Recognized Derivatives	1,000	12,106,000
Other	0	0
Amount Reported on Balance Sheet	1,000	12,106,000
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(50,182,000)	(113,560,000)
Amounts Offset	28,400,000	40,223,000
Net Recognized Derivatives	(21,782,000)	(73,337,000)
Other	(4,054,000)	(4,379,000)
Amount Reported on Balance Sheet	(25,836,000)	(77,716,000)
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(53,941,000)	(93,827,000)
Amounts Offset	6,703,000	3,854,000
Net Recognized Derivatives	(47,238,000)	(89,973,000)
Other	0	0
Amount Reported on Balance Sheet	(47,238,000)	(89,973,000)
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	$ (2,000,000)	$ (3,000,000)

Derivative Accounting - Credit

Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Dec. 31, 2016USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$ 104,123
Cash Collateral Posted	0
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	$ 23,914

Other Income and Other Expen103

Other Income and Other Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other income:
Interest income	$ 884	$ 493	$ 1,010
Debt return on the purchase of Four Corners units 4 & 5			8,386
Miscellaneous	17	128	212
Total other income	901	621	9,608
Other expense:
Non-operating costs	(9,235)	(11,292)	(9,657)
Investment losses — net	(1,747)	(2,080)	(9,426)
Miscellaneous	(4,355)	(4,451)	(2,663)
Total other expense	(15,337)	(17,823)	(21,746)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	261	163	689
Debt return on the purchase of Four Corners units 4 & 5	0	0	8,386
Gain on disposition of property	5,745	716	1,197
Miscellaneous	2,601	1,955	1,023
Total other income	8,607	2,834	11,295
Other expense:
Non-operating costs	(11,034)	(11,648)	(10,397)
Loss on disposition of property	(1,246)	(2,219)	(615)
Miscellaneous	(5,234)	(5,152)	(2,391)
Total other expense	$ (17,514)	$ (19,019)	$ (13,403)

Palo Verde Sale Leaseback Va104

Palo Verde Sale Leaseback Variable Interest Entities (Details) $ in Thousands	Jan. 01, 2017USD ($)	Dec. 31, 2016USD ($)TrustLease	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 1986Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts		$ 19,493	$ 18,933	$ 26,101
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		$ 19,493	18,933	26,101
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	$ 19,000	$ 26,000
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 2017 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	$ 291,000
VIE entity maximum loss exposure to noncontrolling interests during lease extension period, amount	$ 456,000

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, 2016	Dec. 31, 2015
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	$ 113,515	$ 117,385
Equity - noncontrolling interests	132,290	135,540
ARIZONA PUBLIC SERVICE COMPANY
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	113,515	117,385
Equity - noncontrolling interests	132,290	135,540
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	113,515	117,385
Equity - noncontrolling interests	$ 132,290	$ 135,540

Nuclear Decommissioning Trus106

Nuclear Decommissioning Trusts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Nuclear decommissioning trust fund assets
Fair Value	$ 779,586	$ 735,196
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities	633,410	478,813	$ 356,195
Fair value of fixed income securities, summarized by contractual maturities
Total	779,586	735,196
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	779,586	735,196
Unrealized Gains	197,911	169,053
Unrealized Losses	(4,962)	(2,760)
Net receivables for securities purchases	795
Net payables for securities purchases		(335)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	11,213	5,189	4,725
Realized losses	(10,106)	(6,225)	(4,525)
Proceeds from the sale of securities	633,410	478,813	$ 356,195
Fair value of fixed income securities, summarized by contractual maturities
Total	779,586	735,196
ARIZONA PUBLIC SERVICE COMPANY | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	353,261	314,957
Unrealized Gains	188,091	157,098
Unrealized Losses	0	(115)
Fair value of fixed income securities, summarized by contractual maturities
Total	353,261	314,957
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	425,530	420,574
Unrealized Gains	9,820	11,955
Unrealized Losses	(4,962)	(2,645)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	13,063
1 year - 5 years	119,292
5 years - 10 years	105,612
Greater than 10 years	187,563
Total	$ 425,530	$ 420,574

Changes in Accumulated Other107

Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ 4,719,457	$ 4,519,102	$ 4,340,460
Total other comprehensive income	926	23,393	9,912
Ending balance	4,935,912	4,719,457	4,519,102
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	(538)	(957)
Amounts reclassified from accumulated other comprehensive loss	2,941	4,187
Total other comprehensive income	2,403	3,230
Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	(4,509)	16,980
Amounts reclassified from accumulated other comprehensive loss	3,032	3,183
Total other comprehensive income	(1,477)	20,163
AOCI Including Portion Attributable to Noncontrolling Interest
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(44,748)	(68,141)
Ending balance	(43,822)	(44,748)	(68,141)
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	4,814,794	4,629,852	4,454,874
Total other comprehensive income	1,674	21,236	5,039
Ending balance	5,037,970	4,814,794	4,629,852
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(27,097)	(48,333)
Ending balance	(25,423)	(27,097)	$ (48,333)
ARIZONA PUBLIC SERVICE COMPANY | Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	(538)	(957)
Amounts reclassified from accumulated other comprehensive loss	2,941	4,187
Total other comprehensive income	2,403	3,230
ARIZONA PUBLIC SERVICE COMPANY | AOCI Including Portion Attributable to Noncontrolling Interest
Changes in accumulated other comprehensive income (loss) by component
OCI (loss) before reclassifications	(3,821)	14,726
Amounts reclassified from accumulated other comprehensive loss	3,092	3,280
Total other comprehensive income	$ (729)	$ 18,006

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CONDENSED FINANCIAL STATEMENTS
Operating revenues	$ 739,199	$ 1,166,922	$ 915,394	$ 677,167	$ 734,430	$ 1,199,146	$ 890,648	$ 671,219	$ 3,498,682	$ 3,495,443	$ 3,491,632
Operating expenses									2,642,698	2,640,841	2,680,390
OPERATING INCOME	122,816	451,258	231,748	50,162	109,834	445,111	231,973	67,684	855,984	854,602	811,242
Other
Total									27,704	18,013	18,652
Interest expense									205,720	194,964	200,950
Income tax benefit	27,309	141,446	65,742	1,914	22,847	139,555	67,371	7,947	236,411	237,720	220,705
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 53,246	$ 263,027	$ 121,308	$ 4,453	$ 41,117	$ 257,116	$ 122,902	$ 16,122	442,034	437,257	397,595
Other comprehensive income									926	23,393	9,912
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									442,960	460,650	407,507
Pinnacle West
CONDENSED FINANCIAL STATEMENTS
Operating revenues									370	550	642
Operating expenses									26,424	12,733	23,507
OPERATING INCOME									(26,054)	(12,183)	(22,865)
Other
Equity in earnings of subsidiaries									462,027	446,508	411,528
Other expense									(1,771)	(3,302)	(3,276)
Total									460,256	443,206	408,252
Interest expense									3,151	2,672	3,663
INCOME BEFORE INCOME TAXES									431,051	428,351	381,724
Income tax benefit									(10,983)	(8,906)	(15,871)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									442,034	437,257	397,595
Other comprehensive income									926	23,393	9,912
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ 442,960	$ 460,650	$ 407,507

SCHEDULE I - CONDENSED FINAN109

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 8,881	$ 39,488	$ 7,604	$ 9,526
Accounts receivable	250,491	274,691
Income tax receivable	3,751	589
Other current assets	45,028	37,242
Total current assets	822,219	890,516
Investments and other assets
Other assets	69,063	52,518
Total investments and other assets	848,650	799,820
Total Assets	16,004,253	15,028,258
Current liabilities
Accounts payable	264,631	297,480
Accrued taxes	138,964	138,600
Common dividends payable	72,926	69,363
Short-term borrowings	177,200	0
Current maturities of long-term debt	125,000	357,580
Other current liabilities	244,000	197,861
Total current liabilities	1,292,946	1,442,317
Deferred credits and other
Long-term debt less current maturities	4,021,785	3,462,391
Other	156,784	186,345
Total deferred credits and other	5,753,610	5,404,093
Common stock equity
Common stock	2,596,030	2,541,668
Accumulated other comprehensive loss	(43,822)	(44,748)
Retained earnings	2,255,547	2,092,803
Total shareholders’ equity	4,803,622	4,583,917
Noncontrolling interests	132,290	135,540
Total equity	4,935,912	4,719,457	4,519,102	4,340,460
Total Liabilities and Equity	16,004,253	15,028,258
Pinnacle West
Current assets
Cash and cash equivalents	41	17,432	$ 3,088	$ 5,798
Accounts receivable	81,751	93,093
Income tax receivable	0	14,895
Other current assets	340	197
Total current assets	82,132	125,617
Investments and other assets
Investments in subsidiaries	5,084,035	4,815,236
Deferred income taxes	53,805	41,065
Other assets	38,500	43,422
Total investments and other assets	5,176,340	4,899,723
Total Assets	5,258,472	5,025,340
Current liabilities
Accounts payable	5,421	5,901
Accrued taxes	12,050	6,904
Common dividends payable	72,926	69,363
Short-term borrowings	41,700	0
Current maturities of long-term debt	125,000	0
Other current liabilities	31,182	33,120
Total current liabilities	288,279	115,288
Deferred credits and other
Long-term debt less current maturities	0	125,000
Pension liabilities	21,057	21,933
Other	13,224	43,662
Total deferred credits and other	34,281	65,595
Common stock equity
Common stock	2,591,897	2,535,862
Accumulated other comprehensive loss	(43,822)	(44,748)
Retained earnings	2,255,547	2,092,803
Total shareholders’ equity	4,803,622	4,583,917
Noncontrolling interests	132,290	135,540
Total equity	4,935,912	4,719,457
Total Liabilities and Equity	$ 5,258,472	$ 5,025,340

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities
Net income	$ 58,119	$ 267,900	$ 126,182	$ 9,326	$ 45,978	$ 261,978	$ 127,507	$ 20,727	$ 461,527	$ 456,190	$ 423,696
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization									565,011	571,664	496,487
Deferred income taxes									206,870	236,819	159,023
Accounts receivable									(2,489)	(22,219)	(52,672)
Accounts payable									(66,917)	(34,266)	(353)
Net cash flow provided by operating activities									1,023,390	1,094,327	1,099,627
Cash flows from investing activities
Net cash flow used for investing activities									(1,252,078)	(1,066,233)	(922,668)
Cash flows from financing activities
Issuance of long-term debt									693,151	842,415	731,126
Short-term debt borrowings under revolving credit facility									40,000	0	0
Dividends paid on common stock									(274,229)	(260,027)	(246,671)
Repayment of long-term debt									(370,430)	(415,570)	(652,578)
Common stock equity issuance and purchases - net									(4,867)	19,373	15,288
Other									0	1	161
Net cash flow provided by (used for) financing activities									198,081	3,790	(178,881)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS									(30,607)	31,884	(1,922)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR				39,488				7,604	39,488	7,604	9,526
CASH AND CASH EQUIVALENTS AT END OF YEAR	8,881				39,488				8,881	39,488	7,604
Pinnacle West
Cash Flows from Operating Activities
Net income									442,034	437,257	397,595
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries - net									(462,027)	(446,508)	(411,528)
Depreciation and amortization									85	92	94
Deferred income taxes									(12,402)	12,967	4,406
Accounts receivable									15,823	11,336	(22,945)
Accounts payable									10,402	637	2,017
Accrued taxes and income tax receivable - net									20,041	(12,882)	(1,795)
Dividends received from subsidiaries									239,300	266,900	253,600
Other									5,514	(6,995)	18,432
Net cash flow provided by operating activities									258,770	262,804	239,876
Cash flows from investing activities
Construction work in progress									(18,457)	(3,462)	0
Investments in subsidiaries									(19,242)	(3,491)	(10,236)
Repayments of loans from subsidiaries									1,026	157	322
Advances of loans to subsidiaries									(2,092)	(1,010)	(1,450)
Net cash flow used for investing activities									(38,765)	(7,806)	(11,364)
Cash flows from financing activities
Issuance of long-term debt									0	0	125,000
Short-term debt borrowings under revolving credit facility									40,000	0	0
Commercial Paper - net									1,700	0	0
Dividends paid on common stock									(274,229)	(260,027)	(246,671)
Repayment of long-term debt									0	0	(125,000)
Common stock equity issuance and purchases - net									(4,867)	19,373	15,288
Other									0	0	161
Net cash flow provided by (used for) financing activities									(237,396)	(240,654)	(231,222)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS									(17,391)	14,344	(2,710)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR				$ 17,432				$ 3,088	17,432	3,088	5,798
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 41				$ 17,432				$ 41	$ 17,432	$ 3,088

SCHEDULE II - RESERVE FOR UN111

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) - Reserve for uncollectibles. - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Changes in reserve for uncollectibles
Balance at beginning of period	$ 3,125	$ 3,094	$ 3,203
Additions, Charged to cost and expenses	4,025	4,073	3,942
Additions, Charged to other accounts	0	0	0
Deductions	4,113	4,042	4,051
Balance at end of period	3,037	3,125	3,094
Pinnacle West
Changes in reserve for uncollectibles
Balance at beginning of period	3,125	3,094	3,203
Additions, Charged to cost and expenses	4,025	4,073	3,942
Additions, Charged to other accounts	0	0	0
Deductions	4,113	4,042	4,051
Balance at end of period	$ 3,037	$ 3,125	$ 3,094