Pinnacle West Capital (PNW) 10-Q 2 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 22, 2016
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	764,622
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		111,174,772
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
APS
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	7,286
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		71,264,947
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
OPERATING REVENUES	$ 915,394	$ 890,648	$ 1,592,561	$ 1,561,867
OPERATING EXPENSES
Fuel and purchased power	274,848	281,477	496,133	504,714
Operations and maintenance	242,279	210,965	485,474	425,909
Depreciation and amortization	123,073	122,739	242,549	243,688
Taxes other than income taxes	42,117	43,032	84,618	86,248
Other expenses	1,329	462	1,877	1,651
Total	683,646	658,675	1,310,651	1,262,210
OPERATING INCOME	231,748	231,973	281,910	299,657
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	10,369	9,345	20,885	18,569
Other income (Note 8)	197	175	314	410
Other expense (Note 8)	(2,842)	(2,609)	(6,880)	(6,895)
Total	7,724	6,911	14,319	12,084
INTEREST EXPENSE
Interest charges	52,849	48,328	103,593	96,727
Allowance for borrowed funds used during construction	(5,301)	(4,322)	(10,528)	(8,538)
Total	47,548	44,006	93,065	88,189
INCOME BEFORE INCOME TAXES	191,924	194,878	203,164	223,552
INCOME TAXES	65,742	67,371	67,656	75,318
NET INCOME	126,182	127,507	135,508	148,234
Less: Net income attributable to noncontrolling interests (Note 5)	4,874	4,605	9,747	9,210
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 121,308	$ 122,902	$ 125,761	$ 139,024
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	111,368	110,986	111,336	110,958
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	112,004	111,460	111,930	111,426
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 1.09	$ 1.11	$ 1.13	$ 1.25
Net income attributable to common shareholders - diluted (in dollars per share)	1.08	1.10	1.12	1.25
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 1.25	$ 1.19	$ 1.25	$ 1.19
APS
ELECTRIC OPERATING REVENUES	$ 909,757	$ 889,723	$ 1,586,389	$ 1,560,391
OPERATING EXPENSES
Fuel and purchased power	274,848	281,477	496,133	504,714
Operations and maintenance	233,712	208,031	472,423	417,978
Depreciation and amortization	123,033	122,716	242,479	243,642
Income taxes	70,444	71,672	76,294	83,911
Taxes other than income taxes	42,036	43,123	84,446	86,109
Total	744,073	727,019	1,371,775	1,336,354
OPERATING INCOME	165,684	162,704	214,614	224,037
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	10,369	9,345	20,885	18,569
Income taxes	1,721	2,980	3,536	5,131
Other income (Note 8)	5,747	710	6,357	1,349
Other expense (Note 8)	(4,430)	(2,449)	(9,180)	(7,803)
Total	13,407	10,586	21,598	17,246
INTEREST EXPENSE
Interest on long-term debt	48,903	44,826	95,722	90,254
Interest on short-term borrowings	1,930	1,705	4,007	2,879
Debt discount, premium and expense	1,195	1,103	2,334	2,237
Allowance for borrowed funds used during construction	(4,999)	(4,311)	(10,039)	(8,527)
Total	47,029	43,323	92,024	86,843
NET INCOME	132,062	129,967	144,188	154,440
Less: Net income attributable to noncontrolling interests (Note 5)	4,874	4,605	9,747	9,210
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 127,188	$ 125,362	$ 134,441	$ 145,230

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
NET INCOME	$ 126,182	$ 127,507	$ 135,508	$ 148,234
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	128	25	(566)	(775)
Reclassification of net realized loss, net of tax benefit	624	874	1,766	2,850
Pension and other postretirement benefits activity, net of tax benefit (expense)	(701)	(117)	(171)	466
Total other comprehensive income	51	782	1,029	2,541
COMPREHENSIVE INCOME	126,233	128,289	136,537	150,775
Less: Comprehensive income attributable to noncontrolling interests	4,874	4,605	9,747	9,210
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	121,359	123,684	126,790	141,565
APS
NET INCOME	132,062	129,967	144,188	154,440
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	128	25	(566)	(775)
Reclassification of net realized loss, net of tax benefit	624	874	1,766	2,850
Pension and other postretirement benefits activity, net of tax benefit (expense)	(642)	(74)	(31)	607
Total other comprehensive income	110	825	1,169	2,682
COMPREHENSIVE INCOME	132,172	130,792	145,357	157,122
Less: Comprehensive income attributable to noncontrolling interests	4,874	4,605	9,747	9,210
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 127,298	$ 126,187	$ 135,610	$ 147,912

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Net unrealized gain, tax expense	$ 80	$ 16	$ 626	$ 489
Reclassification of net realized loss, tax benefit	392	556	191	923
Pension and other postretirement benefits activity, tax benefit (expense)	439	74	(206)	(793)
Arizona Public Service Company
Net unrealized gain, tax expense	80	16	626	489
Reclassification of net realized loss, tax benefit	392	556	191	923
Pension and other postretirement benefits activity, tax benefit (expense)	$ 403	$ 47	$ (156)	$ (722)

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 43,040	$ 39,488
Customer and other receivables	278,900	274,691
Accrued unbilled revenues	197,571	96,240
Allowance for doubtful accounts	(2,755)	(3,125)
Materials and supplies (at average cost)	241,612	234,234
Fossil fuel (at average cost)	36,768	45,697
Income tax receivable	0	589
Assets from risk management activities (Note 6)	16,676	15,905
Regulatory assets (Note 3)	108,596	149,555
Other current assets	42,979	37,242
Total current assets	963,387	890,516
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 6)	5,464	12,106
Nuclear decommissioning trust (Note 11)	767,416	735,196
Other assets	54,401	52,518
Total investments and other assets	827,281	799,820
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	16,663,962	16,222,232
Accumulated depreciation and amortization	(5,733,857)	(5,594,094)
Net	10,930,105	10,628,138
Construction work in progress	966,146	816,307
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)	115,450	117,385
Intangible assets, net of accumulated amortization	108,751	123,975
Nuclear fuel, net of accumulated amortization	120,408	123,139
Total property, plant and equipment	12,240,860	11,808,944
DEFERRED DEBITS
Regulatory assets (Note 3)	1,190,622	1,214,146
Assets for other postretirement benefits (Note 4)	186,505	185,997
Other	129,910	128,835
Total deferred debits	1,507,037	1,528,978
TOTAL ASSETS	15,538,565	15,028,258
CURRENT LIABILITIES
Accounts payable	316,589	297,480
Accrued taxes	145,167	138,600
Accrued interest	57,927	56,305
Common dividends payable	69,484	69,363
Short-term borrowings (Note 2)	64,140	0
Current maturities of long-term debt (Note 2)	293,580	357,580
Customer deposits	79,136	73,073
Liabilities from risk management activities (Note 6)	55,338	77,716
Liabilities for asset retirements (Note 14)	15,513	28,573
Deferred fuel and purchased power regulatory liability (Note 3)	2,439	9,688
Other regulatory liabilities (Note 3)	113,733	136,078
Other current liabilities	265,498	197,861
Total current liabilities	1,478,544	1,442,317
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	3,897,835	3,462,391
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,794,741	2,723,425
Regulatory liabilities (Note 3)	1,010,821	994,152
Liabilities for asset retirements (Note 14)	446,324	415,003
Liabilities for pension benefits (Note 4)	440,919	480,998
Liabilities from risk management activities (Note 6)	52,212	89,973
Customer advances	101,568	115,609
Coal mine reclamation	203,623	201,984
Deferred investment tax credit	184,998	187,080
Unrecognized tax benefits	9,772	9,524
Other	198,025	186,345
Total deferred credits and other	5,443,003	5,404,093
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,175,500 and 111,095,402 issued at respective dates	2,549,498	2,541,668
Treasury stock at cost; 1,900 and 115,030 shares at respective dates	(130)	(5,806)
Total common stock	2,549,368	2,535,862
Retained earnings	2,079,619	2,092,803
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(37,764)	(37,593)
Derivative instruments	(5,955)	(7,155)
Total accumulated other comprehensive loss	(43,719)	(44,748)
Total shareholders’ equity	4,585,268	4,583,917
Noncontrolling interests (Note 5)	133,915	135,540
Total equity	4,719,183	4,719,457
TOTAL LIABILITIES AND EQUITY	15,538,565	15,028,258
Arizona Public Service Company
CURRENT ASSETS
Cash and cash equivalents	31,207	22,056
Customer and other receivables	278,692	274,428
Accrued unbilled revenues	197,571	96,240
Allowance for doubtful accounts	(2,755)	(3,125)
Materials and supplies (at average cost)	241,612	234,234
Fossil fuel (at average cost)	36,768	45,697
Assets from risk management activities (Note 6)	16,676	15,905
Regulatory assets (Note 3)	108,596	149,555
Other current assets	39,602	35,765
Total current assets	947,969	870,755
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 6)	5,464	12,106
Nuclear decommissioning trust (Note 11)	767,416	735,196
Other assets	34,843	34,455
Total investments and other assets	807,723	781,757
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	16,660,370	16,218,724
Accumulated depreciation and amortization	(5,730,672)	(5,590,937)
Net	10,929,698	10,627,787
Construction work in progress	948,472	812,845
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)	115,450	117,385
Intangible assets, net of accumulated amortization	108,596	123,820
Nuclear fuel, net of accumulated amortization	120,408	123,139
Total property, plant and equipment	12,222,624	11,804,976
DEFERRED DEBITS
Regulatory assets (Note 3)	1,190,622	1,214,146
Assets for other postretirement benefits (Note 4)	183,131	182,625
Other	128,348	127,923
Total deferred debits	1,502,101	1,524,694
TOTAL ASSETS	15,480,417	14,982,182
CURRENT LIABILITIES
Accounts payable	311,655	291,574
Accrued taxes	161,629	144,488
Accrued interest	57,627	56,003
Common dividends payable	69,500	69,400
Short-term borrowings (Note 2)	64,140	0
Current maturities of long-term debt (Note 2)	293,580	357,580
Customer deposits	79,136	73,073
Liabilities from risk management activities (Note 6)	55,338	77,716
Liabilities for asset retirements (Note 14)	15,513	28,573
Deferred fuel and purchased power regulatory liability (Note 3)	2,439	9,688
Other regulatory liabilities (Note 3)	113,733	136,078
Other current liabilities	239,926	180,535
Total current liabilities	1,464,216	1,424,708
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,830,006	2,764,489
Regulatory liabilities (Note 3)	1,010,821	994,152
Liabilities for asset retirements (Note 14)	446,324	415,003
Liabilities for pension benefits (Note 4)	419,545	459,065
Liabilities from risk management activities (Note 6)	52,212	89,973
Customer advances	101,568	115,609
Coal mine reclamation	203,623	201,984
Deferred investment tax credit	184,998	187,080
Unrecognized tax benefits	35,497	35,251
Other	148,993	142,683
Total deferred credits and other	5,433,587	5,405,289
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
EQUITY
Total common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	2,143,934	2,148,493
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(19,973)	(19,942)
Derivative instruments	(5,955)	(7,155)
Total shareholders’ equity	4,675,864	4,679,254
Noncontrolling interests (Note 5)	133,915	135,540
Total equity	4,809,779	4,814,794
Long-term debt less current maturities (Note 2)	3,772,835	3,337,391
Total capitalization	8,582,614	8,152,185
TOTAL LIABILITIES AND EQUITY	$ 15,480,417	$ 14,982,182

CONDENSED CONSOLIDATED BALANCE6

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common stock, par value (in dollars per share)
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	111,175,500	111,095,402
Treasury stock at cost, shares	1,900	115,030

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 135,508	$ 148,234
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	282,291	282,218
Deferred fuel and purchased power	(21,026)	11,711
Deferred fuel and purchased power amortization	13,778	11,424
Allowance for equity funds used during construction	(20,885)	(18,569)
Deferred income taxes	65,881	65,377
Deferred investment tax credit	(2,083)	(2,218)
Change in derivative instruments fair value	(237)	(225)
Changes in current assets and liabilities:
Customer and other receivables	(19,898)	(17,402)
Accrued unbilled revenues	(101,331)	(84,683)
Materials, supplies and fossil fuel	1,551	(18,311)
Income tax receivable	589	3,098
Other current assets	(5,649)	(8,728)
Accounts payable	47,621	36,634
Accrued taxes	6,567	15,199
Other current liabilities	53,912	(13,138)
Change in margin and collateral accounts — assets	(34)	(4,552)
Change in margin and collateral accounts — liabilities	18,010	26,853
Change in other long-term assets	(41,101)	(1,616)
Change in other long-term liabilities	9,011	(37,012)
Net cash flow provided by operating activities	422,475	394,294
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(731,609)	(531,035)
Contributions in aid of construction	29,127	41,010
Allowance for borrowed funds used during construction	(10,528)	(8,538)
Proceeds from nuclear decommissioning trust sales	290,594	225,779
Investment in nuclear decommissioning trust	(291,734)	(234,651)
Other	(1,307)	(2,068)
Net cash flow used for investing activities	(715,457)	(509,503)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	445,933	600,000
Repayment of long-term debt	(76,850)	(344,847)
Short-term borrowing and payments — net	64,140	10,100
Dividends paid on common stock	(135,335)	(128,241)
Common stock equity issuance - net of purchases	10,017	12,161
Distributions to noncontrolling interests	(11,372)	(28,012)
Other	1	1
Net cash flow provided by financing activities	296,534	121,162
NET INCREASE IN CASH AND CASH EQUIVALENTS	3,552	5,953
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	39,488	7,604
CASH AND CASH EQUIVALENTS AT END OF PERIOD	43,040	13,557
Cash paid during the period for:
Income taxes, net of refunds	2,503	1,834
Interest, net of amounts capitalized	89,109	84,008
Significant non-cash investing and financing activities:
Accrued capital expenditures	55,286	38,985
Dividends declared but not yet paid	69,484	65,933
Arizona Public Service Company
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	144,188	154,440
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	282,221	282,172
Deferred fuel and purchased power	(21,026)	11,711
Deferred fuel and purchased power amortization	13,778	11,424
Allowance for equity funds used during construction	(20,885)	(18,569)
Deferred income taxes	60,131	24,442
Deferred investment tax credit	(2,083)	(2,218)
Change in derivative instruments fair value	(237)	(225)
Changes in current assets and liabilities:
Customer and other receivables	(19,809)	(9,250)
Accrued unbilled revenues	(101,331)	(84,683)
Materials, supplies and fossil fuel	1,551	(18,311)
Other current assets	(3,749)	(8,193)
Accounts payable	48,593	37,656
Accrued taxes	17,141	68,382
Other current liabilities	44,711	(31,408)
Change in margin and collateral accounts — assets	(34)	(4,552)
Change in margin and collateral accounts — liabilities	18,010	26,853
Change in other long-term assets	(38,780)	(3,564)
Change in other long-term liabilities	3,979	(30,337)
Net cash flow provided by operating activities	426,369	405,770
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(717,729)	(530,850)
Contributions in aid of construction	29,127	41,010
Allowance for borrowed funds used during construction	(10,039)	(8,527)
Proceeds from nuclear decommissioning trust sales	290,594	225,779
Investment in nuclear decommissioning trust	(291,734)	(234,651)
Other	(388)	(614)
Net cash flow used for investing activities	(700,169)	(507,853)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	445,933	600,000
Repayment of long-term debt	(76,850)	(344,847)
Short-term borrowing and payments — net	64,140	10,100
Dividends paid on common stock	(138,900)	(131,700)
Distributions to noncontrolling interests	(11,372)	(28,012)
Net cash flow provided by financing activities	282,951	105,541
NET INCREASE IN CASH AND CASH EQUIVALENTS	9,151	3,458
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	22,056	4,515
CASH AND CASH EQUIVALENTS AT END OF PERIOD	31,207	7,973
Cash paid during the period for:
Income taxes, net of refunds	8,772	184
Interest, net of amounts capitalized	88,066	82,651
Significant non-cash investing and financing activities:
Accrued capital expenditures	55,286	38,985
Dividends declared but not yet paid	$ 69,500	$ 65,900

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($) $ in Thousands		Total	Common Stock	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	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 (in shares) at Dec. 31, 2014			110,649,762	78,400					71,264,947
Balance at end of period 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
Increase (Decrease) in Shareholders' Equity
Net income		148,234			139,024		9,210	154,440			145,230		9,210
Other comprehensive income		2,541				2,541		2,682				2,682
Dividends on common stock		(131,833)			(131,833)			(131,800)			(131,800)
Other								2			2
Issuance of common stock (in shares)			215,268
Issuance of common stock		13,975	$ 13,975
Purchase of treasury stock (in shares)	[1]			(93,280)
Purchase of treasury stock	[1]	(6,096)		$ (6,096)
Reissuance of treasury stock for stock-based compensation and other (in shares)				118,121
Reissuance of treasury stock for stock-based compensation and other		7,732		$ 7,732	0
Capital activities by noncontrolling interests		(28,012)					(28,012)	(28,012)					(28,012)
Ending balance (in shares) at Jun. 30, 2015			110,865,030	53,559					71,264,947
Balance at beginning of period at Jun. 30, 2015		4,525,643	$ 2,526,945	$ (1,765)	1,933,256	(65,600)	132,807	4,627,164	$ 178,162	2,379,696	1,982,150	(45,651)	132,807
Increase (Decrease) in Shareholders' Equity
Net income		127,507						129,967
Other comprehensive income		782						825
Ending balance (in shares) at Jun. 30, 2015			110,865,030	53,559					71,264,947
Balance at beginning of period at Jun. 30, 2015		$ 4,525,643	$ 2,526,945	$ (1,765)	1,933,256	(65,600)	132,807	4,627,164	$ 178,162	2,379,696	1,982,150	(45,651)	132,807
Beginning balance (in shares) at Dec. 31, 2015		111,095,402	111,095,402	115,030					71,264,947
Balance at end of period 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
Increase (Decrease) in Shareholders' Equity
Net income		135,508			125,761		9,747	144,188			134,441		9,747
Other comprehensive income		1,029				1,029		1,169				1,169
Dividends on common stock		(138,947)			(138,947)			(139,000)			(139,000)
Issuance of common stock (in shares)			80,098
Issuance of common stock		7,830	$ 7,830
Purchase of treasury stock (in shares)	[1]			(71,962)
Purchase of treasury stock	[1]	(4,880)		$ (4,880)
Reissuance of treasury stock for stock-based compensation and other (in shares)				185,092
Reissuance of treasury stock for stock-based compensation and other		10,558		$ 10,556	2		0
Capital activities by noncontrolling interests		$ (11,372)					(11,372)	(11,372)					(11,372)
Ending balance (in shares) at Jun. 30, 2016		111,175,500	111,175,500	1,900					71,264,947
Balance at beginning of period at Jun. 30, 2016		$ 4,719,183	$ 2,549,498	$ (130)	2,079,619	(43,719)	133,915	4,809,779	$ 178,162	2,379,696	2,143,934	(25,928)	133,915
Increase (Decrease) in Shareholders' Equity
Net income		126,182						132,062
Other comprehensive income		$ 51						110
Ending balance (in shares) at Jun. 30, 2016		111,175,500	111,175,500	1,900					71,264,947
Balance at beginning of period at Jun. 30, 2016		$ 4,719,183	$ 2,549,498	$ (130)	$ 2,079,619	$ (43,719)	$ 133,915	$ 4,809,779	$ 178,162	$ 2,379,696	$ 2,143,934	$ (25,928)	$ 133,915
[1]	Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

Consolidation and Nature of Ope

Consolidation and Nature of Operations	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Consolidation and Nature of Operations	Consolidation and Nature of Operations The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado"). Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 5 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors. Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2015 Form 10-K. Supplemental Cash Flow Information The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Six Months Ended 2016 2015 Cash paid during the period for: Income taxes, net of refunds $ 2,503 $ 1,834 Interest, net of amounts capitalized 89,109 84,008 Significant non-cash investing and financing activities: Accrued capital expenditures $ 55,286 $ 38,985 Dividends accrued but not yet paid 69,484 65,933

Long-Term Debt and Liquidity Ma

Long-Term Debt and Liquidity Matters	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt and Liquidity Matters	Long-Term Debt and Liquidity Matters Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes. Pinnacle West 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 June 30, 2016 , Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings. APS During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million . 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 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. 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. At June 30, 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 June 30, 2016 , APS had $64 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 7 for a discussion of APS’s separate outstanding letters of credit. 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 presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of June 30, 2016 As of December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 125,000 $ 125,000 $ 125,000 $ 125,000 APS 4,066,415 4,658,591 3,694,971 3,981,367 Total $ 4,191,415 $ 4,783,591 $ 3,819,971 $ 4,106,367 Debt Provisions 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 June 30, 2016 , APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.7 billion , and total capitalization was approximately $8.9 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.

Regulatory Matters

Regulatory Matters	6 Months Ended
	Jun. 30, 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 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 44.2 % 5.13 % Common stock equity 55.8 % 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 kilowatt-hour (“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 the Four Corners Power Plant (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 Power Supply Adjustor (“PSA”), the Lost Fixed Cost Recovery Mechanism (“LFCR”), the Transmission Cost Adjustor (“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 administrative law judge set a procedural schedule for the rate proceedings. The ACC staff and interveners will begin filing their direct testimony on December 21, and the hearing will commence on March 22, 2017. The Commission staff supports completing the case within 12 months. APS cannot predict the outcome of its request. Prior Rate Case Filing On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million . APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6% . On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (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 for fuel and purchased power costs ("Base Fuel Rate") from $0.03757 to $0.03207 per kilowatt hour ("kWh"); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff ("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 the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below); • Implementation of a Lost Fixed Cost Recovery ("LFCR") rate mechanism to support energy efficiency and distributed renewable generation; • Modifications to the Environmental Improvement Surcharge ("EIS") 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 Power Supply Adjustor ("PSA"), including the elimination of the 9 0/10 sharing provision; • A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge ("DSMAC") to recoup capital expenditures not required under the terms of APS’s 2009 retail rate case settlement agreement (the "2009 Settlement Agreement"); • Modification of the Transmission Cost Adjustor ("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 accordance with the ACC's decision on APS's 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 megawatts ("MW") of APS-owned grid scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of grid scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program, called the "Solar Partner Program," is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case. On July 1, 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. 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. Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules. On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rulemaking has not been initiated and there has been no additional action on the draft to date. 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. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2016 and 2015 (dollars in thousands): Six Months Ended 2016 2015 Beginning balance $ (9,688 ) $ 6,925 Deferred fuel and purchased power costs — current period 21,027 (11,710 ) Amounts charged to customers (13,778 ) (11,424 ) Ending balance $ (2,439 ) $ (16,209 ) The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year. This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh. On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters . In July 2008, the United States Federal Energy Regulatory Commission ("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 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 such as APS to make changes to their protocols in the future. Lost Fixed Cost Recovery Mechanism . The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units. APS files for a LFCR adjustment every January. APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million , effective March 1, 2014. The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million , which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. In April 2016, the ACC approved the 2016 annual LFCR to be effective in April 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the one month delay in implementation will not have an adverse effect on APS. Net Metering On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS's net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electric grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR. In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electric grid. The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. APS cannot predict the outcome of this proceeding. In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015 and February 23, 2016, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS actively participated in the related hearings held in March 2016. APS has also intervened in the upcoming Tucson Electric Power Company rate case. On June 24, 2016, APS filed testimony in the Tucson Electric Power Company rate case in support of the Tucson Electric Power Company proposed rate design changes. The outcomes of these proceedings will not directly impact our financial position. Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB") In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case. The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision. On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument was conducted on March 22, 2016. If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter. System Benefits Charge The 2012 Settlement Agreement provides 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. Four Corners On December 30, 2013, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general 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 $67 million as of June 30, 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 has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter will be resolved. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect this order in the second quarter of 2016. On July 29, 2016, APS filed for a rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter. Cholla On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("EPA") approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and is seeking recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ( $119 million as of June 30, 2016), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted. Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in thousands): Amortization Through June 30, 2016 December 31, 2015 Current Non-Current Current Non-Current Pension (a) $ — $ 617,283 $ — $ 619,223 Retired power plant costs 2033 9,913 122,554 9,913 127,518 Income taxes — allowance for funds used during construction ("AFUDC") equity 2046 5,419 137,611 5,495 133,712 Deferred fuel and purchased power — mark-to-market (Note 6) 2019 30,986 40,573 71,852 69,697 Four Corners cost deferral 2024 6,689 60,238 6,689 63,582 Income taxes — investment tax credit basis adjustment 2045 1,851 47,826 1,766 48,462 Lost fixed cost recovery (b) 2017 49,852 — 45,507 — Palo Verde VIEs (Note 5) 2046 — 18,465 — 18,143 Deferred compensation 2036 — 35,701 — 34,751 Deferred property taxes (c) — 62,726 — 50,453 Loss on reacquired debt 2034 1,592 16,919 1,515 16,375 Tax expense of Medicare subsidy 2024 1,512 11,647 1,520 12,163 Transmission vegetation management 2016 — — 4,543 — Mead-Phoenix transmission line CIAC 2050 332 10,874 332 11,040 Transmission cost adjustor (b) 2018 — 2,814 — 2,942 Coal reclamation 2026 418 5,391 418 6,085 Other Various 32 — 5 — Total regulatory assets (d) $ 108,596 $ 1,190,622 $ 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 Other Comprehensive Income ("OCI") and result in lower future revenues. See Note 4 for further discussion. (b) See "Cost Recovery Mechanisms" discussion above. (c) Per the provision of the 2012 Settlement Agreement. (d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters." The detail of regulatory liabilities is as follows (dollars in thousands): Amortization Through June 30, 2016 December 31, 2015 Current Non-Current Current Non-Current Asset retirement obligations 2057 $ — $ 299,713 $ — $ 277,554 Removal costs (a) 26,373 245,777 39,746 240,367 Other postretirement benefits (d) 33,294 155,279 34,100 179,521 Income taxes — deferred investment tax credit 2045 3,774 95,877 3,604 97,175 Income taxes — change in rates 2046 1,771 71,257 1,113 72,454 Spent nuclear fuel 2047 31 71,342 3,051 67,437 Renewable energy standard (b) 2017 35,882 2,182 43,773 4,365 Demand side management (b) 2017 4,957 21,864 6,079 19,115 Sundance maintenance 2030 — 14,483 — 13,678 Deferred fuel and purchased power (b) (c) 2017 2,439 — 9,688 — Deferred gains on utility property 2019 2,062 9,535 2,062 6,001 Transmission cost adjustor (b) 2017 5,545 — — — Four Corners coal reclamation 2031 — 15,969 — 8,920 Other Various 44 7,543 2,550 7,565 Total regulatory liabilities $ 116,172 $ 1,010,821 $ 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. (b) See "Cost Recovery Mechanisms" discussion above. (c) Subject to a carrying charge. (d) See Note 4 .

Retirement Plans and Other Post

Retirement Plans and Other Postretirement Benefits	6 Months Ended
	Jun. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Retirement Plans and Other Postretirement Benefits	Retirement Plans and Other Postretirement Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement dates. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of the plan changes, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $140 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement. Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012. We completed amortizing these costs as of June 30, 2015. We amortized approximately $2 million and $4 million for the three and six months ended June 30, 2015, respectively. 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 or amortized to the regulatory asset) (dollars in thousands): Pension Benefits Other Benefits Three Months Ended Six Months Ended Three Months Ended Six Months Ended 2016 2015 2016 2015 2016 2015 2016 2015 Service cost — benefits earned during the period $ 12,630 $ 13,990 $ 26,896 $ 29,814 $ 3,560 $ 4,068 $ 7,497 $ 8,413 Interest cost on benefit obligation 32,878 30,802 65,823 61,992 7,519 6,867 14,860 14,051 Expected return on plan assets (43,161 ) (44,467 ) (86,953 ) (89,616 ) (9,125 ) (9,281 ) (18,247 ) (18,428 ) Amortization of: Prior service cost 132 149 263 297 (9,471 ) (9,492 ) (18,942 ) (18,984 ) Net actuarial loss 10,627 7,767 20,358 15,528 1,349 880 2,295 2,441 Net periodic benefit cost $ 13,106 $ 8,241 $ 26,387 $ 18,015 $ (6,168 ) $ (6,958 ) $ (12,537 ) $ (12,507 ) Portion of cost charged to expense $ 6,433 $ 5,232 $ 12,951 $ 11,219 $ (3,027 ) $ (2,482 ) $ (6,153 ) $ (4,271 ) Contributions We made voluntary contributions of $80 million to our pension plan year-to-date in 2016. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period. We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

Palo Verde Sale Leaseback Varia

Palo Verde Sale Leaseback Variable Interest Entities	6 Months Ended
	Jun. 30, 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 2016 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years , or return the assets to the lessors. The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs. As a result of consolidation, we eliminate lease accounting and instead recognize depreciation, resulting in an increase in net income for the three and six months ended June 30, 2016 of $5 million and $10 million respectively, and for the three and six months ended June 30, 2015 of $5 million and $9 million respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation. Our Condensed Consolidated Balance Sheets at June 30, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands): June 30, 2016 December 31, 2015 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 115,450 $ 117,385 Equity — Noncontrolling interests 133,915 135,540 Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the United States Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $288 million beginning in 2016, and up to $456 million over the lease terms. For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

Derivative Accounting

Derivative Accounting	6 Months Ended
	Jun. 30, 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 Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. See Note 10 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 June 30, 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 2,291 GWh Gas 220 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 three and six months ended June 30, 2016 and 2015 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2016 2015 2016 2015 Gain (loss) recognized in OCI on derivative instruments (effective portion) OCI — derivative instruments $ 208 $ 41 $ 60 $ (286 ) Loss reclassified from accumulated OCI into income (effective portion realized) (a) Fuel and purchased power (b) (1,016 ) (1,430 ) (1,957 ) (3,773 ) (a) During the three and six months ended June 30, 2016 and 2015 , we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals. During the next twelve months, we estimate that a net loss of $4 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended June 30, Commodity Contracts 2016 2015 2016 2015 Net gain (loss) recognized in income Operating revenues $ 585 $ (66 ) $ 483 $ (114 ) Net gain (loss) recognized in income Fuel and purchased power (a) 60,894 10,613 29,958 (34,190 ) Total $ 61,479 $ 10,547 $ 30,441 $ (34,304 ) (a) Amounts are before the effect of PSA deferrals. Derivative Instruments in the Condensed Consolidated Balance Sheets Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets. We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below. The significant majority of our derivative instruments are not currently designated as hedging instruments. The Condensed Consolidated Balance Sheets as of June 30, 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 June 30, 2016 and December 31, 2015 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of June 30, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 30,393 $ (14,424 ) $ 15,969 $ 707 $ 16,676 Investments and other assets 14,260 (8,796 ) 5,464 — 5,464 Total assets 44,653 (23,220 ) 21,433 707 22,140 Current liabilities (65,432 ) 14,424 (51,008 ) (4,330 ) (55,338 ) Deferred credits and other (61,008 ) 8,796 (52,212 ) — (52,212 ) Total liabilities (126,440 ) 23,220 (103,220 ) (4,330 ) (107,550 ) Total $ (81,787 ) $ — $ (81,787 ) $ (3,623 ) $ (85,410 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $0 . (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 $4,330 , and cash margin provided to counterparties of $707 . 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. We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 73% of Pinnacle West’s $22 million of risk management assets as of June 30, 2016 . This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2016 (dollars in thousands): June 30, 2016 Aggregate fair value of derivative instruments in a net liability position $ 126,440 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 76,949 (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 $145 million if our debt credit ratings were to fall below investment grade.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 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 United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million . Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016. 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 will be submitted to the DOE in the fourth quarter of 2016, and payment 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 retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million , which is provided by American Nuclear Insurers ("ANI"). The remaining balance of $13 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million , subject to an annual limit of $18.9 million per incident, to be periodically adjusted for inflation. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111.1 million , with a maximum annual retrospective premium assessment of approximately $16.6 million . The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion , a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited ("NEIL"). APS is subject to retrospective premium assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $23.8 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. Contractual Obligations There have been no material changes, as of June 30, 2016, outside the normal course of business in contractual obligations from the information provided in our 2015 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations. Superfund-Related Matters The Comprehensive Environmental Response Compensation and Liability Act ("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 potentially responsible parties ("PRPs"). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million . We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. On August 6, 2013, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. 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 kilovolt ("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, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs"). These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS. Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners and the Navajo Generating Station ("Navajo Plant"). EPA and ADEQ will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. EPA is currently in the process of considering 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. Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $400 million . In addition, APS and El Paso Electric Company ("El Paso") entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4C Acquisition, LLC ("4CA"), a wholly-owned subsidiary of Pinnacle West, purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC provided notice of its intent to exercise the option. 4CA is negotiating a definitive purchase agreement with NTEC for the purchase by NTEC of the 7% interest. The cost of the pollution controls related to the 7% interest is approximately $45 million , which will be assumed by the ultimate owner of the 7% interest. Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million . In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process. Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $100 million (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015), is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On October 16, 2015, ADEQ issued the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. 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. The proposed rule was published in the Federal Register on July 19, 2016 and is subject to a 45 -day public comment period. APS anticipates that EPA will issue the final rule by the end of 2016. Once EPA’s action is finalized, there may be judicial petitions for review of EPA’s final action filed 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. Mercury and Air Toxic Standards ("MATS"). In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $8 million for Cholla (excludes costs related to Cholla Unit 2, which was closed on October 1, 2015). No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. Salt River Project Agricultural Improvement and Power District ("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 . Litigation concerning the rules has occurred and further litigation concerning the propriety of EPA's related findings is expected. 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 the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million , and its share of incremental costs for Cholla is approximately $40 million . The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million . Additionally, the CCR rule requires on-going 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. Because the initial monitoring at these plants is not yet complete, at the present time expenditures related to potential corrective actions cannot be reasonably estimated. 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 three 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 electric generating units ("EGUs"). EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO 2 performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal. With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO 2 emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two -year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below. 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 reports that it is continuing to assess its options while completing outreach and soliciting feedback from stakeholders. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation. The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such 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 on-going, and additional information or considerations may arise that change our expectations. Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard 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 December 21, 2015, several environmental groups filed a notice of intent to sue with Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies under the Endangered Species Act (“ESA”) alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the United States Department of the Interior's ("DOI's") review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the National Environmental Policy Act (“NEPA”) and culminated in the issuance of a Record of Decision justifying the agency action extending the life of the plant and the adjacent mine. On April 20, 2016, the same environmental groups followed through with their notice of intent to sue by filing a lawsuit against OSM and other DOI 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. Expanding upon the December 2015 ESA notice, 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. We filed a motion to intervene in the proceedings on July 15, 2016. 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, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million . APS's share of this settlement payment, together with its share of the partial payment described above is approximately $0.8 million . Financial Assurances In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of June 30, 2016 , standby letters of credit totaled $79 million and will expire in 2016 and 2017. As of June 30, 2016 , surety bonds expiring through 2019 totaled $150 million . The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely. Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2016 . Effective July 6, 2016, Pinnacle West has issued two parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners. Peabody Bankruptcy On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri. Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona. APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement. On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleges that the Buyers have breached the Agreement. Peabody requests substantial, but unspecified, monetary dama

Other Income and Other Expense

Other Income and Other Expense	6 Months Ended
	Jun. 30, 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 the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended 2016 2015 2016 2015 Other income: Interest income $ 184 $ 184 $ 302 $ 294 Investment gains — net 13 — 13 — Miscellaneous — (9 ) (1 ) 116 Total other income $ 197 $ 175 $ 314 $ 410 Other expense: Non-operating costs $ (2,085 ) $ (1,952 ) $ (4,133 ) $ (4,200 ) Investment losses — net (539 ) (650 ) (1,058 ) (1,145 ) Miscellaneous (218 ) (7 ) (1,689 ) (1,550 ) Total other expense $ (2,842 ) $ (2,609 ) $ (6,880 ) $ (6,895 )
Arizona Public Service Company
Component of Other Income and Other Expense Nonoperating [Line Items]
Other Income and Other Expense	The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended 2016 2015 2016 2015 Other income: Interest income $ 109 $ 6 $ 181 $ 73 Gain on disposition of property 4,989 478 5,321 685 Miscellaneous 649 226 855 591 Total other income $ 5,747 $ 710 $ 6,357 $ 1,349 Other expense: Non-operating costs (a) $ (2,719 ) $ (1,878 ) $ (4,685 ) $ (4,395 ) Loss on disposition of property (657 ) (251 ) (1,083 ) (894 ) Miscellaneous (1,054 ) (320 ) (3,412 ) (2,514 ) Total other expense $ (4,430 ) $ (2,449 ) $ (9,180 ) $ (7,803 ) (a) As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 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 the three and six months ended June 30, 2016 and 2015 (in thousands, except per share amounts): Three Months Ended Six Months Ended 2016 2015 2016 2015 Net income attributable to common shareholders $ 121,308 $ 122,902 $ 125,761 $ 139,024 Weighted average common shares outstanding — basic 111,368 110,986 111,336 110,958 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 636 474 594 468 Weighted average common shares outstanding — diluted 112,004 111,460 111,930 111,426 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 1.09 $ 1.11 $ 1.13 $ 1.25 Net income attributable to common shareholders — diluted $ 1.08 $ 1.10 $ 1.12 $ 1.25

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 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 instruments valued using NAV, as a practical expedient, to no longer be classified within the fair value hierarchy. As such, instruments valued using NAV, as a practical expedient, 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 and plan assets held in our retirement and other benefit plans. See Note 7 in the 2015 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets. Risk Management Activities — Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk. Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs. Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization. Investments Held in our Nuclear Decommissioning Trust The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued 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 11 for additional discussion about our nuclear decommissioning trust. Fair Value Tables The following table presents the fair value at June 30, 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 June 30, 2016 Assets Cash equivalents $ 9,857 $ — $ — $ — $ 9,857 Risk management activities — derivative instruments: Commodity contracts — 26,509 18,118 (22,487 ) (b) 22,140 Nuclear decommissioning trust: U.S. commingled equity funds — — — 328,037 (c) 328,037 Fixed income securities: Cash and cash equivalent funds 17,892 — — (13,139 ) (d) 4,753 U.S. Treasury 117,448 — — — 117,448 Corporate debt — 106,399 — — 106,399 Mortgage-backed securities — 112,771 — — 112,771 Municipal bonds — 73,847 — — 73,847 Other — 24,161 — — 24,161 Subtotal nuclear decommissioning trust 135,340 317,178 — 314,898 767,416 Total $ 145,197 $ 343,687 $ 18,118 $ 292,411 $ 799,413 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (75,916 ) $ (50,498 ) $ 18,864 (b) $ (107,550 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 6 . (c) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy. (d) 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 6 . (c) Valued using NAV as a practical expedient, and therefore 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 significant unobservable inputs at June 30, 2016 and 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 June 30, 2016 and December 31, 2015 : June 30, 2016 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 16,151 $ 39,548 Discounted cash flows Electricity forward price (per MWh) $21.68 - $43.50 $ 31.26 Option Contracts (b) — 2,993 Option model Electricity forward price (per MWh) $35.46 - $49.65 $ 43.12 Electricity price volatilities 56% - 140% 94 % Natural gas price volatilities 38% - 80% 49 % Natural Gas: Forward Contracts (a) 1,967 7,957 Discounted cash flows Natural gas forward price (per MMBtu) $2.67 - $3.37 $ 2.91 Total $ 18,118 $ 50,498 (a) Includes swaps and physical and financial contracts. (b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. December 31, 2015 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range 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 three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended Commodity Contracts 2016 2015 2016 2015 Net derivative balance at beginning of period $ (39,507 ) $ (48,814 ) $ (32,979 ) $ (41,386 ) Total net gains (losses) realized/unrealized: Included in OCI 104 25 104 (237 ) Deferred as a regulatory asset or liability 1,499 5,813 (7,604 ) (4,933 ) Settlements 4,502 4,541 6,267 4,852 Transfers into Level 3 from Level 2 120 (3,566 ) 382 (3,968 ) Transfers from Level 3 into Level 2 902 (944 ) 1,450 2,727 Net derivative balance at end of period $ (32,380 ) $ (42,945 ) $ (32,380 ) $ (42,945 ) 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 2 for our long-term debt fair values.

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts	6 Months Ended
	Jun. 30, 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 Condensed Consolidated Balance Sheets. See Note 10 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 June 30, 2016 and December 31, 2015 (dollars in thousands): Fair Value Total Unrealized Gains Total Unrealized Losses June 30, 2016 Equity securities $ 328,037 $ 165,926 $ (7 ) Fixed income securities 452,518 22,953 (345 ) Net payables (a) (13,139 ) — — Total $ 767,416 $ 188,879 $ (352 ) 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 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): Three Months Ended Six Months Ended 2016 2015 2016 2015 Realized gains $ 2,282 $ 1,260 $ 4,720 $ 2,455 Realized losses (1,350 ) (1,525 ) (3,136 ) (2,050 ) Proceeds from the sale of securities (a) 148,785 110,498 290,594 225,779 (a) Proceeds are reinvested in the trust. The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2016 is as follows (dollars in thousands): Fair Value Less than one year $ 13,046 1 year – 5 years 133,548 5 years – 10 years 103,874 Greater than 10 years 202,050 Total $ 452,518

New Accounting Standards

New Accounting Standards	6 Months Ended
	Jun. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	New Accounting Standards 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 has been 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 guidance may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We are currently evaluating the new standard, and related amendments, and the impacts it may have on our financial statements. 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 guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. 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 guidance 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 guidance 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. In March 2016, new stock compensation accounting guidance was issued that modifies the accounting for employee share-based payments. The new guidance will require all tax benefits and deficiencies arising from share-based payments to be recognized in net income, modifies the tax withholding threshold for awards to qualify for equity classification, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. The new guidance is effective for us on January 1, 2017, with early application permitted. Certain aspects of the guidance must be adopted using a prospective approach and other aspects will be adopted using a retrospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. In June 2016, new accounting guidance was issued that amends the measurement of credit losses on certain financial instruments. The new guidance 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.

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Loss	6 Months Ended
	Jun. 30, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Changes in Accumulated Other Comprehensive Loss	Changes in Accumulated Other Comprehensive Loss The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 Balance at beginning of period $ (43,770 ) $ (66,382 ) $ (44,748 ) $ (68,141 ) Derivative Instruments OCI (loss) before reclassifications 128 25 (566 ) (775 ) Amounts reclassified from accumulated other comprehensive loss (a) 624 874 1,766 2,850 Net current period OCI (loss) 752 899 1,200 2,075 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (1,585 ) (969 ) (1,585 ) (969 ) Amounts reclassified from accumulated other comprehensive loss (b) 884 852 1,414 1,435 Net current period OCI (loss) (701 ) (117 ) (171 ) 466 Balance at end of period $ (43,719 ) $ (65,600 ) $ (43,719 ) $ (65,600 ) (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 6 . (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4 .
Arizona Public Service Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Changes in Accumulated Other Comprehensive Loss	The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 Balance at beginning of period $ (26,038 ) $ (46,476 ) $ (27,097 ) $ (48,333 ) Derivative Instruments OCI (loss) before reclassifications 128 25 (566 ) (775 ) Amounts reclassified from accumulated other comprehensive loss (a) 624 874 1,766 2,850 Net current period OCI (loss) 752 899 1,200 2,075 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (1,521 ) (927 ) (1,521 ) (927 ) Amounts reclassified from accumulated other comprehensive loss (b) 879 853 1,490 1,534 Net current period OCI (loss) (642 ) (74 ) (31 ) 607 Balance at end of period $ (25,928 ) $ (45,651 ) $ (25,928 ) $ (45,651 ) (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 6 . (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4 .

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations In 2016, APS recognized an asset retirement obligation (“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 . The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2016 (dollars in thousands): Asset retirement obligations at January 1, 2016 $ 443,576 Changes attributable to: Accretion expense 13,112 Settlements (5,224 ) Newly incurred liabilities 10,373 Asset retirement obligations at June 30, 2016 $ 461,837 Decommissioning activities for Four Corners Units 1-3 began in January 2014. Decommissioning activities for Cholla Ash Ponds began in January 2015. Thus, $16 million of the total asset retirement obligation of $462 million at June 30, 2016, is 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

New Accounting Standards (Polic

New Accounting Standards (Policies)	6 Months Ended
	Jun. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	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 has been 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 guidance may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We are currently evaluating the new standard, and related amendments, and the impacts it may have on our financial statements. 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 guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. 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 guidance 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 guidance 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. In March 2016, new stock compensation accounting guidance was issued that modifies the accounting for employee share-based payments. The new guidance will require all tax benefits and deficiencies arising from share-based payments to be recognized in net income, modifies the tax withholding threshold for awards to qualify for equity classification, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. The new guidance is effective for us on January 1, 2017, with early application permitted. Certain aspects of the guidance must be adopted using a prospective approach and other aspects will be adopted using a retrospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. In June 2016, new accounting guidance was issued that amends the measurement of credit losses on certain financial instruments. The new guidance 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.

Consolidation and Nature of O24

Consolidation and Nature of Operations (Tables)	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of supplemental cash flow information	The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Six Months Ended 2016 2015 Cash paid during the period for: Income taxes, net of refunds $ 2,503 $ 1,834 Interest, net of amounts capitalized 89,109 84,008 Significant non-cash investing and financing activities: Accrued capital expenditures $ 55,286 $ 38,985 Dividends accrued but not yet paid 69,484 65,933

Long-Term Debt and Liquidity 25

Long-Term Debt and Liquidity Matters (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Schedule of estimated fair value of long-term debt, including current maturities	The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of June 30, 2016 As of December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 125,000 $ 125,000 $ 125,000 $ 125,000 APS 4,066,415 4,658,591 3,694,971 3,981,367 Total $ 4,191,415 $ 4,783,591 $ 3,819,971 $ 4,106,367

Regulatory Matters (Tables)

Regulatory Matters (Tables)	6 Months Ended
	Jun. 30, 2016
Regulated Operations [Abstract]
Proposed capital structure and cost of capital	the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 44.2 % 5.13 % Common stock equity 55.8 % 10.50 % Weighted-average cost of capital 8.13 %
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): Six Months Ended 2016 2015 Beginning balance $ (9,688 ) $ 6,925 Deferred fuel and purchased power costs — current period 21,027 (11,710 ) Amounts charged to customers (13,778 ) (11,424 ) Ending balance $ (2,439 ) $ (16,209 )
Schedule of regulatory assets	The detail of regulatory assets is as follows (dollars in thousands): Amortization Through June 30, 2016 December 31, 2015 Current Non-Current Current Non-Current Pension (a) $ — $ 617,283 $ — $ 619,223 Retired power plant costs 2033 9,913 122,554 9,913 127,518 Income taxes — allowance for funds used during construction ("AFUDC") equity 2046 5,419 137,611 5,495 133,712 Deferred fuel and purchased power — mark-to-market (Note 6) 2019 30,986 40,573 71,852 69,697 Four Corners cost deferral 2024 6,689 60,238 6,689 63,582 Income taxes — investment tax credit basis adjustment 2045 1,851 47,826 1,766 48,462 Lost fixed cost recovery (b) 2017 49,852 — 45,507 — Palo Verde VIEs (Note 5) 2046 — 18,465 — 18,143 Deferred compensation 2036 — 35,701 — 34,751 Deferred property taxes (c) — 62,726 — 50,453 Loss on reacquired debt 2034 1,592 16,919 1,515 16,375 Tax expense of Medicare subsidy 2024 1,512 11,647 1,520 12,163 Transmission vegetation management 2016 — — 4,543 — Mead-Phoenix transmission line CIAC 2050 332 10,874 332 11,040 Transmission cost adjustor (b) 2018 — 2,814 — 2,942 Coal reclamation 2026 418 5,391 418 6,085 Other Various 32 — 5 — Total regulatory assets (d) $ 108,596 $ 1,190,622 $ 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 Other Comprehensive Income ("OCI") and result in lower future revenues. See Note 4 for further discussion. (b) See "Cost Recovery Mechanisms" discussion above. (c) Per the provision of the 2012 Settlement Agreement. (d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."
Schedule of regulatory liabilities	The detail of regulatory liabilities is as follows (dollars in thousands): Amortization Through June 30, 2016 December 31, 2015 Current Non-Current Current Non-Current Asset retirement obligations 2057 $ — $ 299,713 $ — $ 277,554 Removal costs (a) 26,373 245,777 39,746 240,367 Other postretirement benefits (d) 33,294 155,279 34,100 179,521 Income taxes — deferred investment tax credit 2045 3,774 95,877 3,604 97,175 Income taxes — change in rates 2046 1,771 71,257 1,113 72,454 Spent nuclear fuel 2047 31 71,342 3,051 67,437 Renewable energy standard (b) 2017 35,882 2,182 43,773 4,365 Demand side management (b) 2017 4,957 21,864 6,079 19,115 Sundance maintenance 2030 — 14,483 — 13,678 Deferred fuel and purchased power (b) (c) 2017 2,439 — 9,688 — Deferred gains on utility property 2019 2,062 9,535 2,062 6,001 Transmission cost adjustor (b) 2017 5,545 — — — Four Corners coal reclamation 2031 — 15,969 — 8,920 Other Various 44 7,543 2,550 7,565 Total regulatory liabilities $ 116,172 $ 1,010,821 $ 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. (b) See "Cost Recovery Mechanisms" discussion above. (c) Subject to a carrying charge. (d) See Note 4 .

Retirement Plans and Other Po27

Retirement Plans and Other Postretirement Benefits (Tables)	6 Months Ended
	Jun. 30, 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 or amortized to the regulatory asset) (dollars in thousands): Pension Benefits Other Benefits Three Months Ended Six Months Ended Three Months Ended Six Months Ended 2016 2015 2016 2015 2016 2015 2016 2015 Service cost — benefits earned during the period $ 12,630 $ 13,990 $ 26,896 $ 29,814 $ 3,560 $ 4,068 $ 7,497 $ 8,413 Interest cost on benefit obligation 32,878 30,802 65,823 61,992 7,519 6,867 14,860 14,051 Expected return on plan assets (43,161 ) (44,467 ) (86,953 ) (89,616 ) (9,125 ) (9,281 ) (18,247 ) (18,428 ) Amortization of: Prior service cost 132 149 263 297 (9,471 ) (9,492 ) (18,942 ) (18,984 ) Net actuarial loss 10,627 7,767 20,358 15,528 1,349 880 2,295 2,441 Net periodic benefit cost $ 13,106 $ 8,241 $ 26,387 $ 18,015 $ (6,168 ) $ (6,958 ) $ (12,537 ) $ (12,507 ) Portion of cost charged to expense $ 6,433 $ 5,232 $ 12,951 $ 11,219 $ (3,027 ) $ (2,482 ) $ (6,153 ) $ (4,271 )

Palo Verde Sale Leaseback Var28

Palo Verde Sale Leaseback Variable Interest Entities (Tables)	6 Months Ended
	Jun. 30, 2016
Variable Interest Entities [Abstract]
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets	Our Condensed Consolidated Balance Sheets at June 30, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands): June 30, 2016 December 31, 2015 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 115,450 $ 117,385 Equity — Noncontrolling interests 133,915 135,540

Derivative Accounting (Tables)

Derivative Accounting (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 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 2,291 GWh Gas 220 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 three and six months ended June 30, 2016 and 2015 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2016 2015 2016 2015 Gain (loss) recognized in OCI on derivative instruments (effective portion) OCI — derivative instruments $ 208 $ 41 $ 60 $ (286 ) Loss reclassified from accumulated OCI into income (effective portion realized) (a) Fuel and purchased power (b) (1,016 ) (1,430 ) (1,957 ) (3,773 ) (a) During the three and six months ended June 30, 2016 and 2015 , 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 three and six months ended June 30, 2016 and 2015 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended June 30, Commodity Contracts 2016 2015 2016 2015 Net gain (loss) recognized in income Operating revenues $ 585 $ (66 ) $ 483 $ (114 ) Net gain (loss) recognized in income Fuel and purchased power (a) 60,894 10,613 29,958 (34,190 ) Total $ 61,479 $ 10,547 $ 30,441 $ (34,304 ) (a) Amounts are before the effect of PSA deferrals.
Schedule of offsetting assets	The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2016 and December 31, 2015 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of June 30, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 30,393 $ (14,424 ) $ 15,969 $ 707 $ 16,676 Investments and other assets 14,260 (8,796 ) 5,464 — 5,464 Total assets 44,653 (23,220 ) 21,433 707 22,140 Current liabilities (65,432 ) 14,424 (51,008 ) (4,330 ) (55,338 ) Deferred credits and other (61,008 ) 8,796 (52,212 ) — (52,212 ) Total liabilities (126,440 ) 23,220 (103,220 ) (4,330 ) (107,550 ) Total $ (81,787 ) $ — $ (81,787 ) $ (3,623 ) $ (85,410 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $0 . (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 $4,330 , and cash margin provided to counterparties of $707 . 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 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 June 30, 2016 and December 31, 2015 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of June 30, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 30,393 $ (14,424 ) $ 15,969 $ 707 $ 16,676 Investments and other assets 14,260 (8,796 ) 5,464 — 5,464 Total assets 44,653 (23,220 ) 21,433 707 22,140 Current liabilities (65,432 ) 14,424 (51,008 ) (4,330 ) (55,338 ) Deferred credits and other (61,008 ) 8,796 (52,212 ) — (52,212 ) Total liabilities (126,440 ) 23,220 (103,220 ) (4,330 ) (107,550 ) Total $ (81,787 ) $ — $ (81,787 ) $ (3,623 ) $ (85,410 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $0 . (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 $4,330 , and cash margin provided to counterparties of $707 . 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 June 30, 2016 (dollars in thousands): June 30, 2016 Aggregate fair value of derivative instruments in a net liability position $ 126,440 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 76,949 (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)	6 Months Ended
	Jun. 30, 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 the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended 2016 2015 2016 2015 Other income: Interest income $ 184 $ 184 $ 302 $ 294 Investment gains — net 13 — 13 — Miscellaneous — (9 ) (1 ) 116 Total other income $ 197 $ 175 $ 314 $ 410 Other expense: Non-operating costs $ (2,085 ) $ (1,952 ) $ (4,133 ) $ (4,200 ) Investment losses — net (539 ) (650 ) (1,058 ) (1,145 ) Miscellaneous (218 ) (7 ) (1,689 ) (1,550 ) Total other expense $ (2,842 ) $ (2,609 ) $ (6,880 ) $ (6,895 )
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 the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended 2016 2015 2016 2015 Other income: Interest income $ 109 $ 6 $ 181 $ 73 Gain on disposition of property 4,989 478 5,321 685 Miscellaneous 649 226 855 591 Total other income $ 5,747 $ 710 $ 6,357 $ 1,349 Other expense: Non-operating costs (a) $ (2,719 ) $ (1,878 ) $ (4,685 ) $ (4,395 ) Loss on disposition of property (657 ) (251 ) (1,083 ) (894 ) Miscellaneous (1,054 ) (320 ) (3,412 ) (2,514 ) Total other expense $ (4,430 ) $ (2,449 ) $ (9,180 ) $ (7,803 ) (a) As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 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 the three and six months ended June 30, 2016 and 2015 (in thousands, except per share amounts): Three Months Ended Six Months Ended 2016 2015 2016 2015 Net income attributable to common shareholders $ 121,308 $ 122,902 $ 125,761 $ 139,024 Weighted average common shares outstanding — basic 111,368 110,986 111,336 110,958 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 636 474 594 468 Weighted average common shares outstanding — diluted 112,004 111,460 111,930 111,426 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 1.09 $ 1.11 $ 1.13 $ 1.25 Net income attributable to common shareholders — diluted $ 1.08 $ 1.10 $ 1.12 $ 1.25

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 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 June 30, 2016 Assets Cash equivalents $ 9,857 $ — $ — $ — $ 9,857 Risk management activities — derivative instruments: Commodity contracts — 26,509 18,118 (22,487 ) (b) 22,140 Nuclear decommissioning trust: U.S. commingled equity funds — — — 328,037 (c) 328,037 Fixed income securities: Cash and cash equivalent funds 17,892 — — (13,139 ) (d) 4,753 U.S. Treasury 117,448 — — — 117,448 Corporate debt — 106,399 — — 106,399 Mortgage-backed securities — 112,771 — — 112,771 Municipal bonds — 73,847 — — 73,847 Other — 24,161 — — 24,161 Subtotal nuclear decommissioning trust 135,340 317,178 — 314,898 767,416 Total $ 145,197 $ 343,687 $ 18,118 $ 292,411 $ 799,413 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (75,916 ) $ (50,498 ) $ 18,864 (b) $ (107,550 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 6 . (c) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy. (d) 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 6 . (c) Valued using NAV as a practical expedient, and therefore 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	The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2016 and December 31, 2015 : June 30, 2016 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 16,151 $ 39,548 Discounted cash flows Electricity forward price (per MWh) $21.68 - $43.50 $ 31.26 Option Contracts (b) — 2,993 Option model Electricity forward price (per MWh) $35.46 - $49.65 $ 43.12 Electricity price volatilities 56% - 140% 94 % Natural gas price volatilities 38% - 80% 49 % Natural Gas: Forward Contracts (a) 1,967 7,957 Discounted cash flows Natural gas forward price (per MMBtu) $2.67 - $3.37 $ 2.91 Total $ 18,118 $ 50,498 (a) Includes swaps and physical and financial contracts. (b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. December 31, 2015 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range 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
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs	The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended Commodity Contracts 2016 2015 2016 2015 Net derivative balance at beginning of period $ (39,507 ) $ (48,814 ) $ (32,979 ) $ (41,386 ) Total net gains (losses) realized/unrealized: Included in OCI 104 25 104 (237 ) Deferred as a regulatory asset or liability 1,499 5,813 (7,604 ) (4,933 ) Settlements 4,502 4,541 6,267 4,852 Transfers into Level 3 from Level 2 120 (3,566 ) 382 (3,968 ) Transfers from Level 3 into Level 2 902 (944 ) 1,450 2,727 Net derivative balance at end of period $ (32,380 ) $ (42,945 ) $ (32,380 ) $ (42,945 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ — $ — $ —

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2016 and December 31, 2015 (dollars in thousands): Fair Value Total Unrealized Gains Total Unrealized Losses June 30, 2016 Equity securities $ 328,037 $ 165,926 $ (7 ) Fixed income securities 452,518 22,953 (345 ) Net payables (a) (13,139 ) — — Total $ 767,416 $ 188,879 $ (352 ) 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 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): Three Months Ended Six Months Ended 2016 2015 2016 2015 Realized gains $ 2,282 $ 1,260 $ 4,720 $ 2,455 Realized losses (1,350 ) (1,525 ) (3,136 ) (2,050 ) Proceeds from the sale of securities (a) 148,785 110,498 290,594 225,779 (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 June 30, 2016 is as follows (dollars in thousands): Fair Value Less than one year $ 13,046 1 year – 5 years 133,548 5 years – 10 years 103,874 Greater than 10 years 202,050 Total $ 452,518

Changes in Accumulated Other 34

Changes in Accumulated Other Comprehensive Loss (Tables)	6 Months Ended
	Jun. 30, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component	The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 Balance at beginning of period $ (43,770 ) $ (66,382 ) $ (44,748 ) $ (68,141 ) Derivative Instruments OCI (loss) before reclassifications 128 25 (566 ) (775 ) Amounts reclassified from accumulated other comprehensive loss (a) 624 874 1,766 2,850 Net current period OCI (loss) 752 899 1,200 2,075 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (1,585 ) (969 ) (1,585 ) (969 ) Amounts reclassified from accumulated other comprehensive loss (b) 884 852 1,414 1,435 Net current period OCI (loss) (701 ) (117 ) (171 ) 466 Balance at end of period $ (43,719 ) $ (65,600 ) $ (43,719 ) $ (65,600 ) (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 6 . (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4 .
Arizona Public Service Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component	The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2016 and 2015 (dollars in thousands): Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 Balance at beginning of period $ (26,038 ) $ (46,476 ) $ (27,097 ) $ (48,333 ) Derivative Instruments OCI (loss) before reclassifications 128 25 (566 ) (775 ) Amounts reclassified from accumulated other comprehensive loss (a) 624 874 1,766 2,850 Net current period OCI (loss) 752 899 1,200 2,075 Pension and Other Postretirement Benefits OCI (loss) before reclassifications (1,521 ) (927 ) (1,521 ) (927 ) Amounts reclassified from accumulated other comprehensive loss (b) 879 853 1,490 1,534 Net current period OCI (loss) (642 ) (74 ) (31 ) 607 Balance at end of period $ (25,928 ) $ (45,651 ) $ (25,928 ) $ (45,651 ) (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 6 . (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4 .

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Change in asset retirement obligations	The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2016 (dollars in thousands): Asset retirement obligations at January 1, 2016 $ 443,576 Changes attributable to: Accretion expense 13,112 Settlements (5,224 ) Newly incurred liabilities 10,373 Asset retirement obligations at June 30, 2016 $ 461,837

Consolidation and Nature of O36

Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash paid during the period for:
Income taxes, net of refunds	$ 2,503	$ 1,834
Interest, net of amounts capitalized	89,109	84,008
Significant non-cash investing and financing activities:
Accrued capital expenditures	55,286	38,985
Dividends accrued but not yet paid	$ 69,484	$ 65,933

Long-Term Debt and Liquidity 37

Long-Term Debt and Liquidity Matters - Narrative (Details)	Aug. 01, 2016USD ($)	Jun. 30, 2016USD ($)Facility	Jun. 01, 2016USD ($)	May 13, 2016USD ($)	May 12, 2016USD ($)	May 06, 2016USD ($)	Apr. 22, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Provisions
Total shareholder equity		$ 4,585,268,000							$ 4,583,917,000
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing in May 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility					$ 200,000,000
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing May 2021
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility				$ 200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)		300,000,000
Outstanding borrowings		0
Pinnacle West | Letter of Credit | Revolving credit facility maturing May 2021
Long-Term Debt and Liquidity Matters
Outstanding letters of credit		0
Pinnacle West | Commercial paper | Revolving credit facility maturing May 2021
Long-Term Debt and Liquidity Matters
Commercial paper		0
APS
Debt Provisions
Total shareholder equity		4,675,864,000							4,679,254,000
APS | ACC
Debt Provisions
Total shareholder equity		4,700,000,000
Total capitalization		8,900,000,000
Dividend restrictions, shareholder equity required		$ 3,600,000,000
APS | ACC | Minimum
Debt Provisions
Required common equity ratio ordered by ACC (as a percent) (at least)		40.00%
APS | Arizona pollution control corporation revenue refunding bonds, 2009 series A
Long-Term Debt and Liquidity Matters
Debt Instrument, repurchased face amount			$ 12,850,000
APS | Revolving Credit Facility | Revolving credit facility maturing in May 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility					$ 500,000,000
APS | Revolving Credit Facility | Revolving Credit Facilities Maturing in 2020 and 2021
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility		$ 1,000,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)		1,400,000,000
Outstanding borrowings		$ 0
Number of line of credit facilities | Facility		2
APS | Revolving Credit Facility | Revolving credit facility maturing May 2021
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility		$ 500,000,000		$ 500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)		700,000,000
APS | Revolving Credit Facility | Revolving credit facility maturing September 2020
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility		500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)		700,000,000
APS | Commercial paper
Long-Term Debt and Liquidity Matters
Maximum commercial paper support available under credit facility		500,000,000						$ 500,000,000	$ 250,000,000
APS | Commercial paper | Revolving Credit Facilities Maturing in 2020 and 2021
Long-Term Debt and Liquidity Matters
Commercial paper		$ 64,140,000
APS | Secured debt | Term loan facility maturing April 22, 2019
Long-Term Debt and Liquidity Matters
Debt issued							$ 100,000,000
Senior Notes | APS | Unsecured senior notes 3.75 percent mature on 15 May, 2046
Long-Term Debt and Liquidity Matters
Debt issued						$ 350,000,000
Debt instrument, stated interest rate						3.75%
Current Maturities of Long-term Debt | APS | Arizona pollution control corporation revenue refunding bonds, 2009 series D and E
Long-Term Debt and Liquidity Matters
Debt Instrument, repurchased face amount			$ 64,000,000
Subsequent Event | Senior Notes | APS | Unsecured Senior Notes 6.25 Percent Mature on 01 August, 2016 [Member]
Long-Term Debt and Liquidity Matters
Debt instrument, stated interest rate	6.25%
Repayments of debt	$ 250,000,000

Long-Term Debt and Liquidity 38

Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 4,191,415	$ 3,819,971
Fair Value	4,783,591	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	4,066,415	3,694,971
Fair Value	$ 4,658,591	$ 3,981,367

Regulatory Matters - Retail Rat

Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS $ in Millions	Jun. 01, 2016USD ($)kWh$ / kWh	Dec. 31, 2015USD ($)	Jun. 01, 2011USD ($)
Public Utilities, General Disclosures [Line Items]
Net retail rate increase	$ 165.9		$ 95.5
Adjustor account balance transferred into base rates, amount		$ 267.6
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
Required return on incremental fair value rate base above original cost rate base	1.00%
Base rate for fuel and purchased power costs (in dollars per kWh) | $ / kWh	0.029882
Decrease in base rate for fuel and purchased power costs (in dollars per kWh) | $ / kWh	0.03207
Plan option, non-partial requirements customers, maximum average monthly energy usage (in kWh) | kWh	600
Public utilities, case completion term	12 months
Approximate percentage of increase in the average retail customer bill			6.60%
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%
Four Corners Power Plant
Public Utilities, General Disclosures [Line Items]
Authorization to defer for potential future recovery of construction costs	$ 400
Ocotillo Plant
Public Utilities, General Disclosures [Line Items]
Authorization to defer for potential future recovery of construction costs	$ 500

Regulatory Matters (Details)

Regulatory Matters (Details)

Jun. 01, 2016USD ($)

Feb. 01, 2016$ / kWh

Jan. 15, 2016USD ($)

Jan. 01, 2016USD ($)

Jun. 01, 2015USD ($)

Mar. 02, 2015USD ($)

Nov. 04, 2014

Apr. 15, 2014CustomerMW

Mar. 01, 2014USD ($)

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

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

Apr. 30, 2014workshop

Jan. 31, 2016$ / kWh

Jun. 30, 2016USD ($)$ / kWh

Jun. 30, 2015USD ($)

Dec. 31, 2015USD ($)$ / kWh

Jul. 12, 2016USD ($)

Jul. 01, 2016USD ($)

Apr. 01, 2016USD ($)

Jan. 12, 2016USD ($)

Nov. 25, 2015USD ($)

Mar. 20, 2015project

Dec. 19, 2014MW

Change in regulatory asset

Deferred fuel and purchased power costs — current period

$ 21,026,000

$ (11,711,000)

Amounts charged to customers

(13,778,000)

(11,424,000)

APS

Change in regulatory asset

Deferred fuel and purchased power costs — current period

21,026,000

(11,711,000)

Amounts charged to customers

$ (13,778,000)

(11,424,000)

RES 2014 | APS | AZ Sun Program

Settlement Agreement

Request to build additional utility scale solar, capacity | MW

20

RES 2014 | APS | Alternative to AZ Sun Program

Settlement Agreement

Request to build additional utility scale solar, capacity | MW

10

Additional capacity from APS-owned non AZ Sun projects, impacted customers | Customer

1,500

RES 2014 | APS | Alternative to AZ Sun Program, Phase 1

Settlement Agreement

Request to build additional utility scale solar, capacity | MW

8

RES 2014 | APS | Alternative to AZ Sun Program Phase 2

Settlement Agreement

Request to build additional utility scale solar, capacity | MW

2

Lost Fixed Cost Recovery Mechanisms | APS

Change in regulatory asset

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

0.031

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

0.023

Percentage of retail revenues

1.00%

Amount of adjustment representing prorated sales losses approval

$ 46,400,000

$ 38,500,000

$ 25,300,000

Increase in amount of adjustment representing prorated sales losses

$ 7,900,000

ACC | Retail Rate Case Filing with Arizona Corporation Commission | APS

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

Change in regulatory asset

Reduced system benefits charge, amount

$ 14,600,000

ACC | Retail Rate Case Filing with Arizona Corporation Commission | APS | Maximum

Settlement Agreement

Annual cost recovery due to modifications to the Environmental Improvement Surcharge

$ 5,000,000

ACC | RES | APS

Settlement Agreement

Plan term

5 years

ACC | RES 2016 | APS

Settlement Agreement

Amount of approved budget

$ 148,000,000

ACC | RES 2017 | APS

Settlement Agreement

Amount of proposed budget

$ 150,000,000

ACC | DSMAC 2015 | APS

Settlement Agreement

Amount of approved budget

$ 68,900,000

$ 68,900,000

Number of resource savings projects | project

3

ACC | DSMAC 2015 | Subsequent Event | APS

Settlement Agreement

Additional budget approved

$ 4,000,000

ACC | DSMC 2016 | APS

Settlement Agreement

Amount of approved budget

$ 68,900,000

ACC | Electric energy efficiency standard | APS

Settlement Agreement

Number of workshops | workshop

3

Number of days to convene a workshop

120 days

ACC | Power Supply Adjustor (PSA) | APS

Change in regulatory asset

Beginning balance

$ (9,688,000)

$ (9,688,000)

6,925,000

$ 6,925,000

Deferred fuel and purchased power costs — current period

21,027,000

(11,710,000)

Amounts charged to customers

(13,778,000)

(11,424,000)

Ending balance

$ (2,439,000)

$ (16,209,000)

$ (9,688,000)

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

0.001678

PSA rate for prior year (in dollars per kWh) | $ / kWh

0.000887

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

0.001975

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

(0.000297)

Transition component increase in PSA (in dollars per kWh) | $ / kWh

(0.004936)

ACC | Net Metering | APS

Change in regulatory asset

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

0.70

0.70

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

$ 4.90

United States Federal Energy Regulatory Commission | Open Access Transmission Tariff [Member] | APS

Change in regulatory asset

Decrease in annual wholesale transmission rates

$ 17,600,000

Increase in annual wholesale transmission rates

$ 24,900,000

Regulatory Matters - Four Corne

Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions	Dec. 23, 2014	Dec. 30, 2013	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Ownership interest acquired		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1
Net receipt due to negotiation of alternate arrangement		$ 40
Four Corners cost deferral | SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Regulatory assets, non-current			$ 67	$ 67
Regulatory noncurrent asset amortization period				10 years
Retired power plant costs
Business Acquisition [Line Items]
Net book value			119	$ 119
Four Corners | SCE
Business Acquisition [Line Items]
Regulatory assets, non-current					$ 12
Regulatory asset, write off amount			$ 12

Regulatory Matters - Schedule o

Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Detail of regulatory assets
Regulatory assets, current	$ 108,596	$ 149,555
Regulatory assets, non-current	1,190,622	1,214,146
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	617,283	619,223
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	9,913	9,913
Regulatory assets, non-current	122,554	127,518
Income taxes — allowance for funds used during construction (AFUDC) equity
Detail of regulatory assets
Regulatory assets, current	5,419	5,495
Regulatory assets, non-current	137,611	133,712
Deferred fuel and purchased power — mark-to-market (Note 6)
Detail of regulatory assets
Regulatory assets, current	30,986	71,852
Regulatory assets, non-current	40,573	69,697
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	6,689	6,689
Regulatory assets, non-current	60,238	63,582
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,851	1,766
Regulatory assets, non-current	47,826	48,462
Lost fixed cost recovery (b)
Detail of regulatory assets
Regulatory assets, current	49,852	45,507
Regulatory assets, non-current	0	0
Palo Verde VIEs (Note 5)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	18,465	18,143
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	35,701	34,751
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	62,726	50,453
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,592	1,515
Regulatory assets, non-current	16,919	16,375
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,512	1,520
Regulatory assets, non-current	11,647	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	10,874	11,040
Transmission cost adjustor (b)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	2,814	2,942
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	418	418
Regulatory assets, non-current	5,391	6,085
Other
Detail of regulatory assets
Regulatory assets, current	32	5
Regulatory assets, non-current	$ 0	$ 0

Regulatory Matters - Schedule43

Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Detail of regulatory liabilities
Regulatory liabilities, current	$ 116,172	$ 145,766
Regulatory liabilities, non-current	1,010,821	994,152
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	299,713	277,554
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	26,373	39,746
Regulatory liabilities, non-current	245,777	240,367
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	33,294	34,100
Regulatory liabilities, non-current	155,279	179,521
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	3,774	3,604
Regulatory liabilities, non-current	95,877	97,175
Income taxes — change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	1,771	1,113
Regulatory liabilities, non-current	71,257	72,454
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	31	3,051
Regulatory liabilities, non-current	71,342	67,437
Renewable energy standard (b)
Detail of regulatory liabilities
Regulatory liabilities, current	35,882	43,773
Regulatory liabilities, non-current	2,182	4,365
Demand side management (b)
Detail of regulatory liabilities
Regulatory liabilities, current	4,957	6,079
Regulatory liabilities, non-current	21,864	19,115
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	14,483	13,678
Deferred fuel and purchased power (b) (c)
Detail of regulatory liabilities
Regulatory liabilities, current	2,439	9,688
Regulatory liabilities, non-current	0	0
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,062	2,062
Regulatory liabilities, non-current	9,535	6,001
Transmission cost adjustor (b)
Detail of regulatory liabilities
Regulatory liabilities, current	5,545	0
Regulatory liabilities, non-current	0	0
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	15,969	8,920
Other
Detail of regulatory liabilities
Regulatory liabilities, current	44	2,550
Regulatory liabilities, non-current	$ 7,543	$ 7,565

Retirement Plans and Other Po44

Retirement Plans and Other Postretirement Benefits - Narrative (Details) - USD ($)	Sep. 30, 2014	Jul. 31, 2012	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Regulatory Assets
Regulatory asset amortization period		3 years
Amortization of regulatory asset			$ 2,000,000		$ 4,000,000
Pension Benefits
Contributions
Voluntary employer contributions to pension plan				$ 80,000,000
Minimum employer contributions for the next three years				0
Maximum employer contributions for the next two years (up to)				300,000,000
Other Benefits
Other Postretirement Benefit Plan Remeasurement
Other postretirement plan benefit remeasurement, amount seeking approval to move to separate account to Pay Union employee medical costs	$ 140,000,000
Contributions
2016 (up to)				1,000,000
2017 (up to)				1,000,000
2,015				$ 1,000,000

Retirement Plans and Other Po45

Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	$ 12,630	$ 13,990	$ 26,896	$ 29,814
Interest cost on benefit obligation	32,878	30,802	65,823	61,992
Expected return on plan assets	(43,161)	(44,467)	(86,953)	(89,616)
Amortization of:
Prior service cost	132	149	263	297
Net actuarial loss	10,627	7,767	20,358	15,528
Net periodic benefit cost	13,106	8,241	26,387	18,015
Portion of cost charged to expense	6,433	5,232	12,951	11,219
Other postretirement benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	3,560	4,068	7,497	8,413
Interest cost on benefit obligation	7,519	6,867	14,860	14,051
Expected return on plan assets	(9,125)	(9,281)	(18,247)	(18,428)
Amortization of:
Prior service cost	(9,471)	(9,492)	(18,942)	(18,984)
Net actuarial loss	1,349	880	2,295	2,441
Net periodic benefit cost	(6,168)	(6,958)	(12,537)	(12,507)
Portion of cost charged to expense	$ (3,027)	$ (2,482)	$ (6,153)	$ (4,271)

Palo Verde Sale Leaseback Var46

Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016USD ($)power_plant	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)power_plantLease	Jun. 30, 2015USD ($)	Dec. 31, 1986Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,874	$ 4,605	$ 9,747	$ 9,210
Arizona Public Service Company
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts	3		3		3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,874	4,605	$ 9,747	9,210
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	$ 5,000	$ 5,000	10,000	$ 9,000
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period			288,000
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period			$ 456,000
Arizona Public Service Company | Consolidation of VIEs | Through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease			1
Arizona Public Service Company | Consolidation of VIEs | Through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease			2
Arizona Public Service Company | Consolidation of VIEs | Period 2016 through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments			$ 23,000
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments			$ 16,000
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033 | Maximum
Palo Verde Sale Leaseback Variable Interest Entities
Lease period (up to)			2 years

Palo Verde Sale Leaseback Var47

Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$ 115,450	$ 117,385
Equity — Noncontrolling interests	133,915	135,540
Arizona Public Service Company
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	115,450	117,385
Equity — Noncontrolling interests	133,915	135,540
Arizona Public Service Company | Consolidation of VIEs
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	115,450	117,385
Equity — Noncontrolling interests	$ 133,915	$ 135,540

Derivative Accounting - Narrati

Derivative Accounting - Narrative (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)Counterparty	Dec. 31, 2015USD ($)
Designated as Hedging Instruments
Derivative Accounting
Gross recognized derivatives	$ 2,000	$ 3,000
Commodity Contracts
Derivative Accounting
Gross recognized derivatives	$ 126,440	207,387
Concentration of credit risk, number of counterparties | Counterparty	1
Concentration of risk with two counterparties, as a percentage of risk management assets	73.00%
Risk management activities-derivative instruments: Commodity Contracts	$ 22,140	$ 28,011
Additional collateral to counterparties for energy related non-derivative instrument contracts	145,000
Commodity Contracts | Designated as Hedging Instruments
Derivative Accounting
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income	$ (4,000)
Arizona Public Service Company
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%

Derivative Accounting - Schedul

Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts MMcf in Thousands	6 Months Ended
	Jun. 30, 2016GWhMMcf
Outstanding gross notional amount of derivatives
Power | GWh	2,291
Gas | MMcf	220

Derivative Accounting - Gains a

Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Designated as Hedging Instruments
Gains and losses from derivative instruments
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	$ 0	$ 0	$ 0	$ 0
Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Loss reclassified from accumulated OCI into income (effective portion realized)	(1,016,000)	(1,430,000)	(1,957,000)	(3,773,000)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net gain (loss) recognized in income	61,479,000	10,547,000	30,441,000	(34,304,000)
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net gain (loss) recognized in income	585,000	(66,000)	483,000	(114,000)
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net gain (loss) recognized in income	60,894,000	10,613,000	29,958,000	(34,190,000)
Other comprehensive income | Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain (loss) recognized in OCI on derivative instruments (effective portion)	$ 208,000	$ 41,000	$ 60,000	$ (286,000)

Derivative Accounting - Derivat

Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - Commodity Contracts - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets
Gross Recognized Derivatives	$ 44,653	$ 53,356
Amounts Offset	(23,220)	(26,017)
Net Recognized Derivatives	21,433	27,339
Other	707	672
Amount Reported on Balance Sheet	22,140	28,011
Liabilities
Gross Recognized Derivatives	(126,440)	(207,387)
Amounts Offset	23,220	44,077
Net Recognized Derivatives	(103,220)	(163,310)
Other	(4,330)	(4,379)
Amount Reported on Balance Sheet	(107,550)	(167,689)
Assets and Liabilities
Gross Recognized Derivatives	(81,787)	(154,031)
Amounts Offset	0	18,060
Net Recognized Derivatives	(81,787)	(135,971)
Other	(3,623)	(3,707)
Amount Reported on Balance Sheet	(85,410)	(139,678)
Current Assets
Assets
Gross Recognized Derivatives	30,393	37,396
Amounts Offset	(14,424)	(22,163)
Net Recognized Derivatives	15,969	15,233
Other	707	672
Amount Reported on Balance Sheet	16,676	15,905
Investments and Other Assets
Assets
Gross Recognized Derivatives	14,260	15,960
Amounts Offset	(8,796)	(3,854)
Net Recognized Derivatives	5,464	12,106
Other	0	0
Amount Reported on Balance Sheet	5,464	12,106
Current Liabilities
Liabilities
Gross Recognized Derivatives	(65,432)	(113,560)
Amounts Offset	14,424	40,223
Net Recognized Derivatives	(51,008)	(73,337)
Other	(4,330)	(4,379)
Amount Reported on Balance Sheet	(55,338)	(77,716)
Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(61,008)	(93,827)
Amounts Offset	8,796	3,854
Net Recognized Derivatives	(52,212)	(89,973)
Other	0	0
Amount Reported on Balance Sheet	$ (52,212)	$ (89,973)

Derivative Accounting - Credit

Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Jun. 30, 2016USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	$ 126,440
Cash collateral posted	0
Additional cash collateral in the event credit-risk-related contingent features were fully triggered	$ 76,949

Commitments and Contingencies -

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)	Aug. 18, 2014USD ($)	Jun. 30, 2016USD ($)time_periodpower_plantclaim	Dec. 31, 1986Trust
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount	$ 57,400,000
Proceeds from legal settlements		$ 53,900,000
Arizona Public Service Company
Commitments and Contingencies
Maximum insurance against public liability per occurrence for a nuclear incident (up to)		13,400,000,000
Maximum available nuclear liability insurance (up to)		375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program		13,000,000,000
Maximum retrospective premium assessment per reactor for each nuclear liability incident		127,300,000
Annual limit per incident with respect to maximum retrospective premium assessment		$ 18,900,000
Number of VIE lessor trusts		3	3
Maximum potential retrospective assessment per incident of APS		$ 111,100,000
Annual payment limitation with respect to maximum potential retrospective premium 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
Arizona Public Service Company | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount	$ 16,700,000
Number of claims submitted | claim		2
Number of settlement agreement time periods | time_period		2
Proceeds from legal settlements		$ 15,700,000

Commitments and Contingencies54

Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - Arizona Public Service Company $ in Millions	Aug. 06, 2013Defendant	Sep. 08, 2011kVCustomer	Jun. 30, 2016USD ($)
Loss Contingencies [Line Items]
Capacity of transmission line that tripped out of service (in kV) | 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
Loss Contingencies [Line Items]
Costs related to investigation and study under Superfund site | $			$ 2
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant	24

Commitments and Contingencies55

Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions	Jul. 06, 2016guarantee	Jun. 30, 2016USD ($)Letter_of_credit	Jun. 24, 2016	Mar. 16, 2016USD ($)	May 23, 2013USD ($)	Jun. 30, 2016USD ($)Letter_of_credit
Environmental Matters
Clean power plan, optional extension period						2 years
Four Corners | New Mexico Tax Matter
Environmental Matters
Coal severance surtax, penalty, and interest					$ 30
Litigation settlement awarded (against), amount				$ (1)
Arizona Public Service Company | Letter of Credit Expiring in 2016 and 2017
Financial Assurances
Outstanding letters of credit		$ 79				$ 79
Arizona Public Service Company | Letters of Credit Expiring in 2017
Financial Assurances
Number of letters of credit expiring | Letter_of_credit		150,000,000				150,000,000
Arizona Public Service Company | Four Corners | New Mexico Tax Matter
Environmental Matters
Share of the assessment					12
Partial payment of assessment					$ 0.8
Litigation settlement awarded (against), amount				$ (0.8)
4C Acquisition, LLC | Four Corners Units 4 and 5
Environmental Matters
Percentage of share of cost of control						7.00%
Regional Haze Rules | Arizona Public Service Company | Four Corners Units 4 and 5
Environmental Matters
Percentage of share of cost of control						63.00%
Expected environmental cost						$ 400
Regional Haze Rules | Arizona Public Service Company | Natural gas tolling contract obligations | Four Corners Units 4 and 5
Environmental Matters
Additional percentage share of cost of control						7.00%
Regional Haze Rules | Arizona Public Service Company | Four Corners | Four Corners Units 4 and 5
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate						$ 45
Regional Haze Rules | Arizona Public Service Company | Navajo Plant
Environmental Matters
Expected environmental cost						200
Regional Haze Rules | Arizona Public Service Company | Cholla
Environmental Matters
Expected environmental cost						100
Proposal comment period		45 days
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Navajo Plant
Environmental Matters
Expected environmental cost						1
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Cholla
Environmental Matters
Expected environmental cost						8
Coal combustion waste | Arizona Public Service Company | Four Corners
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate						15
Coal combustion waste | Arizona Public Service Company | Navajo Plant
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate						1
Coal combustion waste | Arizona Public Service Company | Navajo Plant | Boron Inclusion on List of Groundwater Constituents
Environmental Matters
Industry litigation, period to complete rulemaking proceeding			3 years
Coal combustion waste | Arizona Public Service Company | Cholla
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate						$ 40
Payment Guarantee | Subsequent Event
Financial Assurances
Number of parental guarantees | guarantee	2

Other Income and Other Expens56

Other Income and Other Expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Other income:
Interest income	$ 184	$ 184	$ 302	$ 294
Investment gains — net	13	0	13	0
Miscellaneous	0	(9)	(1)	116
Total other income	197	175	314	410
Other expense:
Non-operating costs	(2,085)	(1,952)	(4,133)	(4,200)
Investment losses — net	(539)	(650)	(1,058)	(1,145)
Miscellaneous	(218)	(7)	(1,689)	(1,550)
Total other expense	(2,842)	(2,609)	(6,880)	(6,895)
Arizona Public Service Company
Other income:
Interest income	109	6	181	73
Gain on disposition of property	4,989	478	5,321	685
Miscellaneous	649	226	855	591
Total other income	5,747	710	6,357	1,349
Other expense:
Non-operating costs	(2,719)	(1,878)	(4,685)	(4,395)
Loss on disposition of property	(657)	(251)	(1,083)	(894)
Miscellaneous	(1,054)	(320)	(3,412)	(2,514)
Total other expense	$ (4,430)	$ (2,449)	$ (9,180)	$ (7,803)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 121,308	$ 122,902	$ 125,761	$ 139,024
Weighted average common shares outstanding - basic (in shares)	111,368	110,986	111,336	110,958
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units (in shares)	636	474	594	468
Weighted average common shares outstanding — diluted (in shares)	112,004	111,460	111,930	111,426
Net income attributable to common shareholders - basic (in dollars per share)	$ 1.09	$ 1.11	$ 1.13	$ 1.25
Net income attributable to common shareholders - diluted (in dollars per share)	$ 1.08	$ 1.10	$ 1.12	$ 1.25

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets
Nuclear decommissioning trust	$ 767,416	$ 735,196
Total assets	18,118	30,364
Recurring
Assets
Cash equivalents	9,857
Derivative instruments, other	(22,487)	(25,345)
Derivative assets	22,140	28,011
Nuclear decommissioning trust, other	314,898	314,622
Nuclear decommissioning trust	767,416	735,196
Total, other	292,411	289,277
Total assets	799,413	763,207
Liabilities
Total, other	18,864	39,698
Derivative liability	(107,550)	(167,689)
Recurring | US commingled equity funds
Assets
Nuclear decommissioning trust, other	328,037	314,957
Nuclear decommissioning trust	328,037	314,957
Recurring | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust, other	(13,139)	(335)
Nuclear decommissioning trust	4,753	11,925
Recurring | U.S. Treasury
Assets
Nuclear decommissioning trust	117,448	117,245
Recurring | Corporate debt
Assets
Nuclear decommissioning trust	106,399	96,243
Recurring | Mortgage-backed securities
Assets
Nuclear decommissioning trust	112,771	99,065
Recurring | Municipality bonds
Assets
Nuclear decommissioning trust	73,847	72,206
Recurring | Other
Assets
Nuclear decommissioning trust	24,161	23,555
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash equivalents	9,857
Decommissioning fund investments, gross fair value	135,340	129,505
Gross assets, fair value disclosure	145,197	129,505
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalent funds
Assets
Decommissioning fund investments, gross fair value	17,892	12,260
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	117,448	117,245
Recurring | Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	26,509	22,992
Decommissioning fund investments, gross fair value	317,178	291,069
Gross assets, fair value disclosure	343,687	314,061
Liabilities
Gross derivative liability	(75,916)	(144,044)
Recurring | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Decommissioning fund investments, gross fair value	106,399	96,243
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	112,771	99,065
Recurring | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Decommissioning fund investments, gross fair value	73,847	72,206
Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets
Decommissioning fund investments, gross fair value	24,161	23,555
Recurring | Significant Unobservable Inputs (a) (Level 3)
Assets
Gross derivative assets	18,118	30,364
Gross assets, fair value disclosure	18,118	30,364
Liabilities
Gross derivative liability	$ (50,498)	$ (63,343)

Fair Value Measurements - Signi

Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 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	$ 18,118	$ 30,364
Liabilities	50,498	63,343
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	16,151	24,543
Liabilities	$ 39,548	$ 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	21.68	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	43.50	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	31.26	26.86
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 0	$ 0
Liabilities	$ 2,993	$ 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	35.46	23.87
Electricity price volatilities (as a percent)	56.00%	40.00%
Natural gas price volatilities (as a percent)	38.00%	32.00%
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	49.65	44.13
Electricity price volatilities (as a percent)	140.00%	59.00%
Natural gas price volatilities (as a percent)	80.00%	40.00%
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	43.12	33.91
Electricity price volatilities (as a percent)	94.00%	52.00%
Natural gas price volatilities (as a percent)	49.00%	35.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 1,967	$ 5,821
Liabilities	$ 7,957	$ 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	2.67	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	3.37	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	2.91	2.61

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net derivative balance at beginning of period	$ (39,507)	$ (48,814)	$ (32,979)	$ (41,386)
Included in OCI	104	25	104	(237)
Deferred as a regulatory asset or liability	1,499	5,813	(7,604)	(4,933)
Settlements	4,502	4,541	6,267	4,852
Transfers into Level 3 from Level 2	120	(3,566)	382	(3,968)
Transfers from Level 3 into Level 2	902	(944)	1,450	2,727
Net derivative balance at end of period	(32,380)	(42,945)	(32,380)	(42,945)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0	$ 0	$ 0

Nuclear Decommissioning Trust61

Nuclear Decommissioning Trusts (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Nuclear decommissioning trust fund assets
Fair Value	$ 767,416		$ 767,416		$ 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			290,594	$ 225,779
Fair value of fixed income securities, summarized by contractual maturities
Total	767,416		767,416		735,196
Arizona Public Service Company
Nuclear decommissioning trust fund assets
Fair Value	767,416		767,416		735,196
Unrealized Gains	188,879		188,879		169,053
Unrealized Losses	(352)		(352)		(2,760)
Net payables for securities purchases	(13,139)		(13,139)		(335)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	2,282	$ 1,260	4,720	2,455
Realized losses	(1,350)	(1,525)	(3,136)	(2,050)
Proceeds from the sale of securities	148,785	$ 110,498	290,594	$ 225,779
Fair value of fixed income securities, summarized by contractual maturities
Total	767,416		767,416		735,196
Arizona Public Service Company | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	328,037		328,037		314,957
Unrealized Gains	165,926		165,926		157,098
Unrealized Losses	(7)		(7)		(115)
Fair value of fixed income securities, summarized by contractual maturities
Total	328,037		328,037		314,957
Arizona Public Service Company | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	452,518		452,518		420,574
Unrealized Gains	22,953		22,953		11,955
Unrealized Losses	(345)		(345)		(2,645)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	13,046		13,046
1 year - 5 years	133,548		133,548
5 years - 10 years	103,874		103,874
Greater than 10 years	202,050		202,050
Total	$ 452,518		$ 452,518		$ 420,574

Changes in Accumulated Other 62

Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	$ 4,719,183	$ 4,525,643	$ 4,719,183	$ 4,525,643
Total other comprehensive income	51	782	1,029	2,541
Balance at end of period			4,719,457	4,519,102
AOCI Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(43,719)	(65,600)	(43,719)	(65,600)
Balance at end of period	(43,770)	(66,382)	(44,748)	(68,141)
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	128	25	(566)	(775)
Amounts reclassified from accumulated other comprehensive loss	624	874	1,766	2,850
Total other comprehensive income	752	899	1,200	2,075
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	(1,585)	(969)	(1,585)	(969)
Amounts reclassified from accumulated other comprehensive loss	884	852	1,414	1,435
Total other comprehensive income	(701)	(117)	(171)	466
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	4,809,779	4,627,164	4,809,779	4,627,164
Total other comprehensive income	110	825	1,169	2,682
Balance at end of period			4,814,794	4,629,852
Arizona Public Service Company | AOCI Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(25,928)	(45,651)	(25,928)	(45,651)
Balance at end of period	(26,038)	(46,476)	(27,097)	(48,333)
Arizona Public Service Company | Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	128	25	(566)	(775)
Amounts reclassified from accumulated other comprehensive loss	624	874	1,766	2,850
Total other comprehensive income	752	899	1,200	2,075
Arizona Public Service Company | Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	(1,521)	(927)	(1,521)	(927)
Amounts reclassified from accumulated other comprehensive loss	879	853	1,490	1,534
Total other comprehensive income	$ (642)	$ (74)	$ (31)	$ 607

Asset Retirement Obligations -

Asset Retirement Obligations - Roll-Forward (Details) - Arizona Public Service Company $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	$ 443,576
Changes attributable to:
Accretion expense	13,112
Settlements	(5,224)
Newly incurred liabilities	10,373
Asset retirement obligations at the end of year	$ 461,837

Asset Retirement Obligations 64

Asset Retirement Obligations - Narrative (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)turbine_unit	Dec. 31, 2015USD ($)
Asset Retirement Obligations
Asset retirement obligation, current	$ 15,513	$ 28,573
Arizona Public Service Company
Asset Retirement Obligations
Newly incurred liabilities	10,373
Asset retirement obligation, current	15,513	28,573
Asset retirement obligation	$ 461,837	$ 443,576
Arizona Public Service Company | Ocotillo Steam Units
Asset Retirement Obligations
Number of constructed turbine units | turbine_unit	5
Newly incurred liabilities	$ 10,000