Arizona Public Service 10-K20 Feb 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	764622
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$6,356,930,539
Entity Common Stock, Shares Outstanding		110,575,187
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
ARIZONA PUBLIC SERVICE COMPANY
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	7286
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$0
Entity Common Stock, Shares Outstanding		71,264,947
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING REVENUES	$3,491,632	$3,454,628	$3,301,804
OPERATING EXPENSES
Fuel and purchased power	1,179,829	1,095,709	994,790
Operations and maintenance	908,025	924,727	884,769
Depreciation and amortization	417,358	415,708	404,336
Taxes other than income taxes	172,295	164,167	159,323
Other expenses	2,883	7,994	6,831
Total	2,680,390	2,608,305	2,450,049
OPERATING INCOME	811,242	846,323	851,755
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	30,790	25,581	22,436
Other income (Note S-3)	9,608	1,704	1,606
Other expense (Note S-3)	-21,746	-16,024	-19,842
Total	18,652	11,261	4,200
INTEREST EXPENSE
Interest charges	200,950	201,888	214,616
Allowance for borrowed funds used during construction (Note 1)	-15,457	-14,861	-14,971
Total	185,493	187,027	199,645
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	644,401	670,557	656,310
INCOME TAXES (Note 4)	220,705	230,591	237,317
INCOME FROM CONTINUING OPERATIONS	423,696	439,966	418,993
Net of income tax benefit of $(3,813) (Note 1)	0	0	-5,829
NET INCOME	423,696	439,966	413,164
Less: Net income attributable to noncontrolling interests (Note 18)	26,101	33,892	31,622
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	397,595	406,074	381,542
Average common shares outstanding â€” basic (in shares)	110,626	109,984	109,510
Average common shares outstanding â€” diluted (in shares)	111,178	110,806	110,527
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders â€” basic (in dollars per share)	$3.59	$3.69	$3.54
Net income attributable to common shareholders - basic (in dollars per share)	$3.59	$3.69	$3.48
Income from continuing operations attributable to common shareholders â€” diluted (in dollars per share)	$3.58	$3.66	$3.50
Net income attributable to common shareholders â€” diluted (in dollars per share)	$3.58	$3.66	$3.45
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	397,595	406,074	387,380
Discontinued operations, net of tax	0	0	-5,838
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	3,488,946	3,451,251	3,293,489
OPERATING EXPENSES
Fuel and purchased power	1,179,829	1,095,709	994,790
Operations and maintenance	882,442	897,824	873,916
Depreciation and amortization	417,264	415,612	404,242
Taxes other than income taxes	171,583	163,377	158,412
Income taxes (Notes 4 and S-1)	245,036	256,864	256,600
Total	2,896,154	2,829,386	2,687,960
OPERATING INCOME	592,792	621,865	605,529
OTHER INCOME (DEDUCTIONS)
Income taxes (Notes 4 and S-1)	7,676	11,769	12,204
Allowance for equity funds used during construction (Note 1)	30,790	25,581	22,436
Other income (Note S-3)	11,295	3,896	2,868
Other expense (Note S-3)	-13,403	-20,449	-21,150
Total	36,358	20,797	16,358
INTEREST EXPENSE
Interest on long-term debt	186,323	188,011	198,398
Interest on short-term borrowings	6,796	6,605	7,135
Debt discount, premium and expense	4,168	4,046	4,215
Allowance for borrowed funds used during construction (Note 1)	-15,457	-14,861	-14,971
Total	181,830	183,801	194,777
INCOME TAXES (Note 4)	237,360	245,095	244,396
NET INCOME	447,320	458,861	427,110
Less: Net income attributable to noncontrolling interests (Note 18)	26,101	33,892	31,613
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$421,219	$424,969	$395,497

CONSOLIDATED_STATEMENTS_OF_INC1

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement [Abstract]
Income tax expense (benefit) on discontinued operations	$0	$0	($3,813)

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income	$423,696	$439,966	$413,164
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	-810	-213	-22,763
Reclassification of net realized loss, net of tax benefit	13,483	26,747	59,887
Pension and other postretirement benefits activity, net of tax benefit (expense)	-2,761	9,421	1,031
Total other comprehensive income	9,912	35,955	38,155
COMPREHENSIVE INCOME	433,608	475,921	451,319
Less: Net income attributable to noncontrolling interests (Note 18)	26,101	33,892	31,622
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	407,507	442,029	419,697
ARIZONA PUBLIC SERVICE COMPANY
Net income	447,320	458,861	427,110
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	-809	-214	-22,775
Reclassification of net realized loss, net of tax benefit	13,483	26,747	59,888
Pension and other postretirement benefits activity, net of tax benefit (expense)	-7,635	9,190	-617
Total other comprehensive income	5,039	35,723	36,496
COMPREHENSIVE INCOME	452,359	494,584	463,606
Less: Net income attributable to noncontrolling interests (Note 18)	26,101	33,892	31,613
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$426,258	$460,692	$431,993

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net unrealized loss, tax benefit	($438)	$140	$14,900
Reclassification of net realized loss, tax benefit	7,932	17,472	39,120
Pension and other postretirement benefits activity, tax (expense) benefit	1,307	-6,156	-651
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized loss, tax benefit	-438	140	14,888
Reclassification of net realized loss, tax benefit	7,932	17,472	39,119
Pension and other postretirement benefits activity, tax (expense) benefit	$4,655	($6,003)	$408

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$7,604	$9,526
Customer and other receivables	297,740	299,904
Accrued unbilled revenues	100,533	96,796
Allowance for doubtful accounts	-3,094	-3,203
Materials and supplies (at average cost)	218,889	221,682
Fossil fuel (at average cost)	37,097	38,028
Income tax receivable (Note 4)	3,098	135,517
Assets from risk management activities (Note 16)	13,785	17,169
Deferred fuel and purchased power regulatory asset (Note 3)	6,926	20,755
Other regulatory assets (Note 3)	129,808	76,388
Deferred income taxes (Notes 4 and S-1)	122,232	91,152
Other current assets	38,817	39,895
Total current assets	973,435	1,043,609
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	17,620	23,815
Nuclear decommissioning trust (Notes 13 and 19)	713,866	642,007
Other assets	54,047	60,875
Total investments and other assets	785,533	726,697
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	15,543,063	15,200,464
Accumulated depreciation and amortization	-5,397,751	-5,300,219
Net	10,145,312	9,900,245
Construction work in progress	682,807	581,369
Palo Verde sale leaseback, net of accumulated depreciation of $229,795 and $225,925 (Note 18)	121,255	125,125
Intangible assets, net of accumulated amortization of $489,538 and $439,703	119,755	157,689
Nuclear fuel, net of accumulated amortization of $143,554 and $146,057	125,201	124,557
Total property, plant and equipment	11,194,330	10,888,985
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,054,087	711,712
Assets for other postretirement benefits (Note 7)	152,290	0
Other	153,857	137,683
Total deferred debits	1,360,234	849,395
Total Assets	14,313,532	13,508,686
CURRENT LIABILITIES
Accounts payable	295,211	284,516
Accrued taxes (Note 4)	140,613	130,998
Accrued interest	52,603	48,351
Common dividends payable	65,790	62,528
Short-term borrowings (Note 5)	147,400	153,125
Current maturities of long-term debt (Note 6)	383,570	540,424
Customer deposits	72,307	76,101
Liabilities from risk management activities (Note 16)	59,676	31,892
Liability for asset retirements (Note 11)	32,462	32,896
Regulatory liabilities (Note 3)	130,549	99,273
Other current liabilities	178,962	158,540
Total current liabilities	1,559,143	1,618,644
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	3,031,215	2,796,465
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,582,636	2,351,882
Regulatory liabilities (Notes 1, 3, 4 and 7)	1,051,196	801,297
Liability for asset retirements (Note 11)	358,288	313,833
Liabilities for pension and other postretirement benefits (Note 7)	453,736	513,628
Liabilities from risk management activities (Note 16)	50,602	70,315
Customer advances	123,052	114,480
Coal mine reclamation	198,292	207,453
Deferred investment tax credit	178,607	152,361
Unrecognized tax benefits (Note 4)	19,377	42,209
Other	188,286	185,659
Total deferred credits and other	5,204,072	4,753,117
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, issued 110,649,762 at end of 2014 and 110,280,703 at end of 2013	2,512,970	2,491,558
Treasury stock at cost; 78,400 shares at end of 2014 and 98,944 shares at end of 2013	-3,401	-4,308
Total common stock	2,509,569	2,487,250
Retained earnings	1,926,065	1,785,273
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 7)	-57,756	-54,995
Derivative instruments (Note 16)	-10,385	-23,058
Total accumulated other comprehensive loss	-68,141	-78,053
Total shareholdersâ€™ equity	4,367,493	4,194,470
Noncontrolling interests (Note 18)	151,609	145,990
Total equity	4,519,102	4,340,460
Total Liabilities and Equity	14,313,532	13,508,686
ARIZONA PUBLIC SERVICE COMPANY
CURRENT ASSETS
Cash and cash equivalents	4,515	3,725
Customer and other receivables	297,712	299,055
Accrued unbilled revenues	100,533	96,796
Allowance for doubtful accounts	-3,094	-3,203
Materials and supplies (at average cost)	218,889	221,682
Fossil fuel (at average cost)	37,097	38,028
Income tax receivable (Note 4)	0	135,179
Assets from risk management activities (Note 16)	13,785	17,169
Deferred fuel and purchased power regulatory asset (Note 3)	6,926	20,755
Other regulatory assets (Note 3)	129,808	76,388
Deferred income taxes (Notes 4 and S-1)	55,253	0
Other current assets	38,693	39,153
Total current assets	900,117	944,727
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	17,620	23,815
Nuclear decommissioning trust (Notes 13 and 19)	713,866	642,007
Other assets	33,362	33,709
Total investments and other assets	764,848	699,531
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	15,539,811	15,196,598
Accumulated depreciation and amortization	-5,394,650	-5,296,501
Net	10,145,161	9,900,097
Construction work in progress	682,807	581,369
Palo Verde sale leaseback, net of accumulated depreciation of $229,795 and $225,925 (Note 18)	121,255	125,125
Intangible assets, net of accumulated amortization of $489,538 and $439,703	119,600	157,534
Nuclear fuel, net of accumulated amortization of $143,554 and $146,057	125,201	124,557
Total property, plant and equipment	11,194,024	10,888,682
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,054,087	711,712
Assets for other postretirement benefits (Note 7)	149,260	0
Unamortized debt issue costs	24,642	21,860
Other	128,026	114,865
Total deferred debits	1,356,015	848,437
Total Assets	14,215,004	13,381,377
CURRENT LIABILITIES
Accounts payable	289,930	281,237
Accrued taxes (Note 4)	131,110	122,460
Accrued interest	52,358	48,132
Common dividends payable	65,800	62,500
Short-term borrowings (Note 5)	147,400	153,125
Current maturities of long-term debt (Note 6)	383,570	540,424
Customer deposits	72,307	76,101
Deferred income taxes	0	2,033
Liabilities from risk management activities (Note 16)	59,676	31,892
Liability for asset retirements (Note 11)	32,462	32,896
Regulatory liabilities (Note 3)	130,549	99,273
Other current liabilities	167,302	130,774
Total current liabilities	1,532,464	1,580,847
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,571,365	2,347,724
Regulatory liabilities (Notes 1, 3, 4 and 7)	1,051,196	801,297
Liability for asset retirements (Note 11)	358,288	313,833
Liabilities for pension and other postretirement benefits (Note 7)	424,508	476,017
Liabilities from risk management activities (Note 16)	50,602	70,315
Customer advances	123,052	114,480
Coal mine reclamation	198,292	207,453
Deferred investment tax credit	178,607	152,361
Unrecognized tax benefits (Note 4)	45,740	42,209
Other	144,823	148,502
Total deferred credits and other	5,146,473	4,674,191
EQUITY
Total common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,968,718	1,804,398
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 7)	-37,948	-30,313
Derivative instruments (Note 16)	-10,385	-23,059
Total accumulated other comprehensive loss	-48,333	-53,372
Total shareholdersâ€™ equity	4,478,243	4,308,884
Noncontrolling interests (Note 18)	151,609	145,990
Total equity	4,629,852	4,454,874
Long-term debt less current maturities (Note 6)	2,906,215	2,671,465
Total capitalization	7,536,067	7,126,339
Total Liabilities and Equity	$14,215,004	$13,381,377

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	$229,795	$225,925
Accumulated amortization on intangible assets	489,538	439,703
Accumulated amortization on nuclear fuel	143,554	146,057
EQUITY
Common stock, par value
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	110,649,762	110,280,703
Treasury stock at cost, shares	78,400	98,944
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	229,795	225,925
Accumulated amortization on intangible assets	483,538	439,703
Accumulated amortization on nuclear fuel	$143,554	$146,057

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$423,696,000	$439,966,000	$413,164,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	496,487,000	492,322,000	481,262,000
Deferred fuel and purchased power	-26,927,000	21,678,000	71,573,000
Deferred fuel and purchased power amortization	40,757,000	31,190,000	-116,716,000
Allowance for equity funds used during construction	-30,790,000	-25,581,000	-22,436,000
Deferred income taxes	159,023,000	249,296,000	187,023,000
Deferred investment tax credit	26,246,000	52,542,000	41,579,000
Change in derivative instruments fair value	339,000	534,000	-749,000
Change in derivative instruments fair value
Customer and other receivables	-52,672,000	-44,991,000	14,587,000
Accrued unbilled revenues	-3,737,000	-1,951,000	30,394,000
Materials, supplies and fossil fuel	3,724,000	-11,878,000	-23,043,000
Income tax receivable	132,419,000	-133,094,000	-4,043,000
Other current assets	4,384,000	-17,913,000	-27,352,000
Accounts payable	-353,000	45,414,000	-96,600,000
Accrued taxes	9,615,000	6,059,000	12,736,000
Other current liabilities	17,892,000	-7,513,000	23,869,000
Change in margin and collateral accounts â€” assets	-343,000	993,000	2,216,000
Change in margin and collateral accounts â€” liabilities	-24,975,000	12,355,000	137,785,000
Change in unrecognized tax benefits	2,778,000	-91,425,000	-2,583,000
Change in long-term regulatory liabilities	59,618,000	64,473,000	13,539,000
Change in long-term income tax receivable	0	137,270,000	-1,756,000
Change in other long-term assets	-59,344,000	-41,757,000	6,872,000
Change in other long-term liabilities	-78,210,000	-24,682,000	29,801,000
Net cash flow provided by operating activities	1,099,627,000	1,153,307,000	1,171,122,000
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	-910,634,000	-1,016,322,000	-889,551,000
Contributions in aid of construction	20,325,000	41,090,000	49,876,000
Allowance for borrowed funds used during construction	-15,457,000	-14,861,000	-14,971,000
Proceeds from nuclear decommissioning trust sales	356,195,000	446,025,000	417,603,000
Investment in nuclear decommissioning trust	-373,444,000	-463,274,000	-434,852,000
Other	347,000	-2,059,000	-1,099,000
Net cash flow used for investing activities	-922,668,000	-1,009,401,000	-872,994,000
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	731,126,000	136,307,000	476,081,000
Repayment of long-term debt	-652,578,000	-122,828,000	-654,286,000
Short-term borrowings and payments â€” net	-5,725,000	60,950,000	92,175,000
Dividends paid on common stock	-246,671,000	-235,244,000	-225,075,000
Common stock equity issuance	15,288,000	17,319,000	15,955,000
Distributions to noncontrolling interests	-20,482,000	-17,385,000	-10,529,000
Other	161,000	299,000	170,000
Net cash flow used for financing activities	-178,881,000	-160,582,000	-305,509,000
NET DECREASE IN CASH AND CASH EQUIVALENTS	-1,922,000	-16,676,000	-7,381,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	9,526,000	26,202,000	33,583,000
CASH AND CASH EQUIVALENTS AT END OF YEAR	7,604,000	9,526,000	26,202,000
Supplemental disclosure of cash flow information:
Income taxes, net of refunds	-102,154,000	18,537,000	2,543,000
Interest, net of amounts capitalized	177,074,000	184,010,000	200,923,000
Significant non-cash investing and financing activities:
Accrued capital expenditures	44,712,000	33,184,000	26,208,000
Dividends declared but not paid	65,790,000	62,528,000	59,789,000
Liabilities assumed relating to acquisition of SCE Four Cornersâ€™ interest (see Note 3)	0	145,609,000	0
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	447,320,000	458,861,000	427,110,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	496,393,000	492,226,000	481,168,000
Deferred fuel and purchased power	-26,927,000	21,678,000	71,573,000
Deferred fuel and purchased power amortization	40,757,000	31,190,000	-116,716,000
Allowance for equity funds used during construction	-30,790,000	-25,581,000	-22,436,000
Deferred income taxes	155,401,000	278,101,000	202,159,000
Deferred investment tax credit	26,246,000	52,542,000	41,579,000
Change in derivative instruments fair value	339,000	534,000	-749,000
Change in derivative instruments fair value
Customer and other receivables	-52,466,000	-46,552,000	12,914,000
Accrued unbilled revenues	-3,737,000	-1,951,000	30,394,000
Materials, supplies and fossil fuel	3,724,000	-11,878,000	-23,043,000
Income tax receivable	135,179,000	-134,590,000	-2,280,000
Other current assets	3,766,000	-17,112,000	-27,745,000
Accounts payable	-2,355,000	47,870,000	-97,395,000
Accrued taxes	8,650,000	5,760,000	7,330,000
Other current liabilities	33,970,000	-9,005,000	6,070,000
Change in margin and collateral accounts â€” assets	-343,000	993,000	2,216,000
Change in margin and collateral accounts â€” liabilities	-24,975,000	12,355,000	137,785,000
Change in unrecognized tax benefits	2,778,000	-91,244,000	-2,583,000
Change in long-term regulatory liabilities	59,618,000	64,473,000	13,539,000
Change in long-term income tax receivable	0	137,665,000	-1,756,000
Change in other long-term assets	-65,521,000	-46,043,000	1,391,000
Change in other long-term liabilities	-82,860,000	-25,601,000	34,854,000
Net cash flow provided by operating activities	1,124,167,000	1,194,691,000	1,175,379,000
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	-910,084,000	-1,016,322,000	-889,551,000
Contributions in aid of construction	20,325,000	41,090,000	49,876,000
Allowance for borrowed funds used during construction	-15,457,000	-14,861,000	-14,971,000
Proceeds from nuclear decommissioning trust sales	356,195,000	446,025,000	417,603,000
Investment in nuclear decommissioning trust	-373,444,000	-463,274,000	-434,852,000
Other	347,000	-2,067,000	-1,099,000
Net cash flow used for investing activities	-922,118,000	-1,009,409,000	-872,994,000
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	606,126,000	136,307,000	351,081,000
Repayment of long-term debt	-527,578,000	-122,828,000	-529,286,000
Short-term borrowings and payments â€” net	-5,725,000	60,950,000	92,175,000
Dividends paid on common stock	-253,600,000	-242,100,000	-222,200,000
Distributions to noncontrolling interests	-20,482,000	-17,385,000	-10,529,000
Net cash flow used for financing activities	-201,259,000	-185,056,000	-318,759,000
NET DECREASE IN CASH AND CASH EQUIVALENTS	790,000	226,000	-16,374,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	3,725,000	3,499,000	19,873,000
CASH AND CASH EQUIVALENTS AT END OF YEAR	4,515,000	3,725,000	3,499,000
Supplemental disclosure of cash flow information:
Income taxes, net of refunds	-86,054,000	7,524,000	1,196,000
Interest, net of amounts capitalized	173,436,000	180,757,000	196,038,000
Significant non-cash investing and financing activities:
Accrued capital expenditures	44,712,000	33,184,000	26,208,000
Dividends declared but not paid	65,800,000	62,500,000	59,800,000
Liabilities assumed relating to acquisition of SCE Four Cornersâ€™ interest (see Note 3)	$0	$145,609,000	$0

CONSOLIDATED_STATEMENTS_OF_CHA

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)		Total	Common Stock	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY
In Thousands, except Share data, unless otherwise specified		Total	Common Stock	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	ARIZONA PUBLIC SERVICE COMPANY	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
Balance at Dec. 31, 2011		$3,930,586	$2,444,247	($4,717)	$1,534,483	($152,163)	$108,736	$4,051,406	$178,162	$2,379,696	$1,510,740	($125,591)	$108,399
Balance (in shares) at Dec. 31, 2011			109,356,974	111,161					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		413,164			381,542		31,622	427,110			395,497		31,613
Other comprehensive income		38,155				38,155		36,496				36,496
Dividends, common stock		-291,923			-291,923			-282,000			-282,000
Issuance of common stock		22,676	22,676
Issuance of common stock (in shares)			480,983
Purchase of treasury stock	[1]	-4,607		-4,607
Purchase of treasury stock (in shares)	[1]			-89,629
Stock-based compensation and other		5,113		5,113
Stock-based compensation and other (in shares)				105,598
Net capital activities by noncontrolling interests		-10,875					-10,875	-10,529					-10,529
Balance at Dec. 31, 2012		4,102,289	2,466,923	-4,211	1,624,102	-114,008	129,483	4,222,483	178,162	2,379,696	1,624,237	-89,095	129,483
Balance (in shares) at Dec. 31, 2012			109,837,957	95,192					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		439,966			406,074		33,892	458,861			424,969		33,892
Other comprehensive income		35,955				35,955		35,723				35,723
Dividends, common stock		-244,903			-244,903			-244,800			-244,800
Other								-8			-8
Issuance of common stock		24,635	24,635
Issuance of common stock (in shares)			442,746
Purchase of treasury stock	[1]	-9,727		-9,727
Purchase of treasury stock (in shares)	[1]			-174,290
Stock-based compensation and other		9,630		9,630
Stock-based compensation and other (in shares)				170,538
Net capital activities by noncontrolling interests		-17,385					-17,385	-17,385					-17,385
Balance at Dec. 31, 2013		4,340,460	2,491,558	-4,308	1,785,273	-78,053	145,990	4,454,874	178,162	2,379,696	1,804,398	-53,372	145,990
Balance (in shares) at Dec. 31, 2013		110,280,703	110,280,703	98,944					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		423,696			397,595		26,101	447,320			421,219		26,101
Other comprehensive income		9,912				9,912		5,039				5,039
Dividends, common stock		-256,803			-256,803			-256,900			-256,900
Other								1			1
Issuance of common stock		21,412	21,412
Issuance of common stock (in shares)			369,059
Purchase of treasury stock	[1]	-7,893		-7,893
Purchase of treasury stock (in shares)	[1]			-139,746
Stock-based compensation and other		8,800		8,800
Stock-based compensation and other (in shares)				160,290
Net capital activities by noncontrolling interests		-20,482					-20,482	-20,482					-20,482
Balance at Dec. 31, 2014		$4,519,102	$2,512,970	($3,401)	$1,926,065	($68,141)	$151,609	$4,629,852	$178,162	$2,379,696	$1,968,718	($48,333)	$151,609
Balance (in shares) at Dec. 31, 2014		110,649,762	110,649,762	78,400					71,264,947

[1]	Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

CONSOLIDATED_STATEMENTS_OF_CHA1

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Common stock dividends declared (in dollars per share)	$2.33	$2.23	$2.67

Summary_of_Significant_Account

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE, and formerly SunCor. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a new subsidiary formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. SunCor was a developer of residential, commercial and industrial real estate projects and essentially all of these assets were sold in 2009 and 2010. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. All activities for SunCor are reported as discontinued operations.

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

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

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

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Regulatory Accounting

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

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

See Note 3 for additional information.

Electric Revenues

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

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

For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 3). Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.

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

Allowance for Doubtful Accounts

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

Property, Plant and Equipment

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

•

material and labor;

•

contractor costs;

•

capitalized leases;

•

construction overhead costs (where applicable); and

•

allowance for funds used during construction.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 11.

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

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2014 were as follows:

•Fossil plant — 19 years;

•Nuclear plant — 28 years;

•Other generation — 25 years;

•Transmission — 38 years;

•Distribution — 33 years; and

•Other — 7 years.

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

For the years 2012 through 2014, the depreciation rates ranged from a low of 0.30% to a high of 12.08%. The weighted-average rate was 2.77% for 2014, 3.00% for 2013, and 2.71% for 2012.

Allowance for Funds Used During Construction

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

AFUDC was calculated by using a composite rate of 8.47% for 2014, 8.56% for 2013, and 8.60% for 2012. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Materials and Supplies

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

Fair Value Measurements

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

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

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

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

See Note 13 for additional information about fair value measurements.

Derivative Accounting

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

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

Loss Contingencies and Environmental Liabilities

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Retirement Plans and Other Benefits

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

Nuclear Fuel

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

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

Income Taxes

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

Cash and Cash Equivalents

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

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

Year ended December 31,

2014

2013

2012

Cash paid (received) during the period for:

Income taxes, net of refunds

(102,154

)

18,537

2,543

Interest, net of amounts capitalized

177,074

184,010

200,923

Significant non-cash investing and financing activities:

Accrued capital expenditures

44,712

33,184

26,208

Dividends declared but not paid

65,790

62,528

59,789

Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)

—

145,609

—

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $53 million in 2014, $53 million in 2013, and $50 million in 2012. Estimated amortization expense on existing intangible assets over the next five years is $42 million in 2015, $32 million in 2016, $21 million in 2017, $9 million in 2018, and $3 million in 2019. At December 31, 2014, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

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

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

Business Segments

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

Preferred Stock

At December 31, 2014, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.

New_Accounting_Standards

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	New Accounting Standards

	During 2014, we adopted, on a prospective basis, new guidance relating to the presentation of unrecognized tax benefits. This guidance generally requires entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. Prior to adopting this guidance, we presented unrecognized tax benefits on a gross basis. The adoption of this new guidance changed our balance sheet presentation of unrecognized tax benefits, but did not impact our operating results or cash flows. See Note 4 for details regarding the impacts of adopting this guidance.

	In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The new guidance is effective for us on January 1, 2017, and may be adopted using full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We are currently evaluating this new guidance and the impacts it may have on our financial statements.

Regulatory_Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Regulatory Matters	Regulatory Matters

	Retail Rate Case Filing with the Arizona Corporation Commission

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

	Settlement Agreement

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

	APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The 2012 Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the 2012 Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the 2012 Settlement Agreement.

	Other key provisions of the 2012 Settlement Agreement include the following:
	•An authorized return on common equity of 10.0%;
	•A capital structure comprised of 46.1% debt and 53.9% common equity;

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

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

	•	Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and
	•Deferral of 100% in all years if Arizona property tax rates decrease;

	•	A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);

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

	•	Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
	•Modifications to the PSA, including the elimination of the 90/10 sharing provision;

	•	A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2009 Settlement Agreement discussed below;

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

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

	•	Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
	The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.

	Cost Recovery Mechanisms

	APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

	Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

	On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million. In a final order dated January 7, 2014, the ACC approved the requested budget. Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules are expected to become effective in the second quarter of 2015.

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

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

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

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

	On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan. The ACC approved a budget of $68.9 million for each of 2013 and 2014. The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015.

	On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules 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 Utility 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 rule making has not been initiated and there has been no additional action on the draft to date.

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


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


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


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


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


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

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions):



	Year Ended December 31,
	2014				2013
Beginning balance	$	21			$	73

Deferred fuel and purchased power costs - current period	27				(21		)

Amounts charged to customers	(41		)		(31		)
Ending balance	$	7			$	21


The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year. This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh. Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014.

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 or if metering is unavailable, through accepted estimating techniques.

APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012. 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 effective March 1, 2015.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. A series of workshops in this docket were held in 2014 and another is currently scheduled for February 26, 2015.

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, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. 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 electricity grid.

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 electrical grid. ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift. The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement.

In May 2014, the ACC began conducting a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.

On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015. The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design. On August 12, 2014, the ACC Commissioners voted to lift the requirement that APS file its next general rate case by June 2015. On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.

Four Corners

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis. This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $77 million as of December 31, 2014 and is being amortized in rates over 10 years.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement” that, upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group. However, this alternative arrangement was not approved by FERC. In late March 2014, APS and SCE filed requests for rehearing with FERC. Both requests for rehearing were denied on August 14, 2014. Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control. As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration. If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Cholla

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Cholla Unit 2 by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case.
If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($128 million as of December 31, 2014), 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 millions):


	Remaining		31-Dec-14						31-Dec-13
	Amortization
	Period		Current				Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)		$	—			$	485	$	—	$	314

Income taxes — AFUDC equity	2044		5				118		4		105

Deferred fuel and purchased power — mark-to-market (Note 16)	2017		51				46		5		29

Transmission vegetation management	2016		9				5		9		14

Coal reclamation	2026		—				7		8		18

Palo Verde VIEs (Note 18)	2046		—				35		—		41

Deferred compensation	2036		—				34		—		34

Deferred fuel and purchased power (b) (c)	2015		7				—		21		—

Tax expense of Medicare subsidy	2024		2				14		2		15

Loss on reacquired debt	2034		1				16		1		17

Income taxes — investment tax credit basis adjustment	2044		2				46		1		39

Pension and other postretirement benefits deferral	2015		4				—		8		4

Four Corners cost deferral	2024		7				70		—		37

Lost fixed cost recovery	2015		38				—		25		—

Transmission cost adjustor	2014		—				—		8		2

Retired power plant costs	2033		10				136		3		18

Deferred property taxes	(d)		—				30		—		11

Other	Various		2				12		2		14

Total regulatory assets (e)			$	138			$	1,054	$	97	$	712



(a)	This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. See Note 7 for further discussion.

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

(c)	Subject to a carrying charge.

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

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


	Remaining		31-Dec-14						31-Dec-13
	Amortization
	Period		Current				Non-Current		Current		Non-Current
Removal costs	(a)		$	31			$	273	$	28	$	303

Asset retirement obligations	2044		—				296		—		266

Renewable energy standard (b)	2017		25				23		33		15

Income taxes — change in rates	2043		—				72		—		74

Spent nuclear fuel	2047		5				66		6		36

Deferred gains on utility property	2019		2				8		2		10

Income taxes — deferred investment tax credit	2043		4				93		3		79

Demand side management (b)	2015		31				—		27		—

Other postretirement benefits	(c)		32				199		—		—

Other	Various		1				21		—		18

Total regulatory liabilities			$	131			$	1,051	$	99	$	801



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

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

(c)	See Note 7.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes	Income Taxes

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

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

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

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

	Included in the current income tax receivable on the Consolidated Balance Sheets as of December 31, 2013 was $133 million that represented an anticipated IRS refund related to the finalized examinations of tax years ended December 31, 2008 and 2009. Cash related to this refund was received in the first quarter of 2014.

	On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations has been accounted for in the Consolidated Balance Sheets as of December 31, 2013 and 2014.

	Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18). As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.

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


		2014				2013				2012
	Total unrecognized tax benefits, January 1	$	41,997			$	133,422			$	136,005

	Additions for tax positions of the current year	4,309				3,516				5,167

	Additions for tax positions of prior years	751				13,158				—

	Reductions for tax positions of prior years for:

	Changes in judgment	(2,282		)		(108,099		)		(7,729		)
	Settlements with taxing authorities	—				—				—

	Lapses of applicable statute of limitations	—				—				(21		)

	Total unrecognized tax benefits, December 31	$	44,775			$	41,997			$	133,422


	Included in the balances of unrecognized tax benefits at December 31, 2014, 2013 and 2012 were approximately $11 million, $10 million and $10 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

	As of the balance sheet date, the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.

	In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. As a result of this guidance, $26 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Consolidated Balance Sheets as of December 31, 2014.

	We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense. The amount of interest recognized in the Consolidated Statements of Income related to unrecognized tax benefits was a pre-tax expense of $1 million for 2014, a pre-tax benefit of $4 million for 2013, and a pre-tax expense of $4 million for 2012.

	The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2014 and December 31, 2013 and $13 million as of December 31, 2012. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2014, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

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


		Year Ended December 31,
		2014				2013				2012
	Current:

	Federal	$	25,054			$	(81,784	)		$	(3,493	)

	State	10,382				10,537				8,395

	Total current	35,436				(71,247		)		4,902

	Deferred:

	Federal	167,365				279,973				200,322

	State	17,904				21,865				28,280

Total deferred	185,269				301,838				228,602

Total income tax expense	220,705				230,591				233,504

Less: income tax benefit on discontinued operations	—				—				(3,813		)

Income tax expense — continuing operations	$	220,705			$	230,591			$	237,317


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



	Year Ended December 31,
	2014				2013				2012
Federal income tax expense at 35% statutory rate	$	225,540			$	234,695			$	229,709

Increases (reductions) in tax expense resulting from:

State income tax net of federal income tax benefit	18,149				21,387				23,819

Credits and favorable adjustments related to prior years resolved in current year	—				(3,356		)		—

Medicare Subsidy Part-D	830				823				483

Allowance for equity funds used during construction (see Note 1)	(8,523		)		(6,997		)		(6,158		)
Palo Verde VIE noncontrolling interest (see Note 18)	(9,135		)		(11,862		)		(11,065		)
Investment tax credit amortization	(4,928		)		(3,548		)		(2,030		)
Other	(1,228		)		(551		)		2,559

Income tax expense — continuing operations	$	220,705			$	230,591			$	237,317


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


	December 31,
	2014				2013
Current asset	$	122,232			$	91,152

Long-term liability	(2,582,636		)		(2,351,882		)
Deferred income taxes — net	$	(2,460,404	)		$	(2,260,730	)

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

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2014, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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



	December 31,
	2014				2013
DEFERRED TAX ASSETS

Risk management activities	$	57,505			$	44,920

Regulatory liabilities:

Asset retirement obligation and removal costs	229,772				235,959

Unamortized investment tax credits	96,232				82,116

Other postretirement benefits	90,496				—

Other	60,409				42,609

Pension liabilities	205,227				140,773

Other postretirement liabilities	—				57,869

Renewable energy incentives	65,169				65,434

Credit and loss carryforwards	68,347				133,070

Other	138,729				148,492

Total deferred tax assets	1,011,886				951,242

DEFERRED TAX LIABILITIES

Plant-related	(2,958,369		)		(2,903,730		)
Risk management activities	(12,171		)		(16,191		)
Other postretirement assets	(59,170		)		—

Regulatory assets:

Allowance for equity funds used during construction	(48,286		)		(43,058		)
Deferred fuel and purchased power	(2,498		)		(8,282		)
Deferred fuel and purchased power — mark-to-market	(38,187		)		(13,343		)
Pension and other postretirement benefits	(191,747		)		(129,250		)
Retired power plant costs (see Note 3)	(57,255		)		(8,199		)
Other	(99,123		)		(85,003		)
Other	(5,484		)		(4,916		)
Total deferred tax liabilities	(3,472,290		)		(3,211,972		)
Deferred income taxes — net	$	(2,460,404	)		$	(2,260,730	)

As of December 31, 2014, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $90 million, which first begin to expire in 2031, and other federal and state loss carryforwards of $4 million, which first begin to expire in 2019. The credit and loss carryforwards amount above has been reduced by $26 million of unrecognized tax benefits as a result of the guidance adopted in January 2014, as disclosed above.
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes	Income Taxes

	APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’s taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.

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

	APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits ("ITCs") and the change in income tax rates.

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

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

	The $135 million current income tax receivable on APS’s Consolidated Balance Sheets as of December 31, 2013 represented an anticipated IRS refund related to the finalized examinations of tax years ended December 31, 2008 and 2009. Cash related to this refund was received in the first quarter of 2014.

	On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015 resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations has been accounted for in APS's Consolidated Balance Sheets as of December 31, 2013 and 2014.

	Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18). As a result, there is no income tax expense associated with the VIEs recorded on APS’s Consolidated Statements of Income.

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



		2014				2013				2012
	Total unrecognized tax benefits, January 1	$	41,997			$	133,241			$	135,824

	Additions for tax positions of the current year	4,309				3,516				5,167

	Additions for tax positions of prior years	751				13,158				—

	Reductions for tax positions of prior years for:

	Changes in judgment	(2,282		)		(107,918		)		(7,729		)
	Settlements with taxing authorities	—				—				—

	Lapses of applicable statute of limitations	—				—				(21		)

	Total unrecognized tax benefits, December 31	$	44,775			$	41,997			$	133,241


	Included in the balance of unrecognized tax benefits at December 31, 2014, 2013 and 2012 were approximately $11 million, $10 million and $10 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

	As of the balance sheet date, the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.

	In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. The adoption of this guidance did not have any impact on APS's Consolidated Balance Sheets as of December 31, 2014.

	We reflect interest and penalties, if any, on unrecognized tax benefits in the Statements of Income as income tax expense. The amount of interest recognized in the Statements of Income related to unrecognized tax benefits was a pre-tax expense of $1 million for 2014, a pre-tax benefit of $4 million for 2013 and a pre-tax expense of $4 million for 2012.

	The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $1 million as of December 31, 2014, less than $1 million as of December 31, 2013 and $13 million as of December 31, 2012. To the extent that matters are settled favorably, this amount could be reversed and decrease our effective tax rate. Additionally, as of December 31, 2014, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

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


		Year Ended December 31,
		2014				2013				2012
	Current:

	Federal	$	40,115			$	(97,531	)		$	(11,650	)

	State	15,598				11,983				12,308

	Total current	55,713				(85,548		)		658

	Deferred:

Federal	165,027				305,389				216,367

State	16,620				25,254				27,371

Total deferred	181,647				330,643				243,738

Total income tax expense	$	237,360			$	245,095			$	244,396


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

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


	Year Ended December 31,
	2014				2013				2012
Federal income tax expense at 35% statutory rate	$	239,638			$	246,384			$	235,027

Increases (reductions) in tax expense resulting from:

State income tax net of federal income tax benefit	21,148				23,970				25,379

Credits and favorable adjustments related to prior years resolved in current year	—				(3,231		)		—

Medicare Subsidy Part-D	830				823				483

Allowance for equity funds used during construction (see Note 1)	(8,523		)		(6,997		)		(6,158		)
Palo Verde VIE noncontrolling interest (see Note 18)	(9,135		)		(11,862		)		(11,065		)
Investment tax credit amortization	(4,928		)		(3,548		)		(2,030		)
Other	(1,670		)		(444		)		2,760

Income tax expense	$	237,360			$	245,095			$	244,396


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


	December 31,
	2014				2013
Current asset (liability)	$	55,253			$	(2,033	)

Long-term liability	(2,571,365		)		(2,347,724		)
Deferred income taxes — net	$	(2,516,112	)		$	(2,349,757	)

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

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2014, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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



	December 31,
	2014				2013
DEFERRED TAX ASSETS

Regulatory liabilities:

Asset retirement obligation and removal costs	$	229,772			$	235,959

Unamortized investment tax credits	96,232				82,116

Other postretirement benefits	90,496				—

Other	60,409				42,609

Risk management activities	57,505				44,920

Pension liabilities	194,541				132,263

Other postretirement liabilities	—				53,950

Renewable energy incentives	65,169				65,434

Credit and loss carryforwards	—				38,183

Other	161,379				166,781

Total deferred tax assets	955,503				862,215

DEFERRED TAX LIABILITIES

Plant-related	(2,958,369		)		(2,903,730		)
Risk management activities	(12,171		)		(16,191		)
Other postretirement benefit assets	(58,495		)		—

Regulatory assets:

Allowance for equity funds used during construction	(48,286		)		(43,058		)
Deferred fuel and purchased power	(2,498		)		(8,282		)
Deferred fuel and purchased power — mark-to-market	(38,187		)		(13,343		)
Pension and other postretirement benefits	(191,747		)		(129,250		)
Retired power plant costs (see Note 3)	(57,255		)		(8,199		)
Other	(99,123		)		(85,003		)
Other	(5,484		)		(4,916		)
Total deferred tax liabilities	(3,471,615		)		(3,211,972		)
Deferred income taxes — net	$	(2,516,112	)		$	(2,349,757	)

Lines_of_Credit_and_ShortTerm_

Lines of Credit and Short-Term Borrowings

12 Months Ended

Dec. 31, 2014

Lines of Credit and Short-Term Borrowings

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2014 (dollars in millions):

Credit Facility

Expiration

Amount

Unused

Commitment

Committed

Amount (a)

Fees

Pinnacle West Revolving Credit Facility

May-19

200

0.175

APS Revolving Credit Facility

May-19

500

0.125

APS Revolving Credit Facility

April 2018

500

353

0.125

Total

1,200

1,053

(a)

At December 31, 2014, APS had $147 million of outstanding commercial paper. Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $853 million.

Pinnacle West

On May 9, 2014, Pinnacle West replaced its $200 million revolving credit facility that would have matured in November 2016, with a new $200 million facility that matures in May 2019. At December 31, 2014, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2014, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

On May 9, 2014, APS refinanced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019.

At December 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million credit facility that matures in May 2019 (see above). APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2014, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $147 million at December 31, 2014.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2013 (dollars in millions):

Credit Facility

Expiration

Amount

Unused

Commitment

Committed

Amount (a)

Fees

Pinnacle West Revolving Credit Facility

November 2016

200

0.175

APS Revolving Credit Facility

November 2016

500

347

0.125

APS Revolving Credit Facility

Apr-18

500

0.125

Total

1,200

1,047

(a)

At December 31, 2013, APS had $153 million of outstanding commercial paper. Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $847 million.

Pinnacle West

At December 31, 2013, the Pinnacle West credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

APS

On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility. The new revolving credit facility matures in April 2018.

At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS can use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $153 million at December 31, 2013.

See “Financial Assurances” in Note 10 for a discussion of APS’s separate outstanding letters of credit.

Debt Provisions

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017.

LongTerm_Debt_and_Liquidity_Ma

Long-Term Debt and Liquidity Matters	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt and Liquidity Matters	Long-Term Debt and Liquidity Matters

	All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2014 and 2013 (dollars in thousands):


		Maturity		Interest		December 31,
		Dates (a)		Rates		2014				2013
	APS

	Pollution Control Bonds:

	Variable	2029-2038		(b)		$	156,405			$	75,580

	Fixed	2024-2034		0.45%-5.75%		249,300				426,125

	Total Pollution Control Bonds					405,705				501,705

	Senior unsecured notes	2015-2044		3.35%-8.75%		2,875,000				2,675,000

	Palo Verde sale leaseback lessor notes	2015		8.00%		13,420				38,869

	Unamortized discount					(9,206		)		(8,732		)
	Unamortized premium					4,866				5,047

	Total APS long-term debt					3,289,785				3,211,889

	Less current maturities	(d)				383,570				540,424

	Total APS long-term debt less current maturities					2,906,215				2,671,465

	Pinnacle West

	Term loan	2017		(c)		125,000				125,000

	TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES					$	3,031,215			$	2,796,465


	(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.
	(b) The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.27% at December 31, 2014 and 0.03%-0.06% at December 31, 2013.
	(c) The weighted-average interest rate was 1.019% at December 31, 2014 and 1.269% at December 31, 2013.
	(d) Current maturities include $70 million of pollution control bonds expected to be remarketed in 2015 and $300 million in senior unsecured notes that mature in 2015.


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


	Year		Consolidated				Consolidated
			Pinnacle West				APS
	2015		$	384			$	384

	2016		357				357

	2017		157				32

	2018		32				32

	2019		500				500

	Thereafter		1,989				1,989

	Total		$	3,419			$	3,294


	Debt Fair Value

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



	As of								As of
	31-Dec-14								31-Dec-13
	Carrying				Fair Value				Carrying				Fair Value
	Amount								Amount
Pinnacle West	$	125			$	125			$	125			$	125

APS	3,290				3,714				3,212				3,454

Total	$	3,415			$	3,839			$	3,337			$	3,579


Credit Facilities and Debt Issuances

Pinnacle West

On December 31, 2014, Pinnacle West entered into a $125 million term loan facility that matures December 31, 2017. Pinnacle West used the proceeds to repay and refinance the term loan facility that would have matured in November 2015.

APS

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. On January 15, 2014, both of these series of bonds were canceled and refinanced.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044. The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used in 2013 to re-acquire the two series of tax-exempt indebtedness.

On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E, due 2029 in connection with the mandatory tender provisions for this indebtedness. On May 14, 2014, APS remarketed all $36 million of the 2009 Series A Bonds, which are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2014. We expect to remarket or refinance all $64 million of the 2009 Series D Bonds and 2009 Series E Bonds within the next twelve months.

On May 30, 2014, APS purchased all $38 million of the Navajo County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034, and on June 1, 2014, APS purchased a total of $64 million of the Navajo 2009 Series B Bonds and 2009 Series C Bonds, in each case, in connection with the mandatory tender provisions for this indebtedness. On September 23, 2014, APS remarketed all $38 million of the 2009 Series A Bonds, which are classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014. On October 1, 2014, APS remarketed all $32 million of the 2009 Series C Bonds, which are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2014. We expect to remarket or refinance all $32 million of the 2009 Series B Bonds within the next twelve months.

On June 1, 2014, APS remarketed all $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2014.

On June 18, 2014, APS issued $250 million of 3.35% unsecured senior notes that mature on June 15, 2024. The net proceeds from the sale were used along with other funds to repay at maturity APS’s $300 million aggregate principal amount of 5.80% senior notes due June 30, 2014.

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

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

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2014, the ratio was approximately 46% for Pinnacle West and 45% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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

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

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2014, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.0 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.2 billion, assuming APS’s total capitalization remains the same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

Retirement_Plans_and_Other_Ben

Retirement Plans and Other Benefits	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Retirement Plans and Other Benefits	Retirement Plans and Other Benefits

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

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

	On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement (HRA). The Company will provide a subsidy allowing post-65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The remeasurement reduced net periodic benefit costs in 2014 by $10 million ($5 million of which reduced expense), which was recognized during the fourth quarter of 2014. The September 30, 2014 remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income. As a result of this reduction, the other postretirement benefit obligation, and related regulatory asset, have been reduced to the extent that Pinnacle West will now reflect an asset for other postretirement benefits and a related regulatory liability with balances at December 31, 2014 of $152 million and $231 million, respectively.

	Because of the plan changes, the Company is currently in the process of seeking IRS and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs.

	Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 13 for further discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

	A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory liability. In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over 3 years beginning in July 2012. We amortized approximately $8 million during 2014, $8 million during 2013, and $4 million during 2012.

	The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):


		Pension												Other Benefits
		2014				2013				2012				2014				2013			2012
	Service cost-benefits earned during the period	$	53,080			$	64,195			$	63,502			$	18,139			$	23,597		$	27,163

	Interest cost on benefit obligation	129,194				112,392				119,586				41,243				41,536			46,467

	Expected return on plan assets	(158,998		)		(146,333		)		(140,979		)		(46,400		)		(45,717		)	(45,793		)
	Amortization of:

	Transition obligation	—				—				—				—				—			452

	Prior service cost (credit)	869				1,097				1,143				(9,626		)		(179		)	(179		)

	Net actuarial loss	10,963				39,852				44,250				1,175				11,310			20,233

	Net periodic benefit cost	$	35,108			$	71,203			$	87,502			$	4,531			$	30,547		$	48,343

	Portion of cost charged to expense	$	21,985			$	38,968			$	36,333			$	6,000			$	18,469		$	19,321


	The following table shows the plans’ changes in the benefit obligations and funded status for the years 2014 and 2013 (dollars in thousands):


		Pension								Other Benefits
		2014				2013				2014				2013
	Change in Benefit Obligation

	Benefit obligation at January 1	$	2,646,530			$	2,850,846			$	890,418			$	990,418

	Service cost	53,080				64,195				18,139				23,597

	Interest cost	129,194				112,392				41,243				41,536

	Benefit payments	(128,550		)		(125,269		)		(29,054		)		(26,675		)
	Actuarial (gain) loss	378,394				(255,634		)		150,188				(138,458		)

	Plan amendments	—				—				(388,599		)		—

	Benefit obligation at December 31	3,078,648				2,646,530				682,335				890,418

	Change in Plan Assets

	Fair value of plan assets at January 1	2,264,121				2,079,181				748,339				684,221

	Actual return on plan assets	292,992				150,546				105,223				76,995

	Employer contributions	175,000				140,500				770				14,438

Benefit payments	(116,709		)		(106,106		)		(19,707		)		(27,315		)
Fair value of plan assets at December 31	2,615,404				2,264,121				834,625				748,339

Funded Status at December 31	$	(463,244	)		$	(382,409	)		$	152,290			$	(142,079	)


The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2014 and 2013 (dollars in thousands):


	2014				2013
Projected benefit obligation	$	3,078,648			$	2,646,530

Accumulated benefit obligation	2,873,741				2,469,889

Fair value of plan assets	2,615,404				2,264,121


The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2014 and 2013 (dollars in thousands):


	Pension								Other Benefits
	2014				2013				2014				2013
Noncurrent asset	$	—			$	—			$	152,290			$	—

Current liability	(9,508		)		(10,860		)		—				—

Noncurrent liability	(453,736		)		(371,549		)		—				(142,079		)

Net amount recognized	$	(463,244	)		$	(382,409	)		$	152,290			$	(142,079	)


The following table shows the details related to accumulated other comprehensive loss as of December 31, 2014 and 2013 (dollars in thousands):


	Pension								Other Benefits
	2014				2013				2014				2013
Net actuarial loss	$	577,976			$	344,540			$	148,006			$	57,816

Prior service cost (credit)	1,203				2,072				(379,269		)		(296		)

APS’s portion recorded as a regulatory (asset) liability	(485,037		)		(265,107		)		230,916				(49,298		)

Income tax expense (benefit)	(36,890		)		(32,204		)		851				(2,528		)

Accumulated other comprehensive loss	$	57,252			$	49,301			$	504			$	5,694


The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2015 (dollars in thousands):


	Pension				Other
					Benefits
Net actuarial loss	$	28,180			$	5,651

Prior service cost (credit)	595				(37,968		)

Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2014	$	28,775			$	(32,317	)


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


	Benefit Obligations						Benefit Costs
	As of December 31,						For the Years Ended December 31,
	2014			2013			2014					2013			2012
							January - September		October - December
Discount rate – pension	4.02	%		4.88	%		4.88	%	4.88	%		4.01	%		4.42	%
Discount rate – other benefits	4.14	%		5.1	%		5.1	%	4.41	%		4.2	%		4.59	%
Rate of compensation increase	4	%		4	%		4	%	4	%		4	%		4	%
Expected long-term return on plan assets - pension	N/A			N/A			6.9	%	6.9	%		7	%		7.75	%

Expected long-term return on plan assets - other benefits	N/A			N/A			6.8	%	4.25	%		7	%		7.75	%

Initial healthcare cost trend rate (pre-65 participants)	7	%		7.5	%		7.5	%	7.5	%		7.5	%		7.5	%
Initial healthcare cost trend rate (post-65 participants)	5	%		7.5	%		7.5	%	5	%		7.5	%		7.5	%
Ultimate healthcare cost trend rate	5	%		5	%		5	%	5	%		5	%		5	%
Number of years to ultimate trend rate (pre-65 participants)	4			4			4		4			4			4

Number of years to ultimate trend rate (post-65 participants)	0			4			4		0			4			4


In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2015, we are assuming a 6.90% long-term rate of return for pension assets and 4.74% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

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

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


	1% Increase				1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	10			$	(4	)

Effect on service and interest cost components of net periodic other postretirement benefit costs	12				(9		)

Effect on the accumulated other postretirement benefit obligation	110				(88		)


Plan Assets

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

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

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

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

Based on the IPS, and given the pension plan’s funded status at year-end 2014, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 39% to 45%. The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments. The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. As of December 31, 2014, long-term fixed income assets represented 61% of total pension plan assets, and return-generating assets represented 39% of total pension plan assets.

As of December 31, 2014, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. As of December 31, 2014, investment in fixed income assets represented 43% of the other postretirement benefit plan total assets, and non-fixed income assets represented 57% of the other postretirement benefit plan’s assets. Fixed income assets are primarily invested in corporate bonds of investment-grade U.S. issuers, and U.S. Treasuries. Non-fixed income assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both emerging and developed markets.

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of partnerships and common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2.

The common and collective trusts, which are similar to mutual funds, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). Common and collective trusts are valued using the concept of net asset value (“NAV”), which is a value derived from the quoted active market prices of the underlying securities. The plans’ common and collective real estate trust is valued using NAV, which is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2014, the plans were able to transact in the common and collective trusts at NAV and accordingly classify these investments as Level 2. Because the trust’s shares are offered to a limited group of investors, they are not considered to be traded in an active market.

Investments in partnerships are also valued using the concept of NAV, which is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Partnerships are classified as Level 2 if the plan is able to transact in the partnership at the NAV. At December 31, 2014, certain partnerships have been classified as Level 3 due to restrictions that limit the plan's ability to transact in these partnerships at the NAV. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerhips; as of December 31, 2014, $30 million of these commitments have been funded.

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

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2014, by asset category, are as follows (dollars in thousands):



	Quoted Prices				Significant				Significant				Other (b)				Balance at December 31, 2014
	in Active				Other				Unobservable
	Markets for				Observable				Inputs
	Identical				Inputs				(Level 3)
	Assets				(Level 2)
	(Level 1)
Pension Plan:

Assets:

Cash and cash equivalents	$	387			$	—			$	—			$	—			$	387

Fixed Income Securities:

Corporate	—				1,162,096				—				—				1,162,096

U.S. Treasury	291,817				—				—				—				291,817

Other (a)	—				113,265				—				—				113,265

Equities:

U.S. Companies	246,387				—				—				—				246,387

International Companies	18,069				—				—				—				18,069

Common and collective trusts:

U.S. Equities	—				127,336				—				—				127,336

International Equities	—				317,167				—				—				317,167

Real estate	—				129,715				—				—				129,715

Partnerships	—				138,337				27,929				—				166,266

Short-term investments and other	—				26,016				—				16,883				42,899

Total Pension Plan	$	556,660			$	2,013,932			$	27,929			$	16,883			$	2,615,404

Other Benefits:

Assets:

Cash and cash equivalents	$	318			$	—			$	—			$	—			$	318

Fixed Income Securities:

Corporate	—				187,961				—				—				187,961

U.S. Treasury	130,967				—				—				—				130,967

Other (a)	—				35,291				—				—				35,291

Equities:

U.S. Companies	265,106				—				—				—				265,106

International Companies	17,813				—				—				—				17,813

Common and collective trusts:

U.S. Equities	—				88,258				—				—				88,258

International Equities	—				85,746				—				—				85,746

Real Estate	—				11,657				—				—				11,657

Short-term investments and other	—				7,408				—				4,100				11,508

Total Other Benefits	$	414,204			$	416,321			$	—			$	4,100			$	834,625



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

(b)	Represents plan receivables and payables.


The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2013, by asset category, are as follows (dollars in thousands):


	Quoted Prices				Significant				Significant				Other (b)				Balance at December 31, 2013
	in Active				Other				Unobservable
	Markets for				Observable				Inputs
	Identical				Inputs				(Level 3)
	Assets				(Level 2)
	(Level 1)
Pension Plan:

Assets:

Cash and cash equivalents	$	504			$	—			$	—			$	—			$	504

Fixed Income Securities:

Corporate	—				898,621				—				—				898,621

U.S. Treasury	231,590				—				—				—				231,590

Other (a)	—				84,011				—				—				84,011

Equities:

U.S. Companies	239,036				—				—				—				239,036

International Companies	19,429				—				—				—				19,429

Common and collective trusts:

U.S. Equities	—				116,150				—				—				116,150

International Equities	—				367,551				—				—				367,551

Fixed Income	—				137,520				—				—				137,520

Real estate	—				119,739				—				—				119,739

Partnerships	—				—				8,660				—				8,660

Short-term investments and other	—				41,060				—				250				41,310

Total Pension Plan	$	490,559			$	1,764,652			$	8,660			$	250			$	2,264,121

Other Benefits:

Assets:

Cash and cash equivalents

Fixed Income Securities:

Corporate	$	—			$	153,888			$	—			$	—			$	153,888

U.S. Treasury	98,704				—				—				—				98,704

Other (a)	—				27,936				—				—				27,936

Equities:

U.S. Companies	252,181				—				—				—				252,181

International Companies	20,892				—				—				—				20,892

Common and collective trusts:

U.S. Equities	—				80,751				—				—				80,751

International Equities	—				92,382				—				—				92,382

Real Estate	—				10,761				—				—				10,761

Short-term investments and other	—				8,414				—				2,430				10,844

Total Other Benefits	$	371,777			$	374,132			$	—			$	2,430			$	748,339



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

(b)	Represents plan receivables and payables.

The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2014 and 2013 (dollars in thousands):


		Pension
Partnerships		2014				2013
Beginning balance at January 1		$	8,660			$	2,419

Actual return on assets still held at December 31		927				(498		)

Purchases		19,984				7,377

Sales		(1,642		)		(638		)
Transfers in and/or out of Level 3		—				—

Ending balance at December 31		$	27,929			$	8,660


Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $175 million in 2014, $141 million in 2013, and $65 million in 2012. The minimum contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017). With regard to contributions to our other postretirement benefit plans, we made a contribution of $1 million in 2014, $14 million in 2013, and $23 million in 2012. We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans. APS funds its share of the contributions. APS’s share of the pension plan contribution was $175 million in 2014, $140 million in 2013, and $64 million in 2012. APS’s share of the contributions to the other postretirement benefit plan was $1 million in 2014, $14 million in 2013, and $22 million in 2012.

Estimated Future Benefit Payments

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


Year		Pension				Other Benefits
2015		$	139,013			$	25,134

2016		155,968				27,311

2017		160,080				29,253

2018		167,600				31,258

2019		177,470				33,190

Years 2020-2024		983,557				184,772


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

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2014, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $9 million for 2014, $9 million for 2013, and $8 million for 2012.

Leases

Leases	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Leases	Leases

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

	Total lease expense recognized in the Consolidated Statements of Income was $18 million in 2014, $18 million in 2013, and $19 million in 2012. APS’s lease expense was $15 million in 2014, $15 million in 2013, and $16 million in 2012.

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


	Year	Pinnacle West		APS
		Consolidated
	2015	$	18	$	15

	2016	6		6

	2017	5		5

	2018	4		4

	2019	3		3

	Thereafter	63		62

	Total future lease commitments	$	99	$	95


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

JointlyOwned_Facilities

Jointly-Owned Facilities	12 Months Ended
	Dec. 31, 2014
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Jointly-Owned Facilities	Jointly-Owned Facilities

	APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs, as well as for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2014 (dollars in thousands):



			Percent			Plant in		Accumulated		Construction
			Owned			Service		Depreciation		Work in
										Progress
	Generating facilities:

	Palo Verde Units 1 and 3		29.1	%		$	1,734,918	$	1,051,670	$	16,955

	Palo Verde Unit 2 (a)		16.8	%		556,472		349,960		13,710

	Palo Verde Common		28	%	(b)	612,190		224,208		68,896

	Palo Verde Sale Leaseback				(a)	351,050		229,795		—

	Four Corners Generating Station		63	%		811,648		578,772		33,150

	Navajo Generating Station Units 1, 2 and 3		14	%		272,208		159,198		2,716

	Cholla common facilities (c)		63.3	%	(b)	155,856		49,954		866

	Transmission facilities:

	ANPP 500kV System		33.6	%	(b)	106,369		35,035		3,731

	Navajo Southern System		22.5	%	(b)	59,994		18,119		1,113

	Palo Verde — Yuma 500kV System		18.2	%	(b)	12,925		4,943		12

	Four Corners Switchyards		47.5	%	(b)	33,034		10,035		386

	Phoenix — Mead System		17.1	%	(b)	39,777		12,843		105

	Palo Verde — Estrella 500kV System		50	%	(b)	89,572		16,491		736

	Morgan — Pinnacle Peak System		64.4	%	(b)	130,840		8,970		1,690

	Round Valley System		50	%	(b)	497		276		1

	Palo Verde — Morgan System		90	%	(b)	—		—		69,377

	Hassayampa - North Gila System		80	%	(b)	8,902		3,634		142,645



	(a)	See Note 18.

	(b)	Weighted-average of interests.

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

Commitments_and_Contingencies

Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

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 breach of contract lawsuit against the DOE in the United States Court of Federal Claims. The lawsuit seeks to recover damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde 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 NWPA. 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 current income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

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 $13.6 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $13.2 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment of approximately $16.5 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 $2.75 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 $20 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 $53 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2015 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $723 million in 2015; $747 million in 2016; $630 million in 2017; $610 million in 2018; $583 million in 2019; and $8.2 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

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

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

Years Ended December 31,

2015

2016

2017

2018

2019

Thereafter

Coal take-or-pay commitments (a)

151

171

195

190

194

2,469

(a)

Total take-or-pay commitments are approximately $3.4 billion. The total net present value of these commitments is approximately $2.2 billion.

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

Year Ended December 31,

2014

2013

2012

Total payments

237

188

196

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $46 million in 2015; $42 million in 2016; $42 million in 2017; $42 million in 2018; $42 million in 2019; and $448 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Also, these amounts do not include purchases of renewable energy credits that are associated with purchased power contracts.

Coal Mine Reclamation Obligations

APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $198 million at December 31, 2014 and $207 million at December 31, 2013. Under our current coal supply agreements, we expect to make payments to certain coal providers for the final mine reclamation as follows: $1 million in 2015; $15 million in 2016; $17 million in 2017; $18 million in 2018; $19 million in 2019; and $281 million thereafter. Any amendments to current coal supply agreements may change the timing of the reimbursement.

Superfund-Related Matters

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, OU3 in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

On August 6, 2013, RID filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. We are unable to predict the outcome of this matter; 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

Regulatory. On September 8, 2011 at approximately 3:30 PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.

Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. Service to all affected APS customers was restored by 9:15 PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9.

FERC and NERC conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analysis and conclusions as to the causes of the events. The report included recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report did not address potential reliability violations or an assessment of responsibility of the parties involved.

On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS. FERC Staff alleged that each of the named entities violated varying numbers of NERC Reliability Standards. APS was alleged to have violated seven Reliability Standard Requirements. The allegations of violations were preliminary determinations by FERC Staff and did not constitute findings by FERC itself that any violations had occurred.

On July 7, 2014, FERC approved a Stipulation and Consent Agreement among FERC’s Office of Enforcement, NERC and APS which resolves all civil and administrative disputes within the jurisdiction of FERC concerning the September 8 event, including FERC’s and NERC’s investigations. In the settlement, APS neither admitted nor denied alleged violations of four Reliability Standard Requirements. APS agreed to pay a civil penalty of $3.25 million, of which $2 million is to be paid in equal parts to the Department of the Treasury and NERC and $1.25 million will be credited as a partial civil penalty offset in exchange for APS completing certain reliability enhancements.

Litigation. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision. The appeal is now fully briefed and pending before the Ninth Circuit Court of Appeals. We are unable to predict the outcome of this matter.

Clean Air Act Citizen Lawsuit

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss. We are unable to predict the outcome of this matter.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.

Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners, Cholla and the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes the BART to lessen the impacts of emissions on visibility surrounding the plants. 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 at least $350 million. In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5, which would increase our share of the cost of these controls by approximately $40 million. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP proposal, 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. As described under "Regional Haze Rules - Cholla" below, APS filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, would require installation of SCR controls with a cost to APS of approximately $200 million. However, 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 by April 2016 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 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. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved.

Mercury and Air Toxic Standards. 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 $130 million for Cholla, which would be avoided if EPA approves APS's compromise proposal discussed above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. At this time, SRP, the operating agent for the Navajo Plant, is analyzing the operations that would be covered by the rule and any resulting compliance costs.

Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, GHG emissions (such as the EPA’s proposed “Clean Power Plan” rule issued in accordance with President Obama’s Climate Action Plan), and other rules or matters involving the Clean Air Act, Clean Water Act, ESA, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other 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.

Regional Haze Rules — Cholla

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014; the court scheduled oral argument for March 9, 2015.

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million. For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department 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. We cannot predict the timing or outcome of this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2014, approximately $109 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit will expire in 2015, 2016, and 2017. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 18 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire on December 31, 2015, and totaled approximately $23 million at December 31, 2014. Additionally, APS has issued letters of credit to support collateral obligations under a natural gas tolling contract entered into with a third party. At December 31, 2014, that letter of credit totaled $5 million and will expire in 2015.

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

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2014.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations

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

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

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

	In 2013, a decommissioning study with updated cash flow estimates was completed for Palo Verde, which resulted in a decrease of $52 million. Also in 2013, APS finalized the transaction to acquire SCE’s interest in Four Corners. As part of that transaction, APS assumed SCE’s asset retirement obligation resulting in an increase to the ARO of $34 million. In addition, on December 30, 2013, APS also retired Four Corners Units 1-3 and began decommissioning activities. Finally, Four Corners spent $12 million in actual decommissioning costs. An update was made to the timing of the Units 1-3 decommissioning cash flows to coincide with the expected decommissioning activities. This update resulted in a decrease to the ARO of $4 million.

	The following schedule shows the change in our asset retirement obligations for 2014 and 2013 (dollars in millions):



		2014			2013
	Asset retirement obligations at the beginning of year	$	347		$	357

	Changes attributable to:

	Accretion expense	24			24

	Settlements	(30		)	(12		)
	Assumed SCE’s obligation	—			34

	Estimated cash flow revisions	44			(56		)

	Newly incurred obligation	6			—

	Asset retirement obligations at the end of year	$	391		$	347


	As mentioned above, decommissioning activities for Four Corners Units 1-3 began in January 2014; and, $32 million of the total ARO at December 31, 2014, was classified as a current liability on the balance sheet. At December 31, 2013, $33 million of the total ARO of $347 million was classified as a current liability on the balance sheet.

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

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Selected Quarterly Financial Information [Line Items]
Selected Quarterly Financial Data (Unaudited)	Selected Quarterly Financial Data (Unaudited)

	Consolidated quarterly financial information for 2014 and 2013 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.



		2014 Quarter Ended								2014
		March 31,		June 30,		Sept. 30,		Dec. 31,		Total
	Operating revenues	$	686,251	$	906,264	$	1,172,667	$	726,450	$	3,491,632

	Operations and maintenance	212,882		211,222		223,418		260,503		908,025

	Operating income	75,170		254,113		421,775		60,184		811,242

	Income taxes	6,405		74,540		134,753		5,007		220,705

	Income from continuing operations	24,691		141,384		248,086		9,535		423,696

	Net income attributable to common shareholders	15,766		132,458		243,961		5,410		397,595


	Earnings Per Share:

	Net income attributable to common shareholders — Basic	$	0.14	$	1.2	$	2.2	$	0.05	$	3.59

	Net income attributable to common shareholders — Diluted	0.14		1.19		2.2		0.05		3.58




		2013 Quarter Ended								2013
		March 31,		June 30,		Sept. 30,		Dec. 31,		Total
	Operating revenues	$	686,652	$	915,822	$	1,152,392	$	699,762	$	3,454,628

	Operations and maintenance	223,250		229,300		233,323		238,854		924,727

	Operating income	86,923		259,812		415,688		83,900		846,323

	Income taxes	12,469		77,043		131,912		9,167		230,591

	Income from continuing operations	32,836		139,598		234,718		32,814		439,966

	Net income attributable to common shareholders	24,444		131,207		226,163		24,260		406,074


	Earnings Per Share:

	Net income attributable to common shareholders — Basic	$	0.22	$	1.19	$	2.06	$	0.22	$	3.69

	Net income attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66

ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Selected Quarterly Financial Data (Unaudited)	Selected Quarterly Financial Data (Unaudited)

	Quarterly financial information for 2014 and 2013 is as follows (dollars in thousands):



		2014 Quarter Ended,								2014
		March 31,		June 30,		September 30,		December 31,		Total
	Operating revenues	$	685,545	$	905,578	$	1,172,190	$	725,633	$	3,488,946

	Operations and maintenance	208,285		208,059		212,430		253,668		882,442

	Operating income	69,635		180,394		287,928		54,835		592,792

	Net income attributable to common shareholder	19,518		134,916		251,047		15,738		421,219




		2013 Quarter Ended,								2013
		March 31,		June 30,		September 30,		December 31,		Total
	Operating revenues	$	685,827	$	915,065	$	1,151,535	$	698,824	$	3,451,251

	Operations and maintenance	220,752		224,950		222,617		229,505		897,824

	Operating income	74,862		183,728		284,251		79,024		621,865

	Net income attributable to common shareholder	26,042		133,949		234,954		30,024		424,969

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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, cash equivalents, and investments in U.S. Treasury securities.

	Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. This category also includes investments that are redeemable and valued based on NAV, such as common and collective trusts and commingled funds.

	Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

	Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

	Recurring Fair Value Measurements

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

	Cash Equivalents

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

	Risk Management Activities — Derivative Instruments

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

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

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

	When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.

	Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization.

	Investments Held in our Nuclear Decommissioning Trust

	The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on the concept of NAV, which is a value primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2. The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

	Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities. We may transact in this commingled fund on a daily basis at the NAV.

	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 classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.

	We price securities using information provided by our trustee for our nuclear decommissioning trust assets. Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 19 for additional discussion about our nuclear decommissioning trust.

	Fair Value Tables

	The following table presents the fair value at December 31, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):



		Quoted Prices				Significant				Significant			Other						Balance at December 31, 2014
		in Active				Other				Unobservable
		Markets for				Observable				Inputs (a)
		Identical				Inputs				(Level 3)
		Assets				(Level 2)
		(Level 1)
	Assets

	Risk management activities — derivative instruments:

	Commodity Contracts	$	—			$	21			$	33		$	(23	)		(b)		$	31

	Nuclear decommissioning trust:

	U.S. commingled equity funds	—				310				—			—						310

Fixed income securities:

U.S. Treasury	119				—				—			—						119

Cash and cash equivalent funds	—				11				—			(7		)		(c)		4

Corporate debt	—				109				—			—						109

Mortgage-backed securities	—				89				—			—						89

Municipality bonds	—				69				—			—						69

Other	—				14				—			—						14

Subtotal nuclear decommissioning trust	119				602				—			(7		)				714

Total	$	119			$	623			$	33		$	(30	)				$	745

Liabilities

Risk management activities — derivative instruments:

Commodity contracts	$	—			$	(95	)		$	(74	)	$	59			(b)		$	(110	)



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

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

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


The following table presents the fair value at December 31, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):



	Quoted Prices				Significant				Significant			Other						Balance at December 31, 2013
	in Active				Other				Unobservable
	Markets for				Observable				Inputs (a)
	Identical				Inputs				(Level 3)
	Assets				(Level 2)
	(Level 1)
Assets

Risk management activities — derivative instruments:

Commodity Contracts	$	—			$	9			$	41		$	(9	)		(b)		$	41

Nuclear decommissioning trust:

U.S. commingled equity funds	—				272				—			—						272

Fixed income securities:

U.S. Treasury	107				—				—			—						107

Cash and cash equivalent funds	—				11				—			(3		)		(c)		8

Corporate debt	—				88				—			—						88

Mortgage-backed securities	—				85				—			—						85

Municipality bonds	—				71				—			—						71

Other	—				11				—			—						11

Subtotal nuclear decommissioning trust	107				538				—			(3		)				642

Total	$	107			$	547			$	41		$	(12	)				$	683

Liabilities

Risk management activities — derivative instruments:

Commodity contracts	$	—			$	(33	)		$	(90	)	$	21			(b)		$	(102	)



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

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

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

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

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

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2014 and December 31, 2013:



	31-Dec-14								Valuation Technique		Significant Unobservable Input	Range		Weighted-Average
	Fair Value (millions)
Commodity Contracts	Assets				Liabilities
Electricity:

Forward Contracts (a)	$	30			$	56			Discounted cash flows		Electricity forward price (per MWh)	$19.51 - $56.72		$	35.27

Option Contracts (b)	—				15				Option model		Electricity forward price (per MWh)	$32.14 - $66.09		$	45.83

											Natural gas forward price (per MMbtu)	$3.18 - $3.29		$	3.25

											Electricity price volatilities	23% - 63%		41		%

											Natural gas price volatilities	23% - 41%		31		%

Natural Gas:

Forward Contracts (a)	3				3				Discounted cash flows		Natural gas forward price (per MMbtu)	$2.98 - $4.13		$	3.45

Total	$	33			$	74



(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.



	31-Dec-13								Valuation Technique		Significant Unobservable Input	Range		Weighted-Average
	Fair Value (millions)
Commodity Contracts	Assets				Liabilities
Electricity:

Forward Contracts (a)	$	40			$	66			Discounted cash flows		Electricity forward price (per MWh)	$24.89 - $65.04		$	41.09

Option Contracts (b)	—				19				Option model		Electricity forward price (per MWh)	$39.91 - $85.41		$	58.7

											Natural gas forward price (per MMbtu)	$3.57 - $3.80		$	3.71

											Electricity price volatilities	35% - 94%		59		%

											Natural gas price volatilities	22% - 36%		27		%

Natural Gas:

Forward Contracts (a)	1				5				Discounted cash flows		Natural gas forward price (per MMbtu)	$3.47 - $4.31		$	3.87

Total	$	41			$	90



(a)	Includes swaps and physical and financial contracts.

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

The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2014 and 2013 (dollars in millions):



		Year Ended
		December 31,
Commodity Contracts		2014				2013
Net derivative balance at beginning of period		$	(49	)		$	(48	)
Total net gains (losses) realized/unrealized:

Included in earnings		—				—

Included in OCI		—				—

Deferred as a regulatory asset or liability		—				(10		)

Settlements		12				10

Transfers into Level 3 from Level 2		(2		)		—

Transfers from Level 3 into Level 2		(2		)		(1		)
Net derivative balance at end of period		$	(41	)		$	(49	)
Net unrealized gains included in earnings related to instruments still held at end of period		$	—			$	—


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

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value

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

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share

	The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per share amounts):


		2014		2013		2012
	Income from continuing operations attributable to common shareholders	$	397,595	$	406,074	$	387,380

	Weighted average common shares outstanding — basic	110,626		109,984		109,510

	Net effect of dilutive securities:

	Contingently issuable performance shares and restricted stock units	552		822		1,017

	Weighted average common shares outstanding — diluted	111,178		110,806		110,527

	Earnings per average common share outstanding:
	Income from continuing operations attributable to common shareholders — basic	$	3.59	$	3.69	$	3.54

	Income from continuing operations attributable to common shareholders — diluted	$	3.58	$	3.66	$	3.5

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation

	Pinnacle West grants long-term incentive awards under the 2012 Long-Term Incentive Plan (“2012 Plan”) in the form of Stock Grants, Restricted Stock Units, Stock Units and Performance Shares and may grant restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan, effective May 16, 2012, provides 4,595,500 common shares to be available for grant to eligible employees and members of the Board of Directors. Awards made since 2012 were issued under the 2012 Plan, and prior awards from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”).

	Restricted Stock Unit Awards, Stock Unit Awards and Stock Grants

	Stock grants issued to non-officer members of the Board of Directors in 2014, 2013 and 2012 provided the members of the Board of Directors the option to elect to receive a stock grant, or to defer receipt until a later date and receive restricted stock units in 2012 and stock units in 2013 and 2014 in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock. The members of the Board of Directors may elect to receive payments either as of the last business day of the month following the month in which they separate from service on the Board of Directors, or as of a specified date, which must be after December 31 of the year in which the grant was received. The deferred restricted stock units and stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock.

	Restricted stock units have been granted to officers and key employees in each year since 2008. From 2008 through 2009, officers and key employees elected to receive payment in either cash or in fully transferable shares of stock, in exchange for each restricted stock unit on pre-established valuation dates. From 2010 through 2014, officers and key employees elected to receive payment in either stock, or 50% in cash and 50% in stock.

	Restricted stock unit awards vest and settle over a 4-year period. In addition, officers and key employees accrue dividend rights on vested restricted stock units, equal to the amount of dividends that they would have received had they directly owned stock, equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest for the 2008 and 2009 awards were paid in cash. The dividends and interest for the 2010 through 2014 awards are paid in the same form as the restricted stock unit payment election. Restricted stock unit awards are accounted for as a liability award, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately.

	In December 2012, the Company granted a retention award of 50,617 restricted stock units to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West. The award will vest and will be paid in shares of common stock on December 31, 2016, provided that he remains employed with the Company until the vesting date. The award will accrue notional dividends equal to the amount of dividends that would have been received if the Chairman of the Board, President and Chief Executive Officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date. The award can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met.

	A grant of restricted stock unit awards was made to officers of the company on February 15, 2011, payable solely in shares of common stock upon the officer’s retirement or other separation of employment. This award vested 50% on February 15, 2013 and 25% on February 15, 2014. The remaining award will vest 25% on February 15, 2015, provided that the officer remains employed on such date. The officers will also accrue notional dividends equal to the amount of dividends that they would have received if they had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date. Each additional restricted stock unit will proportionally vest on the same remaining vesting schedule that applies to the original restricted stock unit.

	The following table is a summary of granted restricted stock units, stock units and stock grants and the weighted-average fair value for the 3 years ended 2014, 2013 and 2012:


		2014				2013				2012
	Units granted	130,273				129,620				202,278

	Grant date fair value (a)	$	54.91			$	55.21			$	49.31


	(a)	Weighted-average grant date fair value.

	The following table is a summary of the status of restricted stock units, stock units and stock grants, as of December 31, 2014 and changes during the year. This table represents only the stock portion of restricted stock units and stock units, per the election on payment discussed in the paragraph above:



	Nonvested shares		Shares			Weighted-Average
						Grant Date
						Fair Value
	Nonvested at January 1, 2014		397,976			$	47.74

	Granted		130,273			54.91

	Vested		(161,283	)		45.55

	Forfeited		(13,067	)		51.53

	Nonvested at December 31, 2014		353,899			51.23


	The amount of cash required to settle the payments on restricted stock units is (dollars in millions):



	Year		2014				2013				2012
	2008 Grant		$	—			$	—			$	1.9

	2009 Grant		—				3				1.7

	2010 Grant		2.3				2.3				0.6

	2011 Grant		2.4				2.5				0.7

	2012 Grant		2.1				2.2				—

	2013 Grant		2.1				—				—


	Performance Share Awards

Performance share awards have been granted to officers and key employees under the 2012 Plan since 2012 and under the 2007 Plan from 2009 to 2011. Performance share awards contain two performance element criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met.

The 2014, 2013 and 2012 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period, as compared with the total shareholder return of all relevant companies in a specified utility index and the other 50% is based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.

Performance share awards are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. Management also evaluates the probability of meeting the performance criteria at each balance sheet date. If performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.

The following table is a summary of the performance shares granted and the weighted-average fair value for the three years ended 2014, 2013 and 2012:



	2014				2013				2012
Units granted (a)	166,244				176,332				185,878

Grant date fair value (b)	$	54.86			$	55.45			$	47.4


(a) Reflects the target payout level.
(b) Weighted-average grant date fair value.

The following table is a summary of the status of performance shares as of December 31, 2014 and changes during the year:



Nonvested shares (a)		Shares			Weighted-Average
					Grant Date
					Fair Value
Nonvested at January 1, 2014		344,396			$	51.13

Granted		166,244			54.86

Increase in performance factor		86,558			47.4

Vested		(258,224	)		47.4

Forfeited		(14,744	)		53.3

Nonvested at December 31, 2014		324,230			54.92



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

Stock Options

The Company has not granted stock options since 2004 and has no stock options outstanding.

As of December 31, 2014, there was $15 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested during 2014, 2013 and 2012 was $20 million, $20 million and $19 million, respectively.

The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $33 million in 2014, $25 million in 2013, and $32 million in 2012. The compensation cost that Pinnacle West has capitalized is immaterial for all years. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $13 million in 2014, $10 million in 2013, and $13 million in 2012. APS’s share of compensation cost that has been charged against income was $33 million in 2014, $25 million in 2013, and $32 million in 2012.

Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans, and it does not expect to repurchase any shares except to satisfy tax withholding obligations upon the vesting of restricted stock units and performance shares.

Derivative_Accounting

Derivative Accounting	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Accounting	Derivative Accounting

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

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

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

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

	For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

	As of December 31, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):



	Commodity		Quantity
	Power		3,915			GWh

	Gas		136			Bcf (a)


	(a)	“Bcf” is Billion Cubic Feet.

	Gains and Losses from Derivative Instruments

	The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):



			Financial Statement		Year Ended
					December 31,
	Commodity Contracts		Location		2014				2013				2012
	Loss Recognized in OCI on Derivative Instruments (Effective Portion)		OCI — derivative instruments		$	(372	)		$	(353	)		$	(37,663	)
	Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)		Fuel and purchased power (b)		(21,415		)		(44,219		)		(99,007		)
	Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Fuel and purchased power (b)		—				—				117



	(a)	During the years ended December 31, 2014, 2013, and 2012, we had zero, zero, and $1.8 million of 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 $6 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, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

	The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):



			Financial Statement		Year Ended
					December 31,
	Commodity Contracts		Location		2014				2013				2012
	Net Gain Recognized in Income		Operating revenues		$	324			$	289			$	103

	Net Loss Recognized in Income		Fuel and purchased power (a)		(66,367		)		(10,449		)		(2,747		)
	Total				$	(66,043	)		$	(10,160	)		$	(2,644	)


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

	Derivative Instruments in the Consolidated Balance Sheets

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

We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.

The significant majority of our derivative instruments are not currently designated as hedging instruments. The Consolidated Balance Sheets as of December 31, 2014 and December 31, 2013, include gross liabilities of $4 million and $5 million, respectively, of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2014 and 2013. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.



As of December 31, 2014:		Gross				Amounts				Net				Other			Amount
(dollars in thousands)		Recognized				Offset				Recognized				(c)			Reported on
		Derivatives				(b)				Derivatives							Balance Sheet
		(a)
Current Assets		$	28,562			$	(15,127	)		$	13,435			$	350		$	13,785

Investments and Other Assets		24,810				(7,190		)		17,620				—			17,620

Total Assets		53,372				(22,317		)		31,055				350			31,405


Current Liabilities		(86,062		)		33,829				(52,233		)		(7,443		)	(59,676		)

Deferred Credits and Other		(82,990		)		32,388				(50,602		)		—			(50,602		)

Total Liabilities		(169,052		)		66,217				(102,835		)		(7,443		)	(110,278		)

Total		$	(115,680	)		$	43,900			$	(71,780	)		$	(7,093	)	$	(78,873	)



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

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

(c)	Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,443, and cash margin provided to counterparties of $350.



As of December 31, 2013:		Gross				Amounts				Net				Other			Amount
(dollars in thousands)		Recognized				Offset				Recognized				(c)			Reported on
		Derivatives				(b)				Derivatives							Balance Sheet
		(a)
Current Assets		$	24,587			$	(7,425	)		$	17,162			$	7		$	17,169

Investments and Other Assets		25,364				(1,549		)		23,815				—			23,815

Total Assets		49,951				(8,974		)		40,977				7			40,984


Current Liabilities		(50,540		)		26,166				(24,374		)		(7,518		)	(31,892		)

Deferred Credits and Other		(72,123		)		1,808				(70,315		)		—			(70,315		)

Total Liabilities		(122,663		)		27,974				(94,689		)		(7,518		)	(102,207		)

Total		$	(72,712	)		$	19,000			$	(53,712	)		$	(7,511	)	$	(61,223	)



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

(b)	Includes cash collateral provided to counterparties of $19,000.

(c)	Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.

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 90% of Pinnacle West’s $31 million of risk management assets as of December 31, 2014. This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2014 (dollars in millions):



	31-Dec-14
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	169

Cash Collateral Posted	44

Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	80



(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 $175 million if our debt credit ratings were to fall below investment grade.

Other_Income_and_Other_Expense

Other Income and Other Expense	12 Months Ended
	Dec. 31, 2014
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 other income and other expense for 2014, 2013 and 2012 (dollars in thousands):



		2014			2013			2012
	Other income:

	Interest income	$	1,010		$	1,629		$	1,239

	Debt return on the purchase of Four Corners units 4 & 5	8,386			—			—

	Miscellaneous	212			75			367

	Total other income	$	9,608		$	1,704		$	1,606

	Other expense:

	Non-operating costs	$	(9,657	)	$	(8,207	)	$	(7,777	)
	Investment loss — net	(9,426		)	(3,711		)	(2,453		)
	Miscellaneous	(2,663		)	(4,106		)	(9,612		)
	Total other expense	$	(21,746	)	$	(16,024	)	$	(19,842	)
ARIZONA PUBLIC SERVICE COMPANY
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 APS’s other income and other expense for 2014, 2013 and 2012 (dollars in thousands):



		2014			2013			2012
	Other income:

	Interest income	$	689		$	1,234		$	310

	Debt return on the purchase of Four Corners units 4 & 5	8,386			—			—

	Miscellaneous	2,220			2,662			2,558

	Total other income	$	11,295		$	3,896		$	2,868

	Other expense:

	Non-operating costs (a)	$	(10,397	)	$	(9,626	)	$	(8,706	)
	Asset dispositions	(615		)	(4,992		)	(1,511		)
	Miscellaneous	(2,391		)	(5,831		)	(10,933		)
	Total other expense	$	(13,403	)	$	(20,449	)	$	(21,150	)

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

Palo_Verde_Sale_Leaseback_Vari

Palo Verde Sale Leaseback Variable Interest Entities	12 Months Ended
	Dec. 31, 2014
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 trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million in 2015 related to these leases. The lease agreements include fixed rate renewal periods, which give APS the ability to utilize the assets for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

	On July 7, 2014, APS notified the lessor trust entities of APS’s intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make lease payments of approximately $23 million annually for the period 2016 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

	As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for 2014, 2013 and 2012 of $26 million, $34 million and $32 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. The July 7, 2014 lease extension results in the VIEs accounting for the transaction as a new lease agreement. Consolidation of these VIEs also results in changes to our Consolidated Statements of Cash Flows, but does not impact net cash flows.

	Our Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):



		31-Dec-14		31-Dec-13
	Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	121	$	125

	Current maturities of long-term debt	13		26

	Long-term debt excluding current maturities	—		13

	Equity-Noncontrolling interests	152		146


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

	APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Palo Verde Unit 2 interests which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2014, APS would have been required to pay the noncontrolling equity participants approximately $123 million and assume $13 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Consolidated Balance Sheets.

	For regulatory ratemaking purposes, the leases are treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

Nuclear_Decommissioning_Trusts

Nuclear Decommissioning Trusts	12 Months Ended
	Dec. 31, 2014
Investments, Debt and Equity Securities [Abstract]
Nuclear Decommissioning Trusts	Nuclear Decommissioning Trusts

	To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2014 and December 31, 2013 (dollars in millions):



		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	31-Dec-14

	Equity securities	$	310		$	159		$	—

	Fixed income securities	411			17			(1		)

	Net payables (a)	(7		)	—			—

	Total	$	714		$	176		$	(1	)




		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	31-Dec-13

	Equity securities	$	272		$	129		$	—

	Fixed income securities	373			11			(6		)

	Net payables (a)	(3		)	—			—

	Total	$	642		$	140		$	(6	)



	(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 millions):



		Year Ended December 31,
		2014			2013			2012
	Realized gains	$	5		$	6		$	7

	Realized losses	(5		)	(7		)	(4		)
	Proceeds from the sale of securities (a)	356			446			418



	(a)	Proceeds are reinvested in the trust.

	The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2014 is as follows (dollars in millions):



		Fair Value
	Less than one year	$	14

	1 year – 5 years	116

	5 years – 10 years	122

Greater than 10 years	159

Total	$	411

Changes_in_Accumulated_Other_C

Changes in Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2014
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Changes in Accumulated Other Comprehensive Loss	Changes in Accumulated Other Comprehensive Loss

	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands):


		Year Ended December 31, 2014
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(23,058	)		$	(54,995	)		$	(78,053	)
	OCI (loss) before reclassifications	(810		)		(5,419		)		(6,229		)
	Amounts reclassified from accumulated other comprehensive loss	13,483			(a)	2,658			(b)	16,141

	Net current period OCI (loss)	12,673				(2,761		)		9,912

	Ending balance	$	(10,385	)		$	(57,756	)		$	(68,141	)


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

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

	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):


		Year Ended December 31, 2013
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(49,592	)		$	(64,416	)		$	(114,008	)
	OCI (loss) before reclassifications	(213		)		5,594				5,381

	Amounts reclassified from accumulated other comprehensive loss	26,747			(a)	3,827			(b)	30,574

	Net current period OCI	26,534				9,421				35,955

	Ending balance	$	(23,058	)		$	(54,995	)		$	(78,053	)


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

	(b)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Changes in Accumulated Other Comprehensive Loss	Changes in Accumulated Other Comprehensive Loss

	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands):


		Year Ended December 31, 2014
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(23,059	)		$	(30,313	)		$	(53,372	)
	OCI (loss) before reclassifications	(809		)		(10,415		)		(11,224		)
	Amounts reclassified from accumulated other comprehensive loss	13,483			(a)	2,780			(b)	16,263

	Net current period OCI (loss)	12,674				(7,635		)		5,039

	Ending balance	$	(10,385	)		$	(37,948	)		$	(48,333	)


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

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

	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):


		Year Ended December 31, 2013
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(49,592	)		$	(39,503	)		$	(89,095	)
	OCI (loss) before reclassifications	(214		)		5,387				5,173

	Amounts reclassified from accumulated other comprehensive loss	26,747			(a)	3,803			(b)	30,550

	Net current period OCI	26,533				9,190				35,723

	Ending balance	$	(23,059	)		$	(30,313	)		$	(53,372	)


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

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

SCHEDULE_I_CONDENSED_FINANCIAL

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
CONDENSED FINANCIAL INFORMATION OF REGISTRANT

		Year Ended December 31,
		2014				2013				2012
	Operating revenues	$	642			$	799			$	6,133

	Operating expenses	23,507				24,930				12,125

	Operating loss	(22,865		)		(24,131		)		(5,992		)
	Other

	Equity in earnings of subsidiaries	411,528				420,926				391,528

	Other expense	(3,276		)		(1,999		)		(2,001		)
	Total	408,252				418,927				389,527

	Interest expense	3,663				3,226				4,868

	Income from continuing operations	381,724				391,570				378,667

	Income tax benefit	(15,871		)		(14,504		)		(7,079		)
	Income from continuing operations — net of income taxes	397,595				406,074				385,746

	Loss from discontinued operations — net of income taxes	—				—				(4,204		)

	Net income attributable to common shareholders	397,595				406,074				381,542

	Other comprehensive income — attributable to common shareholders	9,912				35,955				38,155

	Total comprehensive income — attributable to common shareholders	$	407,507			$	442,029			$	419,697



		December 31,
		2014				2013
	ASSETS

	Current assets

	Cash and cash equivalents	$	3,088			$	5,798

	Accounts receivable	99,958				80,108

	Current deferred income taxes	66,979				93,185

	Income tax receivable	7,329				1,853

	Other current assets	124				242

	Total current assets	177,478				181,186

	Investments and other assets

	Investments in subsidiaries	4,630,570				4,455,049

	Other assets	43,051				13,789

	Total investments and other assets	4,673,621				4,468,838

	Total Assets	$	4,851,099			$	4,650,024

	LIABILITIES AND EQUITY

	Current liabilities

Accounts payable	$	5,250			$	3,279

Accrued taxes	12,220				8,538

Common dividends payable	65,790				62,528

Other current liabilities	38,992				31,295

Total current liabilities	122,252				105,640

Long-term debt less current maturities	125,000				125,000

Deferred credits and other

Deferred income taxes	12,055				4,158

Pension and other postretirement liabilities	29,228				37,611

Other	43,462				37,155

Total deferred credits and other	84,745				78,924

Common stock equity

Common stock	2,509,569				2,487,250

Accumulated other comprehensive loss	(68,141		)		(78,053		)
Retained earnings	1,926,065				1,785,273

Total Pinnacle West Shareholders’ equity	4,367,493				4,194,470

Noncontrolling interests	151,609				145,990

Total Equity	4,519,102				4,340,460

Total Liabilities and Equity	$	4,851,099			$	4,650,024



	Year Ended December 31,
	2014				2013				2012
Cash flows from operating activities

Net income	$	397,595			$	406,074			$	381,542

Adjustments to reconcile net income to net cash provided by operating activities:

Equity in earnings of subsidiaries — net	(411,528		)		(420,926		)		(391,528		)
Depreciation and amortization	94				95				94

Deferred income taxes	4,406				(28,806		)		(15,135		)

Accounts receivable	(22,945		)		21,671				28,763

Accounts payable	2,017				(2,449		)		879

Accrued taxes and income tax receivables — net	(1,795		)		1,402				(3,103		)

Dividends received from subsidiaries	253,600				242,100				222,200

Other	18,432				(15,065		)		(4,589		)

Net cash flow provided by operating activities	239,876				204,096				219,123

Cash flows from investing activities

Investments in subsidiaries	(10,236		)		(3,400		)		—

Repayments of loans from subsidiaries	322				2,149				996

Advances of loans to subsidiaries	(1,450		)		(2,099		)		(1,200		)
Net cash flow used for investing activities	(11,364		)		(3,350		)		(204		)
Cash flows from financing activities

Issuance of long-term debt	125,000				—				125,000

Dividends paid on common stock	(246,671		)		(235,244		)		(225,075		)
Repayment of long-term debt	(125,000		)		—				(125,000		)

Common stock equity issuance	15,288				17,319				15,955

Other	161				298				170

Net cash flow used for financing activities	(231,222		)		(217,627		)		(208,950		)
Net increase (decrease) in cash and cash equivalents	(2,710		)		(16,881		)		9,969

Cash and cash equivalents at beginning of year	5,798				22,679				12,710

Cash and cash equivalents at end of year	$	3,088			$	5,798			$	22,679

SCHEDULE_II_RESERVE_FOR_UNCOLL

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	12 Months Ended
	Dec. 31, 2014
Reserve for uncollectibles
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

	Column A	Column B			Column C						Column D			Column E
					Additions
	Description	Balance at			Charged to			Charged			Deductions			Balance
		beginning			cost and			to other						at end of
		of period			expenses			accounts						period
	Reserve for uncollectibles:

	2014	$	3,203		$	3,942		$	—		$	4,051		$	3,094

	2013	3,340			4,923			—			5,060			3,203

	2012	3,748			5,290			—			5,698			3,340

ARIZONA PUBLIC SERVICE COMPANY
Reserve for uncollectibles
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

	Column A		Column B			Column C						Column D			Column E
						Additions
	Description		Balance at			Charged to			Charged			Deductions			Balance
			beginning			cost and			to other						at end of
			of period			expenses			accounts						period
	Reserve for uncollectibles:

	2014		$	3,203		$	3,942		$	—		$	4,051		$	3,094

	2013		3,340			4,923			—			5,060			3,203

	2012		3,748			5,290			—			5,698			3,340

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Description of Business and Basis of Presentation	Description of Business and Basis of Presentation

	Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE, and formerly SunCor. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a new subsidiary formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. SunCor was a developer of residential, commercial and industrial real estate projects and essentially all of these assets were sold in 2009 and 2010. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. All activities for SunCor are reported as discontinued operations.

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

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

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

	Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulatory Accounting	Regulatory Accounting

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

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

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

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

	For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 3). Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.

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

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

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


	•	material and labor;

	•	contractor costs;

	•	capitalized leases;

	•	construction overhead costs (where applicable); and

	•	allowance for funds used during construction.

	We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 11.

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

	We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2014 were as follows:

	•Fossil plant — 19 years;
	•Nuclear plant — 28 years;
	•Other generation — 25 years;
	•Transmission — 38 years;
	•Distribution — 33 years; and
	•Other — 7 years.

	Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. See Note 3 for further discussion. These costs were deferred and will be amortized on the depreciation line of the Consolidated Statements of Income.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction

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

	AFUDC was calculated by using a composite rate of 8.47% for 2014, 8.56% for 2013, and 8.60% for 2012. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Materials and Supplies	Materials and Supplies

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

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

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

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

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

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

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

	Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Retirement Plans and Other Benefits	Retirement Plans and Other Benefits

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

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

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

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

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

	We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives.
Investments	Investments

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

	Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities.
Business Segments	Business Segments

	Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.
New accounting pronouncements	During 2014, we adopted, on a prospective basis, new guidance relating to the presentation of unrecognized tax benefits. This guidance generally requires entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. Prior to adopting this guidance, we presented unrecognized tax benefits on a gross basis. The adoption of this new guidance changed our balance sheet presentation of unrecognized tax benefits, but did not impact our operating results or cash flows. See Note 4 for details regarding the impacts of adopting this guidance.

	In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The new guidance is effective for us on January 1, 2017, and may be adopted using full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We are currently evaluating this new guidance and the impacts it may have on our financial statements.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of supplemental cash flow information	The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):



		Year ended December 31,
		2014			2013		2012
	Cash paid (received) during the period for:

	Income taxes, net of refunds	$	(102,154	)	$	18,537	$	2,543

	Interest, net of amounts capitalized	177,074			184,010		200,923

	Significant non-cash investing and financing activities:

	Accrued capital expenditures	$	44,712		$	33,184	$	26,208

	Dividends declared but not paid	65,790			62,528		59,789

	Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)	—			145,609		—

Regulatory_Matters_Tables

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Schedule of changes in the deferred fuel and purchased power regulatory asset	The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions):



		Year Ended December 31,
		2014				2013
	Beginning balance	$	21			$	73

	Deferred fuel and purchased power costs - current period	27				(21		)

	Amounts charged to customers	(41		)		(31		)
	Ending balance	$	7			$	21

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


		Remaining		31-Dec-14						31-Dec-13
		Amortization
		Period		Current				Non-Current		Current		Non-Current
	Pension and other postretirement benefits	(a)		$	—			$	485	$	—	$	314

	Income taxes — AFUDC equity	2044		5				118		4		105

	Deferred fuel and purchased power — mark-to-market (Note 16)	2017		51				46		5		29

	Transmission vegetation management	2016		9				5		9		14

	Coal reclamation	2026		—				7		8		18

	Palo Verde VIEs (Note 18)	2046		—				35		—		41

	Deferred compensation	2036		—				34		—		34

	Deferred fuel and purchased power (b) (c)	2015		7				—		21		—

	Tax expense of Medicare subsidy	2024		2				14		2		15

	Loss on reacquired debt	2034		1				16		1		17

	Income taxes — investment tax credit basis adjustment	2044		2				46		1		39

	Pension and other postretirement benefits deferral	2015		4				—		8		4

	Four Corners cost deferral	2024		7				70		—		37

	Lost fixed cost recovery	2015		38				—		25		—

	Transmission cost adjustor	2014		—				—		8		2

	Retired power plant costs	2033		10				136		3		18

	Deferred property taxes	(d)		—				30		—		11

	Other	Various		2				12		2		14

	Total regulatory assets (e)			$	138			$	1,054	$	97	$	712



	(a)	This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. See Note 7 for further discussion.

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

	(c)	Subject to a carrying charge.

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

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


		Remaining		31-Dec-14						31-Dec-13
		Amortization
		Period		Current				Non-Current		Current		Non-Current
	Removal costs	(a)		$	31			$	273	$	28	$	303

	Asset retirement obligations	2044		—				296		—		266

	Renewable energy standard (b)	2017		25				23		33		15

	Income taxes — change in rates	2043		—				72		—		74

	Spent nuclear fuel	2047		5				66		6		36

	Deferred gains on utility property	2019		2				8		2		10

	Income taxes — deferred investment tax credit	2043		4				93		3		79

	Demand side management (b)	2015		31				—		27		—

	Other postretirement benefits	(c)		32				199		—		—

	Other	Various		1				21		—		18

	Total regulatory liabilities			$	131			$	1,051	$	99	$	801



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

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

	(c)	See Note 7.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax [Line Items]
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year	The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):


		2014			2013			2012
	Total unrecognized tax benefits, January 1	$	41,997		$	133,422		$	136,005

	Additions for tax positions of the current year	4,309			3,516			5,167

	Additions for tax positions of prior years	751			13,158			—

	Reductions for tax positions of prior years for:

	Changes in judgment	(2,282		)	(108,099		)	(7,729		)
	Settlements with taxing authorities	—			—			—

	Lapses of applicable statute of limitations	—			—			(21		)

	Total unrecognized tax benefits, December 31	$	44,775		$	41,997		$	133,422

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


		Year Ended December 31,
		2014			2013			2012
	Current:

	Federal	$	25,054		$	(81,784	)	$	(3,493	)

	State	10,382			10,537			8,395

	Total current	35,436			(71,247		)	4,902

	Deferred:

	Federal	167,365			279,973			200,322

	State	17,904			21,865			28,280

	Total deferred	185,269			301,838			228,602

	Total income tax expense	220,705			230,591			233,504

	Less: income tax benefit on discontinued operations	—			—			(3,813		)

	Income tax expense — continuing operations	$	220,705		$	230,591		$	237,317

Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
	The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):



		Year Ended December 31,
		2014			2013			2012
	Federal income tax expense at 35% statutory rate	$	225,540		$	234,695		$	229,709

	Increases (reductions) in tax expense resulting from:

	State income tax net of federal income tax benefit	18,149			21,387			23,819

	Credits and favorable adjustments related to prior years resolved in current year	—			(3,356		)	—

	Medicare Subsidy Part-D	830			823			483

	Allowance for equity funds used during construction (see Note 1)	(8,523		)	(6,997		)	(6,158		)
	Palo Verde VIE noncontrolling interest (see Note 18)	(9,135		)	(11,862		)	(11,065		)
	Investment tax credit amortization	(4,928		)	(3,548		)	(2,030		)
	Other	(1,228		)	(551		)	2,559

	Income tax expense — continuing operations	$	220,705		$	230,591		$	237,317

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


		December 31,
		2014			2013
	Current asset	$	122,232		$	91,152

	Long-term liability	(2,582,636		)	(2,351,882		)
	Deferred income taxes — net	$	(2,460,404	)	$	(2,260,730	)
Components of the net deferred income tax liability	The components of the net deferred income tax liability were as follows (dollars in thousands):



		December 31,
		2014			2013
	DEFERRED TAX ASSETS

	Risk management activities	$	57,505		$	44,920

	Regulatory liabilities:

	Asset retirement obligation and removal costs	229,772			235,959

	Unamortized investment tax credits	96,232			82,116

	Other postretirement benefits	90,496			—

	Other	60,409			42,609

	Pension liabilities	205,227			140,773

	Other postretirement liabilities	—			57,869

	Renewable energy incentives	65,169			65,434

	Credit and loss carryforwards	68,347			133,070

	Other	138,729			148,492

	Total deferred tax assets	1,011,886			951,242

	DEFERRED TAX LIABILITIES

	Plant-related	(2,958,369		)	(2,903,730		)
	Risk management activities	(12,171		)	(16,191		)
	Other postretirement assets	(59,170		)	—

	Regulatory assets:

	Allowance for equity funds used during construction	(48,286		)	(43,058		)
	Deferred fuel and purchased power	(2,498		)	(8,282		)
	Deferred fuel and purchased power — mark-to-market	(38,187		)	(13,343		)
	Pension and other postretirement benefits	(191,747		)	(129,250		)
	Retired power plant costs (see Note 3)	(57,255		)	(8,199		)
	Other	(99,123		)	(85,003		)
	Other	(5,484		)	(4,916		)
	Total deferred tax liabilities	(3,472,290		)	(3,211,972		)
	Deferred income taxes — net	$	(2,460,404	)	$	(2,260,730	)
ARIZONA PUBLIC SERVICE COMPANY
Income Tax [Line Items]
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year	The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):



		2014			2013			2012
	Total unrecognized tax benefits, January 1	$	41,997		$	133,241		$	135,824

	Additions for tax positions of the current year	4,309			3,516			5,167

	Additions for tax positions of prior years	751			13,158			—

	Reductions for tax positions of prior years for:

	Changes in judgment	(2,282		)	(107,918		)	(7,729		)
	Settlements with taxing authorities	—			—			—

	Lapses of applicable statute of limitations	—			—			(21		)

	Total unrecognized tax benefits, December 31	$	44,775		$	41,997		$	133,241

Components of income tax expense	The components of APS’s income tax expense are as follows (dollars in thousands):


		Year Ended December 31,
		2014			2013			2012
	Current:

	Federal	$	40,115		$	(97,531	)	$	(11,650	)

	State	15,598			11,983			12,308

	Total current	55,713			(85,548		)	658

	Deferred:

	Federal	165,027			305,389			216,367

	State	16,620			25,254			27,371

	Total deferred	181,647			330,643			243,738

	Total income tax expense	$	237,360		$	245,095		$	244,396

Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations	The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):


		Year Ended December 31,
		2014			2013			2012
	Federal income tax expense at 35% statutory rate	$	239,638		$	246,384		$	235,027

	Increases (reductions) in tax expense resulting from:

	State income tax net of federal income tax benefit	21,148			23,970			25,379

	Credits and favorable adjustments related to prior years resolved in current year	—			(3,231		)	—

	Medicare Subsidy Part-D	830			823			483

	Allowance for equity funds used during construction (see Note 1)	(8,523		)	(6,997		)	(6,158		)
	Palo Verde VIE noncontrolling interest (see Note 18)	(9,135		)	(11,862		)	(11,065		)
	Investment tax credit amortization	(4,928		)	(3,548		)	(2,030		)
	Other	(1,670		)	(444		)	2,760

	Income tax expense	$	237,360		$	245,095		$	244,396

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


		December 31,
		2014			2013
	Current asset (liability)	$	55,253		$	(2,033	)

	Long-term liability	(2,571,365		)	(2,347,724		)
	Deferred income taxes — net	$	(2,516,112	)	$	(2,349,757	)
Components of the net deferred income tax liability	The components of the net deferred income tax liability were as follows (dollars in thousands):



		December 31,
		2014			2013
	DEFERRED TAX ASSETS

	Regulatory liabilities:

	Asset retirement obligation and removal costs	$	229,772		$	235,959

	Unamortized investment tax credits	96,232			82,116

	Other postretirement benefits	90,496			—

	Other	60,409			42,609

	Risk management activities	57,505			44,920

	Pension liabilities	194,541			132,263

	Other postretirement liabilities	—			53,950

	Renewable energy incentives	65,169			65,434

	Credit and loss carryforwards	—			38,183

	Other	161,379			166,781

	Total deferred tax assets	955,503			862,215

	DEFERRED TAX LIABILITIES

	Plant-related	(2,958,369		)	(2,903,730		)
	Risk management activities	(12,171		)	(16,191		)
	Other postretirement benefit assets	(58,495		)	—

	Regulatory assets:

	Allowance for equity funds used during construction	(48,286		)	(43,058		)
	Deferred fuel and purchased power	(2,498		)	(8,282		)
	Deferred fuel and purchased power — mark-to-market	(38,187		)	(13,343		)
	Pension and other postretirement benefits	(191,747		)	(129,250		)
	Retired power plant costs (see Note 3)	(57,255		)	(8,199		)
	Other	(99,123		)	(85,003		)
	Other	(5,484		)	(4,916		)
	Total deferred tax liabilities	(3,471,615		)	(3,211,972		)
	Deferred income taxes — net	$	(2,516,112	)	$	(2,349,757	)

Lines_of_Credit_and_ShortTerm_1

Lines of Credit and Short-Term Borrowings (Tables)	12 Months Ended
	Dec. 31, 2014
Lines of Credit and Short-Term Borrowings
Schedule of consolidated credit facilities and amounts available and outstanding	The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2014 (dollars in millions):



	Credit Facility		Expiration	Amount		Unused		Commitment
				Committed		Amount (a)		Fees
	Pinnacle West Revolving Credit Facility		May-19	$	200	$	200	0.175	%

	APS Revolving Credit Facility		May-19	500		500		0.125	%

	APS Revolving Credit Facility		April 2018	500		353		0.125	%

	Total			$	1,200	$	1,053



	(a)	At December 31, 2014, APS had $147 million of outstanding commercial paper. Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $853 million.
	The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2013 (dollars in millions):



	Credit Facility		Expiration	Amount		Unused		Commitment
				Committed		Amount (a)		Fees
	Pinnacle West Revolving Credit Facility		November 2016	$	200	$	200	0.175	%

	APS Revolving Credit Facility		November 2016	500		347		0.125	%

	APS Revolving Credit Facility		Apr-18	500		500		0.125	%

	Total			$	1,200	$	1,047



	(a)	At December 31, 2013, APS had $153 million of outstanding commercial paper. Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $847 million.

LongTerm_Debt_and_Liquidity_Ma1

Long-Term Debt and Liquidity Matters (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Components of long-term debt on the Consolidated Balance Sheets	The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2014 and 2013 (dollars in thousands):


		Maturity		Interest	December 31,
		Dates (a)		Rates	2014			2013
	APS

	Pollution Control Bonds:

	Variable	2029-2038		(b)	$	156,405		$	75,580

	Fixed	2024-2034		0.45%-5.75%	249,300			426,125

	Total Pollution Control Bonds				405,705			501,705

	Senior unsecured notes	2015-2044		3.35%-8.75%	2,875,000			2,675,000

	Palo Verde sale leaseback lessor notes	2015		8.00%	13,420			38,869

	Unamortized discount				(9,206		)	(8,732		)
	Unamortized premium				4,866			5,047

	Total APS long-term debt				3,289,785			3,211,889

	Less current maturities	(d)			383,570			540,424

	Total APS long-term debt less current maturities				2,906,215			2,671,465

	Pinnacle West

	Term loan	2017		(c)	125,000			125,000

	TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES				$	3,031,215		$	2,796,465


	(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.
	(b) The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.27% at December 31, 2014 and 0.03%-0.06% at December 31, 2013.
	(c) The weighted-average interest rate was 1.019% at December 31, 2014 and 1.269% at December 31, 2013.
	(d) Current maturities include $70 million of pollution control bonds expected to be remarketed in 2015 and $300 million in senior unsecured notes that mature in 2015.
Principal payments due on Pinnacle West's and APS's total long-term debt	The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in millions):


	Year		Consolidated			Consolidated
			Pinnacle West			APS
	2015		$	384		$	384

	2016		357			357

	2017		157			32

	2018		32			32

	2019		500			500

	Thereafter		1,989			1,989

	Total		$	3,419		$	3,294

Schedule of estimated fair value of long-term debt, including current maturities	The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):



		As of						As of
		31-Dec-14						31-Dec-13
		Carrying			Fair Value			Carrying			Fair Value
		Amount						Amount
	Pinnacle West	$	125		$	125		$	125		$	125

	APS	3,290			3,714			3,212			3,454

	Total	$	3,415		$	3,839		$	3,337		$	3,579

Retirement_Plans_and_Other_Ben1

Retirement Plans and Other Benefits (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)	The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):


		Pension												Other Benefits
		2014				2013				2012				2014				2013			2012
	Service cost-benefits earned during the period	$	53,080			$	64,195			$	63,502			$	18,139			$	23,597		$	27,163

	Interest cost on benefit obligation	129,194				112,392				119,586				41,243				41,536			46,467

	Expected return on plan assets	(158,998		)		(146,333		)		(140,979		)		(46,400		)		(45,717		)	(45,793		)
	Amortization of:

	Transition obligation	—				—				—				—				—			452

	Prior service cost (credit)	869				1,097				1,143				(9,626		)		(179		)	(179		)

	Net actuarial loss	10,963				39,852				44,250				1,175				11,310			20,233

	Net periodic benefit cost	$	35,108			$	71,203			$	87,502			$	4,531			$	30,547		$	48,343

	Portion of cost charged to expense	$	21,985			$	38,968			$	36,333			$	6,000			$	18,469		$	19,321

Schedule of changes in the benefit obligations and funded status	The following table shows the plans’ changes in the benefit obligations and funded status for the years 2014 and 2013 (dollars in thousands):


		Pension								Other Benefits
		2014				2013				2014				2013
	Change in Benefit Obligation

	Benefit obligation at January 1	$	2,646,530			$	2,850,846			$	890,418			$	990,418

	Service cost	53,080				64,195				18,139				23,597

	Interest cost	129,194				112,392				41,243				41,536

	Benefit payments	(128,550		)		(125,269		)		(29,054		)		(26,675		)
	Actuarial (gain) loss	378,394				(255,634		)		150,188				(138,458		)

	Plan amendments	—				—				(388,599		)		—

	Benefit obligation at December 31	3,078,648				2,646,530				682,335				890,418

	Change in Plan Assets

	Fair value of plan assets at January 1	2,264,121				2,079,181				748,339				684,221

	Actual return on plan assets	292,992				150,546				105,223				76,995

	Employer contributions	175,000				140,500				770				14,438

	Benefit payments	(116,709		)		(106,106		)		(19,707		)		(27,315		)
	Fair value of plan assets at December 31	2,615,404				2,264,121				834,625				748,339

	Funded Status at December 31	$	(463,244	)		$	(382,409	)		$	152,290			$	(142,079	)

Schedule of projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets	The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2014 and 2013 (dollars in thousands):


		2014				2013
	Projected benefit obligation	$	3,078,648			$	2,646,530

	Accumulated benefit obligation	2,873,741				2,469,889

	Fair value of plan assets	2,615,404				2,264,121

Schedule of amounts recognized on the Consolidated Balance Sheets	The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2014 and 2013 (dollars in thousands):


		Pension								Other Benefits
		2014				2013				2014				2013
	Noncurrent asset	$	—			$	—			$	152,290			$	—

	Current liability	(9,508		)		(10,860		)		—				—

	Noncurrent liability	(453,736		)		(371,549		)		—				(142,079		)

	Net amount recognized	$	(463,244	)		$	(382,409	)		$	152,290			$	(142,079	)

Schedule of accumulated other comprehensive loss	The following table shows the details related to accumulated other comprehensive loss as of December 31, 2014 and 2013 (dollars in thousands):


		Pension								Other Benefits
		2014				2013				2014				2013
	Net actuarial loss	$	577,976			$	344,540			$	148,006			$	57,816

	Prior service cost (credit)	1,203				2,072				(379,269		)		(296		)

	APS’s portion recorded as a regulatory (asset) liability	(485,037		)		(265,107		)		230,916				(49,298		)

	Income tax expense (benefit)	(36,890		)		(32,204		)		851				(2,528		)

	Accumulated other comprehensive loss	$	57,252			$	49,301			$	504			$	5,694

Schedule of estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost	The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2015 (dollars in thousands):


		Pension				Other
						Benefits
	Net actuarial loss	$	28,180			$	5,651

	Prior service cost (credit)	595				(37,968		)

	Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2014	$	28,775			$	(32,317	)

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


		Benefit Obligations						Benefit Costs
		As of December 31,						For the Years Ended December 31,
		2014			2013			2014					2013			2012
								January - September		October - December
	Discount rate – pension	4.02	%		4.88	%		4.88	%	4.88	%		4.01	%		4.42	%
	Discount rate – other benefits	4.14	%		5.1	%		5.1	%	4.41	%		4.2	%		4.59	%
	Rate of compensation increase	4	%		4	%		4	%	4	%		4	%		4	%
	Expected long-term return on plan assets - pension	N/A			N/A			6.9	%	6.9	%		7	%		7.75	%

	Expected long-term return on plan assets - other benefits	N/A			N/A			6.8	%	4.25	%		7	%		7.75	%

	Initial healthcare cost trend rate (pre-65 participants)	7	%		7.5	%		7.5	%	7.5	%		7.5	%		7.5	%
	Initial healthcare cost trend rate (post-65 participants)	5	%		7.5	%		7.5	%	5	%		7.5	%		7.5	%
	Ultimate healthcare cost trend rate	5	%		5	%		5	%	5	%		5	%		5	%
	Number of years to ultimate trend rate (pre-65 participants)	4			4			4		4			4			4

	Number of years to ultimate trend rate (post-65 participants)	0			4			4		0			4			4

Schedule of effects of one percentage point change in the assumed initial and ultimate health care cost trend rates	A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in millions):


		1% Increase				1% Decrease
	Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	10			$	(4	)

	Effect on service and interest cost components of net periodic other postretirement benefit costs	12				(9		)

	Effect on the accumulated other postretirement benefit obligation	110				(88		)

Schedule of fair value of pension plan and other postretirement benefit plan assets, by asset category	The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2014, by asset category, are as follows (dollars in thousands):



		Quoted Prices				Significant				Significant				Other (b)				Balance at December 31, 2014
		in Active				Other				Unobservable
		Markets for				Observable				Inputs
		Identical				Inputs				(Level 3)
		Assets				(Level 2)
		(Level 1)
	Pension Plan:

	Assets:

	Cash and cash equivalents	$	387			$	—			$	—			$	—			$	387

	Fixed Income Securities:

	Corporate	—				1,162,096				—				—				1,162,096

	U.S. Treasury	291,817				—				—				—				291,817

	Other (a)	—				113,265				—				—				113,265

	Equities:

	U.S. Companies	246,387				—				—				—				246,387

	International Companies	18,069				—				—				—				18,069

	Common and collective trusts:

	U.S. Equities	—				127,336				—				—				127,336

	International Equities	—				317,167				—				—				317,167

	Real estate	—				129,715				—				—				129,715

	Partnerships	—				138,337				27,929				—				166,266

	Short-term investments and other	—				26,016				—				16,883				42,899

	Total Pension Plan	$	556,660			$	2,013,932			$	27,929			$	16,883			$	2,615,404

	Other Benefits:

	Assets:

	Cash and cash equivalents	$	318			$	—			$	—			$	—			$	318

	Fixed Income Securities:

	Corporate	—				187,961				—				—				187,961

	U.S. Treasury	130,967				—				—				—				130,967

	Other (a)	—				35,291				—				—				35,291

	Equities:

	U.S. Companies	265,106				—				—				—				265,106

	International Companies	17,813				—				—				—				17,813

Common and collective trusts:

U.S. Equities	—				88,258				—				—				88,258

International Equities	—				85,746				—				—				85,746

Real Estate	—				11,657				—				—				11,657

Short-term investments and other	—				7,408				—				4,100				11,508

Total Other Benefits	$	414,204			$	416,321			$	—			$	4,100			$	834,625



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

(b)	Represents plan receivables and payables.
Schedule of changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3)	The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2013, by asset category, are as follows (dollars in thousands):


		Quoted Prices				Significant				Significant				Other (b)				Balance at December 31, 2013
		in Active				Other				Unobservable
		Markets for				Observable				Inputs
		Identical				Inputs				(Level 3)
		Assets				(Level 2)
		(Level 1)
	Pension Plan:

	Assets:

	Cash and cash equivalents	$	504			$	—			$	—			$	—			$	504

	Fixed Income Securities:

	Corporate	—				898,621				—				—				898,621

	U.S. Treasury	231,590				—				—				—				231,590

	Other (a)	—				84,011				—				—				84,011

	Equities:

	U.S. Companies	239,036				—				—				—				239,036

	International Companies	19,429				—				—				—				19,429

	Common and collective trusts:

	U.S. Equities	—				116,150				—				—				116,150

	International Equities	—				367,551				—				—				367,551

	Fixed Income	—				137,520				—				—				137,520

	Real estate	—				119,739				—				—				119,739

	Partnerships	—				—				8,660				—				8,660

	Short-term investments and other	—				41,060				—				250				41,310

	Total Pension Plan	$	490,559			$	1,764,652			$	8,660			$	250			$	2,264,121

	Other Benefits:

	Assets:

	Cash and cash equivalents

	Fixed Income Securities:

	Corporate	$	—			$	153,888			$	—			$	—			$	153,888

	U.S. Treasury	98,704				—				—				—				98,704

	Other (a)	—				27,936				—				—				27,936

	Equities:

	U.S. Companies	252,181				—				—				—				252,181

	International Companies	20,892				—				—				—				20,892

Common and collective trusts:

U.S. Equities	—				80,751				—				—				80,751

International Equities	—				92,382				—				—				92,382

Real Estate	—				10,761				—				—				10,761

Short-term investments and other	—				8,414				—				2,430				10,844

Total Other Benefits	$	371,777			$	374,132			$	—			$	2,430			$	748,339



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

(b)	Represents plan receivables and payables.
The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2014 and 2013 (dollars in thousands):


		Pension
Partnerships		2014				2013
Beginning balance at January 1		$	8,660			$	2,419

Actual return on assets still held at December 31		927				(498		)

Purchases		19,984				7,377

Sales		(1,642		)		(638		)
Transfers in and/or out of Level 3		—				—

Ending balance at December 31		$	27,929			$	8,660

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


	Year		Pension				Other Benefits
	2015		$	139,013			$	25,134

	2016		155,968				27,311

	2017		160,080				29,253

	2018		167,600				31,258

	2019		177,470				33,190

	Years 2020-2024		983,557				184,772

Leases_Tables

Leases (Tables)	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Estimated future minimum lease payments for Pinnacle West's and APS's operating leases, excluding purchased power agreements	Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions):


	Year	Pinnacle West		APS
		Consolidated
	2015	$	18	$	15

	2016	6		6

	2017	5		5

	2018	4		4

	2019	3		3

	Thereafter	63		62

	Total future lease commitments	$	99	$	95

JointlyOwned_Facilities_Tables

Jointly-Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2014
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
APS's interests in jointly-owned facilities recorded on the Consolidated Balance Sheets	The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2014 (dollars in thousands):



			Percent			Plant in		Accumulated		Construction
			Owned			Service		Depreciation		Work in
										Progress
	Generating facilities:

	Palo Verde Units 1 and 3		29.1	%		$	1,734,918	$	1,051,670	$	16,955

	Palo Verde Unit 2 (a)		16.8	%		556,472		349,960		13,710

	Palo Verde Common		28	%	(b)	612,190		224,208		68,896

	Palo Verde Sale Leaseback				(a)	351,050		229,795		—

	Four Corners Generating Station		63	%		811,648		578,772		33,150

	Navajo Generating Station Units 1, 2 and 3		14	%		272,208		159,198		2,716

	Cholla common facilities (c)		63.3	%	(b)	155,856		49,954		866

	Transmission facilities:

	ANPP 500kV System		33.6	%	(b)	106,369		35,035		3,731

	Navajo Southern System		22.5	%	(b)	59,994		18,119		1,113

	Palo Verde — Yuma 500kV System		18.2	%	(b)	12,925		4,943		12

	Four Corners Switchyards		47.5	%	(b)	33,034		10,035		386

	Phoenix — Mead System		17.1	%	(b)	39,777		12,843		105

	Palo Verde — Estrella 500kV System		50	%	(b)	89,572		16,491		736

	Morgan — Pinnacle Peak System		64.4	%	(b)	130,840		8,970		1,690

	Round Valley System		50	%	(b)	497		276		1

	Palo Verde — Morgan System		90	%	(b)	—		—		69,377

	Hassayampa - North Gila System		80	%	(b)	8,902		3,634		142,645



	(a)	See Note 18.

	(b)	Weighted-average of interests.

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

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Summary of estimated coal take-or-pay commitments	The following table summarizes our estimated coal take-or-pay commitments (dollars in millions):



		Years Ended December 31,
		2015		2016		2017		2018		2019		Thereafter
	Coal take-or-pay commitments (a)	$	151	$	171	$	195	$	190	$	194	$	2,469
	Coal take-or-pay commitments (a)	$	151	$	171	$	195	$	190	$	194	$	2,469


	(a)	Total take-or-pay commitments are approximately $3.4 billion. The total net present value of these commitments is approximately $2.2 billion.
Summary of actual take-or-pay commitments	The following table summarizes actual payments under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in millions):



		Year Ended December 31,
		2014		2013		2012
	Total payments	$	237	$	188	$	196
	Total payments	$	237	$	188	$	196

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Change in asset retirement obligations	The following schedule shows the change in our asset retirement obligations for 2014 and 2013 (dollars in millions):



		2014			2013
	Asset retirement obligations at the beginning of year	$	347		$	357

	Changes attributable to:

	Accretion expense	24			24

	Settlements	(30		)	(12		)
	Assumed SCE’s obligation	—			34

	Estimated cash flow revisions	44			(56		)

	Newly incurred obligation	6			—

	Asset retirement obligations at the end of year	$	391		$	347

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Selected Quarterly Financial Information [Line Items]
Schedule of quarterly financial information	Consolidated quarterly financial information for 2014 and 2013 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.



		2014 Quarter Ended								2014
		March 31,		June 30,		Sept. 30,		Dec. 31,		Total
	Operating revenues	$	686,251	$	906,264	$	1,172,667	$	726,450	$	3,491,632

	Operations and maintenance	212,882		211,222		223,418		260,503		908,025

	Operating income	75,170		254,113		421,775		60,184		811,242

	Income taxes	6,405		74,540		134,753		5,007		220,705

	Income from continuing operations	24,691		141,384		248,086		9,535		423,696

	Net income attributable to common shareholders	15,766		132,458		243,961		5,410		397,595


	Earnings Per Share:

	Net income attributable to common shareholders — Basic	$	0.14	$	1.2	$	2.2	$	0.05	$	3.59

	Net income attributable to common shareholders — Diluted	0.14		1.19		2.2		0.05		3.58




		2013 Quarter Ended								2013
		March 31,		June 30,		Sept. 30,		Dec. 31,		Total
	Operating revenues	$	686,652	$	915,822	$	1,152,392	$	699,762	$	3,454,628

	Operations and maintenance	223,250		229,300		233,323		238,854		924,727

	Operating income	86,923		259,812		415,688		83,900		846,323

	Income taxes	12,469		77,043		131,912		9,167		230,591

	Income from continuing operations	32,836		139,598		234,718		32,814		439,966

	Net income attributable to common shareholders	24,444		131,207		226,163		24,260		406,074


	Earnings Per Share:

	Net income attributable to common shareholders — Basic	$	0.22	$	1.19	$	2.06	$	0.22	$	3.69

	Net income attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66

ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Schedule of quarterly financial information	Quarterly financial information for 2014 and 2013 is as follows (dollars in thousands):



		2014 Quarter Ended,								2014
		March 31,		June 30,		September 30,		December 31,		Total
	Operating revenues	$	685,545	$	905,578	$	1,172,190	$	725,633	$	3,488,946

	Operations and maintenance	208,285		208,059		212,430		253,668		882,442

	Operating income	69,635		180,394		287,928		54,835		592,792

	Net income attributable to common shareholder	19,518		134,916		251,047		15,738		421,219




		2013 Quarter Ended,								2013
		March 31,		June 30,		September 30,		December 31,		Total
	Operating revenues	$	685,827	$	915,065	$	1,151,535	$	698,824	$	3,451,251

	Operations and maintenance	220,752		224,950		222,617		229,505		897,824

	Operating income	74,862		183,728		284,251		79,024		621,865

	Net income attributable to common shareholder	26,042		133,949		234,954		30,024		424,969

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities that are measured at fair value on a recurring basis	The following table presents the fair value at December 31, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):



		Quoted Prices				Significant				Significant				Other						Balance at December 31, 2014
		in Active				Other				Unobservable
		Markets for				Observable				Inputs (a)
		Identical				Inputs				(Level 3)
		Assets				(Level 2)
		(Level 1)
	Assets

	Risk management activities — derivative instruments:

	Commodity Contracts	$	—			$	21			$	33			$	(23	)		(b)		$	31

	Nuclear decommissioning trust:

	U.S. commingled equity funds	—				310				—				—						310

	Fixed income securities:

	U.S. Treasury	119				—				—				—						119

	Cash and cash equivalent funds	—				11				—				(7		)		(c)		4

	Corporate debt	—				109				—				—						109

	Mortgage-backed securities	—				89				—				—						89

	Municipality bonds	—				69				—				—						69

	Other	—				14				—				—						14

	Subtotal nuclear decommissioning trust	119				602				—				(7		)				714

	Total	$	119			$	623			$	33			$	(30	)				$	745

	Liabilities

	Risk management activities — derivative instruments:

	Commodity contracts	$	—			$	(95	)		$	(74	)		$	59			(b)		$	(110	)



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

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

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


	The following table presents the fair value at December 31, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):



		Quoted Prices				Significant				Significant				Other						Balance at December 31, 2013
		in Active				Other				Unobservable
		Markets for				Observable				Inputs (a)
		Identical				Inputs				(Level 3)
		Assets				(Level 2)
		(Level 1)
	Assets

Risk management activities — derivative instruments:

Commodity Contracts	$	—			$	9			$	41			$	(9	)		(b)		$	41

Nuclear decommissioning trust:

U.S. commingled equity funds	—				272				—				—						272

Fixed income securities:

U.S. Treasury	107				—				—				—						107

Cash and cash equivalent funds	—				11				—				(3		)		(c)		8

Corporate debt	—				88				—				—						88

Mortgage-backed securities	—				85				—				—						85

Municipality bonds	—				71				—				—						71

Other	—				11				—				—						11

Subtotal nuclear decommissioning trust	107				538				—				(3		)				642

Total	$	107			$	547			$	41			$	(12	)				$	683

Liabilities

Risk management activities — derivative instruments:

Commodity contracts	$	—			$	(33	)		$	(90	)		$	21			(b)		$	(102	)



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

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

(c)	Represents nuclear decommissioning trust net pending securities sales and purchases.
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 December 31, 2014 and December 31, 2013:



		31-Dec-14								Valuation Technique		Significant Unobservable Input		Range		Weighted-Average
		Fair Value (millions)
	Commodity Contracts	Assets				Liabilities
	Electricity:

	Forward Contracts (a)	$	30			$	56			Discounted cash flows		Electricity forward price (per MWh)		$19.51 - $56.72		$	35.27

	Option Contracts (b)	—				15				Option model		Electricity forward price (per MWh)		$32.14 - $66.09		$	45.83

												Natural gas forward price (per MMbtu)		$3.18 - $3.29		$	3.25

												Electricity price volatilities		23% - 63%		41		%

												Natural gas price volatilities		23% - 41%		31		%

	Natural Gas:

	Forward Contracts (a)	3				3				Discounted cash flows		Natural gas forward price (per MMbtu)		$2.98 - $4.13		$	3.45

	Total	$	33			$	74



	(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.



		31-Dec-13								Valuation Technique		Significant Unobservable Input		Range		Weighted-Average
		Fair Value (millions)
	Commodity Contracts	Assets				Liabilities
	Electricity:

	Forward Contracts (a)	$	40			$	66			Discounted cash flows		Electricity forward price (per MWh)		$24.89 - $65.04		$	41.09

	Option Contracts (b)	—				19				Option model		Electricity forward price (per MWh)		$39.91 - $85.41		$	58.7

												Natural gas forward price (per MMbtu)		$3.57 - $3.80		$	3.71

												Electricity price volatilities		35% - 94%		59		%

												Natural gas price volatilities		22% - 36%		27		%

	Natural Gas:

	Forward Contracts (a)	1				5				Discounted cash flows		Natural gas forward price (per MMbtu)		$3.47 - $4.31		$	3.87

	Total	$	41			$	90



	(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 years ended December 31, 2014 and 2013 (dollars in millions):



			Year Ended
			December 31,
	Commodity Contracts		2014				2013
	Net derivative balance at beginning of period		$	(49	)		$	(48	)
	Total net gains (losses) realized/unrealized:

	Included in earnings		—				—

	Included in OCI		—				—

	Deferred as a regulatory asset or liability		—				(10		)

	Settlements		12				10

	Transfers into Level 3 from Level 2		(2		)		—

	Transfers from Level 3 into Level 2		(2		)		(1		)
	Net derivative balance at end of period		$	(41	)		$	(49	)
	Net unrealized gains included in earnings related to instruments still held at end of period		$	—			$	—

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of earnings per weighted average common share outstanding	The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per share amounts):


		2014		2013		2012
	Income from continuing operations attributable to common shareholders	$	397,595	$	406,074	$	387,380

	Weighted average common shares outstanding — basic	110,626		109,984		109,510

	Net effect of dilutive securities:

	Contingently issuable performance shares and restricted stock units	552		822		1,017

	Weighted average common shares outstanding — diluted	111,178		110,806		110,527

	Earnings per average common share outstanding:
	Income from continuing operations attributable to common shareholders — basic	$	3.59	$	3.69	$	3.54

	Income from continuing operations attributable to common shareholders — diluted	$	3.58	$	3.66	$	3.5

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of granted restricted stock units and stock grants and the weighted average fair value	The following table is a summary of granted restricted stock units, stock units and stock grants and the weighted-average fair value for the 3 years ended 2014, 2013 and 2012:


		2014			2013			2012
	Units granted	130,273			129,620			202,278

	Grant date fair value (a)	$	54.91		$	55.21		$	49.31


	(a)	Weighted-average grant date fair value.
Summary of the status of restricted stock units and stock grants and changes during the year	The following table is a summary of the status of restricted stock units, stock units and stock grants, as of December 31, 2014 and changes during the year. This table represents only the stock portion of restricted stock units and stock units, per the election on payment discussed in the paragraph above:



	Nonvested shares		Shares		Weighted-Average
					Grant Date
					Fair Value
	Nonvested at January 1, 2014		397,976		$	47.74

	Granted		130,273		54.91

	Vested		(161,283	)	45.55

	Forfeited		(13,067	)	51.53

	Nonvested at December 31, 2014		353,899		51.23

Schedule of amount of cash required to settle the payments on restricted stock units	The amount of cash required to settle the payments on restricted stock units is (dollars in millions):



	Year		2014			2013			2012
	2008 Grant		$	—		$	—		$	1.9

	2009 Grant		—			3			1.7

	2010 Grant		2.3			2.3			0.6

	2011 Grant		2.4			2.5			0.7

	2012 Grant		2.1			2.2			—

	2013 Grant		2.1			—			—

Summary of the performance shares granted and the weighted average fair value	The following table is a summary of the performance shares granted and the weighted-average fair value for the three years ended 2014, 2013 and 2012:



		2014			2013			2012
	Units granted (a)	166,244			176,332			185,878

	Grant date fair value (b)	$	54.86		$	55.45		$	47.4


	(a) Reflects the target payout level.
	(b) Weighted-average grant date fair value.
Summary of the status of performance shares and changes during the year	The following table is a summary of the status of performance shares as of December 31, 2014 and changes during the year:



	Nonvested shares (a)		Shares		Weighted-Average
					Grant Date
					Fair Value
	Nonvested at January 1, 2014		344,396		$	51.13

	Granted		166,244		54.86

	Increase in performance factor		86,558		47.4

	Vested		(258,224	)	47.4

	Forfeited		(14,744	)	53.3

	Nonvested at December 31, 2014		324,230		54.92



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

Derivative_Accounting_Tables

Derivative Accounting (Tables)	12 Months Ended
Derivative Accounting (Tables)	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)	As of December 31, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):



	Commodity		Quantity
	Power		3,915			GWh
	Power		3,915			GWh
	Gas		136			Bcf (a)
	Gas		136			Bcf (a)

	(a)	“Bcf” is Billion Cubic Feet.
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships	The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):



			Financial Statement		Year Ended
			Financial Statement		December 31,
	Commodity Contracts		Location		2014				2013				2012
	Loss Recognized in OCI on Derivative Instruments (Effective Portion)		OCI — derivative instruments		$	(372	)		$	(353	)		$	(37,663	)
	Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)		Fuel and purchased power (b)		(21,415		)		(44,219		)		(99,007		)
	Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Fuel and purchased power (b)		—				—				117
			Fuel and purchased power (b)		—				—				117


	(a)	During the years ended December 31, 2014, 2013, and 2012, we had zero, zero, and $1.8 million of losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

	(b)	Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments	The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):



			Financial Statement		Year Ended
			Financial Statement		December 31,
	Commodity Contracts		Location		2014				2013				2012
	Net Gain Recognized in Income		Operating revenues		$	324			$	289			$	103
	Net Gain Recognized in Income		Operating revenues		$	324			$	289			$	103
	Net Loss Recognized in Income		Fuel and purchased power (a)		(66,367		)		(10,449		)		(2,747		)
	Total				$	(66,043	)		$	(10,160	)		$	(2,644	)


	(a)	Amounts are before the effect of PSA deferrals.
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts of offsetting	The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2014 and 2013. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.



	As of December 31, 2014:		Gross				Amounts				Net				Other			Amount
	(dollars in thousands)		Recognized				Offset				Recognized				(c)			Reported on
			Derivatives				(b)				Derivatives							Balance Sheet
			(a)
	Current Assets		$	28,562			$	(15,127	)		$	13,435			$	350		$	13,785
	Current Assets		$	28,562			$	(15,127	)		$	13,435			$	350		$	13,785
	Investments and Other Assets		24,810				(7,190		)		17,620				—			17,620
	Investments and Other Assets		24,810				(7,190		)		17,620				—			17,620
	Total Assets		53,372				(22,317		)		31,055				350			31,405
	Total Assets		53,372				(22,317		)		31,055				350			31,405

	Current Liabilities		(86,062		)		33,829				(52,233		)		(7,443		)	(59,676		)
	Current Liabilities		(86,062		)		33,829				(52,233		)		(7,443		)	(59,676		)
	Deferred Credits and Other		(82,990		)		32,388				(50,602		)		—			(50,602		)
	Deferred Credits and Other		(82,990		)		32,388				(50,602		)		—			(50,602		)
	Total Liabilities		(169,052		)		66,217				(102,835		)		(7,443		)	(110,278		)
	Total Liabilities		(169,052		)		66,217				(102,835		)		(7,443		)	(110,278		)
	Total		$	(115,680	)		$	43,900			$	(71,780	)		$	(7,093	)	$	(78,873	)
	Total		$	(115,680	)		$	43,900			$	(71,780	)		$	(7,093	)	$	(78,873	)


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

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

	(c)	Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,443, and cash margin provided to counterparties of $350.



	As of December 31, 2013:		Gross				Amounts				Net				Other			Amount
	(dollars in thousands)		Recognized				Offset				Recognized				(c)			Reported on
			Derivatives				(b)				Derivatives							Balance Sheet
			(a)
	Current Assets		$	24,587			$	(7,425	)		$	17,162			$	7		$	17,169
	Current Assets		$	24,587			$	(7,425	)		$	17,162			$	7		$	17,169
	Investments and Other Assets		25,364				(1,549		)		23,815				—			23,815
	Investments and Other Assets		25,364				(1,549		)		23,815				—			23,815
	Total Assets		49,951				(8,974		)		40,977				7			40,984
	Total Assets		49,951				(8,974		)		40,977				7			40,984

	Current Liabilities		(50,540		)		26,166				(24,374		)		(7,518		)	(31,892		)
	Current Liabilities		(50,540		)		26,166				(24,374		)		(7,518		)	(31,892		)
	Deferred Credits and Other		(72,123		)		1,808				(70,315		)		—			(70,315		)
	Deferred Credits and Other		(72,123		)		1,808				(70,315		)		—			(70,315		)
	Total Liabilities		(122,663		)		27,974				(94,689		)		(7,518		)	(102,207		)
	Total Liabilities		(122,663		)		27,974				(94,689		)		(7,518		)	(102,207		)
	Total		$	(72,712	)		$	19,000			$	(53,712	)		$	(7,511	)	$	(61,223	)
	Total		$	(72,712	)		$	19,000			$	(53,712	)		$	(7,511	)	$	(61,223	)


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

	(b)	Includes cash collateral provided to counterparties of $19,000.

	(c)	Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.
Information about derivative instruments that have credit-risk-related contingent features	The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2014 (dollars in millions):



		31-Dec-14
	Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	169
		$	169
	Cash Collateral Posted	44
	Cash Collateral Posted	44
	Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	80
		80


	(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_Expense1

Other Income and Other Expense (Tables)	12 Months Ended
	Dec. 31, 2014
Component of Other Income and Other Expense Nonoperating [Line Items]
Detail of other income and other expense	The following table provides detail of other income and other expense for 2014, 2013 and 2012 (dollars in thousands):



		2014			2013			2012
	Other income:

	Interest income	$	1,010		$	1,629		$	1,239

	Debt return on the purchase of Four Corners units 4 & 5	8,386			—			—

	Miscellaneous	212			75			367

	Total other income	$	9,608		$	1,704		$	1,606

	Other expense:

	Non-operating costs	$	(9,657	)	$	(8,207	)	$	(7,777	)
	Investment loss — net	(9,426		)	(3,711		)	(2,453		)
	Miscellaneous	(2,663		)	(4,106		)	(9,612		)
	Total other expense	$	(21,746	)	$	(16,024	)	$	(19,842	)
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 2014, 2013 and 2012 (dollars in thousands):



		2014			2013			2012
	Other income:

	Interest income	$	689		$	1,234		$	310

	Debt return on the purchase of Four Corners units 4 & 5	8,386			—			—

	Miscellaneous	2,220			2,662			2,558

	Total other income	$	11,295		$	3,896		$	2,868

	Other expense:

	Non-operating costs (a)	$	(10,397	)	$	(9,626	)	$	(8,706	)
	Asset dispositions	(615		)	(4,992		)	(1,511		)
	Miscellaneous	(2,391		)	(5,831		)	(10,933		)
	Total other expense	$	(13,403	)	$	(20,449	)	$	(21,150	)

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

Palo_Verde_Sale_Leaseback_Vari1

Palo Verde Sale Leaseback Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2014
Variable Interest Entities [Abstract]
Amounts relating to the VIEs included in Consolidated Balance Sheets	Our Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):



		31-Dec-14		31-Dec-13
	Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	121	$	125

	Current maturities of long-term debt	13		26

	Long-term debt excluding current maturities	—		13

	Equity-Noncontrolling interests	152		146

Nuclear_Decommissioning_Trusts1

Nuclear Decommissioning Trusts (Tables)	12 Months Ended
	Dec. 31, 2014
Investments, Debt and Equity Securities [Abstract]
Fair value of APS's nuclear decommissioning trust fund assets	The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2014 and December 31, 2013 (dollars in millions):



		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	31-Dec-14

	Equity securities	$	310		$	159		$	—

	Fixed income securities	411			17			(1		)

	Net payables (a)	(7		)	—			—

	Total	$	714		$	176		$	(1	)




		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	31-Dec-13

	Equity securities	$	272		$	129		$	—

	Fixed income securities	373			11			(6		)

	Net payables (a)	(3		)	—			—

	Total	$	642		$	140		$	(6	)



	(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 millions):



		Year Ended December 31,
		2014			2013			2012
	Realized gains	$	5		$	6		$	7

	Realized losses	(5		)	(7		)	(4		)
	Proceeds from the sale of securities (a)	356			446			418



	(a)	Proceeds are reinvested in the trust.
Fair value of fixed income securities, summarized by contractual maturities	The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2014 is as follows (dollars in millions):



		Fair Value
	Less than one year	$	14

	1 year – 5 years	116

	5 years – 10 years	122

	Greater than 10 years	159

	Total	$	411

Changes_in_Accumulated_Other_C1

Changes in Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2014
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands):


		Year Ended December 31, 2014
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(23,058	)		$	(54,995	)		$	(78,053	)
	OCI (loss) before reclassifications	(810		)		(5,419		)		(6,229		)
	Amounts reclassified from accumulated other comprehensive loss	13,483			(a)	2,658			(b)	16,141

	Net current period OCI (loss)	12,673				(2,761		)		9,912

	Ending balance	$	(10,385	)		$	(57,756	)		$	(68,141	)


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

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

	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):


		Year Ended December 31, 2013
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(49,592	)		$	(64,416	)		$	(114,008	)
	OCI (loss) before reclassifications	(213		)		5,594				5,381

	Amounts reclassified from accumulated other comprehensive loss	26,747			(a)	3,827			(b)	30,574

	Net current period OCI	26,534				9,421				35,955

	Ending balance	$	(23,058	)		$	(54,995	)		$	(78,053	)


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

	(b)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands):


		Year Ended December 31, 2014
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(23,059	)		$	(30,313	)		$	(53,372	)
	OCI (loss) before reclassifications	(809		)		(10,415		)		(11,224		)
	Amounts reclassified from accumulated other comprehensive loss	13,483			(a)	2,780			(b)	16,263

	Net current period OCI (loss)	12,674				(7,635		)		5,039

	Ending balance	$	(10,385	)		$	(37,948	)		$	(48,333	)


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

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

	The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):


		Year Ended December 31, 2013
		Derivative				Pension and				Total
		Instruments				Other
						Postretirement
						Benefits
	Beginning balance	$	(49,592	)		$	(39,503	)		$	(89,095	)
	OCI (loss) before reclassifications	(214		)		5,387				5,173

	Amounts reclassified from accumulated other comprehensive loss	26,747			(a)	3,803			(b)	30,550

	Net current period OCI	26,533				9,190				35,723

	Ending balance	$	(23,059	)		$	(30,313	)		$	(53,372	)


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

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

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Narrative (Details) (USD $)	12 Months Ended			36 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)	2.77%	3.00%	2.71%
Allowance for Funds Used During Construction
Composite rate used to calculate AFUDC (as a percent)	8.47%	8.56%	8.60%
Intangible Assets
Amortization expense	$53	$53	$50
Estimated amortization expense on existing intangible assets over the next five years
2015	42			42
2016	32			32
2017	21			21
2018	9			9
2019	$3			3
Weighted average remaining amortization period for intangible assets	6 years
ARIZONA PUBLIC SERVICE COMPANY
Nuclear Fuel
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh)	0.001
Preferred Stock
Preferred stock, shares authorized (in shares)	15,535,000			15,535,000
Preferred stock par or stated value per share 1 (in dollars per share)	$25			25
Preferred stock par or stated value per share 2 (in dollars per share)	$50			50
Preferred stock par or stated value per share 3 (in dollars per share)	$100			100
Pinnacle West
Preferred Stock
Preferred stock, shares authorized (in shares)	10,000,000			10,000,000
Minimum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)				0.30%
Maximum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)				12.08%
Investments
Ownership percentage for classification as cost method investments by El Dorado	20.00%
Fossil plant
Approximate remaining average useful lives of utility property
Average useful life	19 years
Nuclear plant
Approximate remaining average useful lives of utility property
Average useful life	28 years
Other generation
Approximate remaining average useful lives of utility property
Average useful life	25 years
Transmission
Approximate remaining average useful lives of utility property
Average useful life	38 years
Distribution
Approximate remaining average useful lives of utility property
Average useful life	33 years
Other
Approximate remaining average useful lives of utility property
Average useful life	7 years

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Accrued capital expenditures	$44,712	$33,184	$26,208
Dividends declared but not paid	65,790	62,528	59,789
Liabilities assumed relating to acquisition of SCE Four Cornersâ€™ interest (see Note 3)	0	145,609	0
Cash Paid During Period [Abstract]
Income tax (benefit), net of refunds	-102,154	18,537	2,543
Interest, net of amounts capitalized	$177,074	$184,010	$200,923

Regulatory_Matters_Details

Regulatory Matters (Details) (APS, USD $)

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Jan. 01, 2014

Jan. 06, 2012

Jun. 01, 2011

Jan. 31, 2012

Apr. 01, 2014

Feb. 12, 2013

Dec. 31, 2014

Jan. 15, 2015

Feb. 01, 2015

Jun. 01, 2014

Apr. 15, 2014

Dec. 31, 2013

Dec. 31, 2012

Jun. 01, 2012

Jul. 01, 2014

Jul. 12, 2013

Retired power plant costs

Regulatory Matters [Line Items]

Regulatory Asset, Net Book Value

$128,000,000

Lost Fixed Cost Recovery Mechanism

Change in regulatory asset

Rate Matter Cap Percentage of Retail Revenue

1.00%

ACC | Net Metering

Change in regulatory asset

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

0.7

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

4.9

Filing with the Arizona Corporation Commission | Arizona Renewable Energy Standard and Tariff 2014 [Member]

Change in regulatory asset

Rate Matter Additional Capacity from AZ Sun Projects

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

Regulatory Matters [Line Items]

Net retail rate increase

95,500,000

Approximate percentage of increase in the average retail customer bill

6.60%

Settlement Agreement

Net change in base rates

Non-fuel base rate increase

116,300,000

Fuel-related base rate decrease

153,100,000

Current base fuel rate (in dollars per kWh)

0.03757

Approved base fuel rate (in dollars per 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

Period to process the subsequent rate cases

12 months

ACC staff sufficiency findings, general period of time

30 days

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

Settlement Agreement

Annual cost recovery due to modifications to the Environmental Improvement Surcharge

5,000,000

Cost Recovery Mechanisms | 2013 DSMAC

Change in regulatory asset

Amount of proposed budget

87,600,000

Rate Matter, Approved Budget

68,900,000

Cost Recovery Mechanisms | Power Supply Adjustor (PSA)

Change in regulatory asset

Increase or decrease in PSA charge (in dollars per kWh)

0.004

Cost Recovery Mechanisms | Lost Fixed Cost Recovery Mechanism

Change in regulatory asset

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

0.031

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

0.023

Amount of adjustment approved representing prorated sales losses

25,300,000

5,100,000

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

Change in regulatory asset

Amount of Adjustment Representing Prorated Sales Losses Pending Approval

38,500,000

Cost Recovery Mechanisms | ACC | RES

Change in regulatory asset

Plan term

5 years

Cost Recovery Mechanisms | ACC | 2013 DSMAC

Change in regulatory asset

Percentage of cumulative energy savings for current year

5.00%

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

Change in regulatory asset

Amount of proposed budget

154,000,000

143,000,000

Rate Matter, Approved Budget

152,000,000

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

Change in regulatory asset

PSA rate for prior year (in dollars per kWh)

-0.001557

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

Change in regulatory asset

PSA rate (in dollars per kWh)

0.000887

Forward component of increase in PSA (in dollars per kWh)

0.001131

Historical component of increase in PSA (in dollars per kWh)

-0.000244

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

Change in regulatory asset

Increase in annual wholesale transmission rates

$5,900,000

Regulatory_Matters_Regulatory_

Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Change in regulatory asset
Deferred fuel and purchased power	($26,927,000)	$21,678,000	$71,573,000
Deferred fuel and purchased power amortization	40,757,000	31,190,000	-116,716,000
ARIZONA PUBLIC SERVICE COMPANY
Change in regulatory asset
Deferred fuel and purchased power	-26,927,000	21,678,000	71,573,000
Deferred fuel and purchased power amortization	40,757,000	31,190,000	-116,716,000
ACC \| ARIZONA PUBLIC SERVICE COMPANY \| Power Supply Adjustor (PSA) \| Cost Recovery Mechanisms
Change in regulatory asset
Beginning balance	21,000,000	73,000,000
Deferred fuel and purchased power	27,000,000	-21,000,000
Deferred fuel and purchased power amortization	-41,000,000	-31,000,000
Ending balance	$7,000,000	$21,000,000

Regulatory_Matters_Four_Corner

Regulatory Matters - Four Corners (Details) (USD $)	0 Months Ended			12 Months Ended
	Dec. 30, 2013	Dec. 30, 2013	Dec. 23, 2014	Dec. 31, 2014	Dec. 31, 2013	Jan. 10, 2014
	Dec. 30, 2013	MW	Dec. 23, 2014	Dec. 31, 2014	Dec. 31, 2013	Jan. 10, 2014
Acquisition
Regulatory assets, non-current				$1,054,087,000	$711,712,000
APS
Acquisition
Regulatory assets, non-current				1,054,087,000	711,712,000
Four Corners cost deferral
Acquisition
Regulatory assets, non-current				70,000,000	37,000,000
SCE \| Four Corners \| APS
Acquisition
Net receipt due to negotiation of alternate arrangement	40,000,000
Capacity rights over the Arizona transmission system assign to third-parties		1,555
Capacity rights related to marketing and trading group for transmission of the additional power received assign to third-parties		300
Four Corners Units 4 and 5 \| SCE \| APS
Acquisition
Ownership interest acquired	48.00%	48.00%				48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact			57,100,000
Four Corners Units 4 and 5 \| SCE \| Four Corners cost deferral \| APS
Acquisition
Regulatory assets, non-current				$77,000,000
Regulatory asset amortization period				P10Y

Regulatory_Matters_Schedule_of

Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Detail of regulatory assets
Regulatory assets, current	$138,000,000	$97,000,000
Regulatory assets, non-current	1,054,087,000	711,712,000
Pension and other postretirement benefits
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	485,000,000	314,000,000
Income taxes - AFUDC equity
Detail of regulatory assets
Regulatory assets, current	5,000,000	4,000,000
Regulatory assets, non-current	118,000,000	105,000,000
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	51,000,000	5,000,000
Regulatory assets, non-current	46,000,000	29,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	5,000,000	14,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	0	8,000,000
Regulatory assets, non-current	7,000,000	18,000,000
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	35,000,000	41,000,000
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	34,000,000	34,000,000
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	7,000,000	21,000,000
Regulatory assets, non-current	0	0
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	14,000,000	15,000,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	16,000,000	17,000,000
Income taxes - investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	2,000,000	1,000,000
Regulatory assets, non-current	46,000,000	39,000,000
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	4,000,000	8,000,000
Regulatory assets, non-current	0	4,000,000
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	7,000,000	0
Regulatory assets, non-current	70,000,000	37,000,000
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	38,000,000	25,000,000
Regulatory assets, non-current	0	0
Transmission cost adjustor
Detail of regulatory assets
Regulatory assets, current	0	8,000,000
Regulatory assets, non-current	0	2,000,000
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	10,000,000	3,000,000
Regulatory assets, non-current	136,000,000	18,000,000
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	30,000,000	11,000,000
Other
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	$12,000,000	$14,000,000

Regulatory_Matters_Schedule_of1

Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Detail of regulatory liabilities
Regulatory liabilities, current	$131,000,000	$99,000,000
Regulatory liabilities, non-current	1,051,196,000	801,297,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	31,000,000	28,000,000
Regulatory liabilities, non-current	273,000,000	303,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	296,000,000	266,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	25,000,000	33,000,000
Regulatory liabilities, non-current	23,000,000	15,000,000
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	72,000,000	74,000,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	5,000,000	6,000,000
Regulatory liabilities, non-current	66,000,000	36,000,000
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,000,000	2,000,000
Regulatory liabilities, non-current	8,000,000	10,000,000
Income taxes-deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	4,000,000	3,000,000
Regulatory liabilities, non-current	93,000,000	79,000,000
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	31,000,000	27,000,000
Regulatory liabilities, non-current	0	0
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	32,000,000	0
Regulatory liabilities, non-current	199,000,000	0
Other
Detail of regulatory liabilities
Regulatory liabilities, current	1,000,000	0
Regulatory liabilities, non-current	$21,000,000	$18,000,000

Income_Taxes_Details

Income Taxes (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended
Income Taxes (Details) (USD $)	Sep. 13, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 17, 2011	Apr. 04, 2013
Income Taxes
Decrease in prior period uncertain tax positions		$2,282,000	$108,099,000	$7,729,000
Income tax examination, liability (refund) adjustment from settlement with taxing authority			-133,000,000
Decrease in long term deferred tax liability due to adoption of regulations	82,000,000	26,000,000
Unrecognized tax benefits if recognized, would decrease effective tax rate		11,000,000	10,000,000	10,000,000
Pre-tax interest expense (benefit) related to unrecognized tax benefits		1,000,000	-4,000,000	4,000,000
Accrued liabilities for interest related to unrecognized tax benefit (less than $1 million for APS in 2014 and 2013)		1,000,000	1,000,000	13,000,000
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less then $1 million)		1,000,000
General business tax credit carryforwards that will begin to expire in 2031		90,000,000
Amount of federal and state loss carryforwards which will begin to expire in 2019		4,000,000
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Decrease in prior period uncertain tax positions		2,282,000	107,918,000	7,729,000
Income tax examination, liability (refund) adjustment from settlement with taxing authority			-135,000,000
Decrease in long term deferred tax liability due to adoption of regulations	82,000,000
Unrecognized tax benefits if recognized, would decrease effective tax rate		11,000,000	10,000,000	10,000,000
Pre-tax interest expense (benefit) related to unrecognized tax benefits		1,000,000	4,000,000	4,000,000
Accrued liabilities for interest related to unrecognized tax benefit (less than $1 million for APS in 2014 and 2013)			1,000,000	13,000,000
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less then $1 million)		1,000,000
Third quarter 2009
Income Taxes
Decrease in prior period uncertain tax positions			67,000,000
Third quarter 2009 \| ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Decrease in prior period uncertain tax positions			67,000,000
Tax Years 2008 and 2009
Income Taxes
Decrease in prior period uncertain tax positions			41,000,000
Tax Years 2008 and 2009 \| ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Decrease in prior period uncertain tax positions			41,000,000
ARIZONA \| State Jurisdiction \| ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Phase-in period of corporate income tax rate reductions beginning in 2014					4 years
Decrease in long term deferred tax liability due to rate changes		74,000,000
NEW MEXICO \| State Jurisdiction \| ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Phase-in period of corporate income tax rate reductions beginning in 2014						5 years
Decrease in long term deferred tax liability due to rate changes		2,000,000
Maximum \| ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Accrued liabilities for interest related to unrecognized tax benefit (less than $1 million for APS in 2014 and 2013)		1,000,000
Palo Verde VIE
Income Taxes
Income tax expense benefit attributable to non controlling interests		$0

Income_Taxes_Income_Taxes_Reco

Income Taxes Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	$41,997	$133,422	$136,005
Additions for tax positions of the current year	4,309	3,516	5,167
Additions for tax positions of prior years	751	13,158	0
Reductions for tax positions of prior years for:
Changes in judgment	-2,282	-108,099	-7,729
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	0	0	-21
Total unrecognized tax benefits, end of the year	44,775	41,997	133,422
ARIZONA PUBLIC SERVICE COMPANY
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	41,997	133,241	135,824
Additions for tax positions of the current year	4,309	3,516	5,167
Additions for tax positions of prior years	751	13,158	0
Reductions for tax positions of prior years for:
Changes in judgment	-2,282	-107,918	-7,729
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	0	0	-21
Total unrecognized tax benefits, end of the year	$44,775	$41,997	$133,241

Income_Taxes_Components_of_Inc

Income Taxes - Components of Income Tax Expense (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal									$25,054	($81,784)	($3,493)
State									10,382	10,537	8,395
Total current									35,436	-71,247	4,902
Deferred:
Federal									167,365	279,973	200,322
State									17,904	21,865	28,280
Total deferred									185,269	301,838	228,602
Total income tax expense									220,705	230,591	233,504
Less: income tax benefit on discontinued operations									0	0	-3,813
INCOME TAXES (Note 4)	5,007	134,753	74,540	6,405	9,167	131,912	77,043	12,469	220,705	230,591	237,317
ARIZONA PUBLIC SERVICE COMPANY
Current:
Federal									40,115	-97,531	-11,650
State									15,598	11,983	12,308
Total current									55,713	-85,548	658
Deferred:
Federal									165,027	305,389	216,367
State									16,620	25,254	27,371
Total deferred									181,647	330,643	243,738
Total income tax expense									237,360	245,095	244,396
INCOME TAXES (Note 4)									$237,360	$245,095	$244,396

Income_Taxes_Effective_Tax_Rat

Income Taxes - Effective Tax Rate Reconciliation (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
Federal income tax rate (as a percent)									35.00%	35.00%	35.00%
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at 35% statutory rate									$225,540,000	$234,695,000	$229,709,000
State income tax net of federal income tax benefit									18,149,000	21,387,000	23,819,000
Credits and favorable adjustments related to prior years resolved in current year									0	-3,356,000	0
Medicare Subsidy Part-D									830,000	823,000	483,000
Allowance for equity funds used during construction									-8,523,000	-6,997,000	-6,158,000
Palo Verde VIE noncontrolling interest									-9,135,000	-11,862,000	-11,065,000
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Amount									-4,928,000	-3,548,000	-2,030,000
Other									-1,228,000	-551,000	2,559,000
INCOME TAXES (Note 4)	5,007,000	134,753,000	74,540,000	6,405,000	9,167,000	131,912,000	77,043,000	12,469,000	220,705,000	230,591,000	237,317,000
ARIZONA PUBLIC SERVICE COMPANY
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
Federal income tax rate (as a percent)									35.00%
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at 35% statutory rate									239,638,000	246,384,000	235,027,000
State income tax net of federal income tax benefit									21,148,000	23,970,000	25,379,000
Credits and favorable adjustments related to prior years resolved in current year									0	-3,231,000	0
Medicare Subsidy Part-D									830,000	823,000	483,000
Allowance for equity funds used during construction									-8,523,000	-6,997,000	-6,158,000
Palo Verde VIE noncontrolling interest									-9,135,000	-11,862,000	-11,065,000
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Amount									-4,928,000	-3,548,000	-2,030,000
Other									-1,670,000	-444,000	2,760,000
INCOME TAXES (Note 4)									$237,360,000	$245,095,000	$244,396,000

Income_Taxes_Income_Taxes_Defe

Income Taxes Income Taxes - Deferred Income Tax Liability Recognized on the Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Net deferred income tax liability recognized on the Consolidated Balance Sheets
Deferred tax asset, current	$122,232	$91,152
Long-term liability	-2,582,636	-2,351,882
Deferred income taxes â€” net	-2,460,404	-2,260,730
ARIZONA PUBLIC SERVICE COMPANY
Net deferred income tax liability recognized on the Consolidated Balance Sheets
Deferred tax asset, current	55,253	0
Deferred tax liability, current	0	-2,033
Long-term liability	-2,571,365	-2,347,724
Deferred income taxes â€” net	($2,516,112)	($2,349,757)

Income_Taxes_Components_of_Def

Income Taxes - Components of Deferred Income Tax Liability (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory liabilities:
Asset retirement obligation and removal costs	$229,772	$235,959
Unamortized investment tax credits	96,232	82,116
Other postretirement liabilities	90,496	0
Other	60,409	42,609
Risk management activities	57,505	44,920
Pension liabilities	205,227	140,773
Other postretirement liabilities	0	57,869
Renewable energy incentives	65,169	65,434
Credit and loss carryforwards	68,347	133,070
Other	138,729	148,492
Total deferred tax assets	1,011,886	951,242
DEFERRED TAX LIABILITIES
Plant-related	-2,958,369	-2,903,730
Risk management activities	-12,171	-16,191
Other postretirement assets	-59,170	0
Regulatory assets:
Allowance for equity funds used during construction	-48,286	-43,058
Deferred fuel and purchased power	-2,498	-8,282
Deferred fuel and purchased power â€” mark-to-market	-38,187	-13,343
Pension and other postretirement benefits	-191,747	-129,250
Retired power plant costs (see Note 3)	-57,255	-8,199
Other	-99,123	-85,003
Other	-5,484	-4,916
Total deferred tax liabilities	-3,472,290	-3,211,972
Deferred income taxes â€” net	-2,460,404	-2,260,730
ARIZONA PUBLIC SERVICE COMPANY
Regulatory liabilities:
Asset retirement obligation and removal costs	229,772	235,959
Unamortized investment tax credits	96,232	82,116
Other postretirement liabilities	90,496	0
Other	60,409	42,609
Risk management activities	57,505	44,920
Pension liabilities	194,541	132,263
Other postretirement liabilities	0	53,950
Renewable energy incentives	65,169	65,434
Credit and loss carryforwards	0	38,183
Other	161,379	166,781
Total deferred tax assets	955,503	862,215
DEFERRED TAX LIABILITIES
Plant-related	-2,958,369	-2,903,730
Risk management activities	-12,171	-16,191
Other postretirement assets	-58,495	0
Regulatory assets:
Allowance for equity funds used during construction	-48,286	-43,058
Deferred fuel and purchased power	-2,498	-8,282
Deferred fuel and purchased power â€” mark-to-market	-38,187	-13,343
Pension and other postretirement benefits	-191,747	-129,250
Retired power plant costs (see Note 3)	-57,255	-8,199
Other	-99,123	-85,003
Other	-5,484	-4,916
Total deferred tax liabilities	-3,471,615	-3,211,972
Deferred income taxes â€” net	($2,516,112)	($2,349,757)

Lines_of_Credit_and_ShortTerm_2

Lines of Credit and Short-Term Borrowings (Details) (USD $)	Feb. 06, 2013	Dec. 31, 2014	Dec. 31, 2013	9-May-14	8-May-14	Apr. 08, 2013	Apr. 09, 2013
ARIZONA PUBLIC SERVICE COMPANY \| ACC
Debt Provisions
Percentage of APS's capitalization used in calculation of short-term debt authorization	7.00%
Required amount to be used in purchases of natural gas and power which is used in calculation of short-term debt authorization	$500,000,000
Long-term debt authorization before increase	4,200,000,000
Long-term debt authorization	5,100,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Commercial paper
Lines of Credit and Short-Term Borrowings
Long-term line of credit		147,000,000	153,000,000
Commercial paper \| Pinnacle West
Lines of Credit and Short-Term Borrowings
Commercial Paper		0	0
Maximum commercial paper support available under credit facility		200,000,000	200,000,000
Commercial paper \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Maximum commercial paper support available under credit facility		250,000,000	250,000,000
Letter of credit \| Pinnacle West
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit		0	0
Letter of credit \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit		109,000,000
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed		1,200,000,000	1,200,000,000
Revolving credit facility \| Pinnacle West \| Revolving credit facility maturing in 2019
Lines of Credit and Short-Term Borrowings
Amount committed		200,000,000		200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		300,000,000
Revolving credit facility \| Pinnacle West \| Revolving credit facility maturing in 2016
Lines of Credit and Short-Term Borrowings
Amount committed			200,000,000		200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders			300,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Long-term line of credit		0	0
Outstanding letters of credit		0	0
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2019
Lines of Credit and Short-Term Borrowings
Amount committed		500,000,000		500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2015
Lines of Credit and Short-Term Borrowings
Amount committed						500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2018
Lines of Credit and Short-Term Borrowings
Amount committed		500,000,000	500,000,000				500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facilities maturing November 2016 and April 2018
Lines of Credit and Short-Term Borrowings
Amount committed			1,000,000,000
Number of credit facilities			2
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders			700,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2016
Lines of Credit and Short-Term Borrowings
Amount committed			500,000,000		500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facilities maturing April 2018 and May 2019
Lines of Credit and Short-Term Borrowings
Amount committed		1,000,000,000
Number of credit facilities		2
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		700,000,000
Line of credit \| Pinnacle West
Lines of Credit and Short-Term Borrowings
Long-term line of credit		$0	$0

Lines_of_Credit_and_ShortTerm_3

Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	9-May-14	8-May-14	Apr. 09, 2013	Apr. 08, 2013
ARIZONA PUBLIC SERVICE COMPANY \| Commercial paper
Lines of Credit and Short-Term Borrowings
Long-term line of credit	$147,000,000	$153,000,000
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed	1,200,000,000	1,200,000,000
Unused amount	1,053,000,000	1,047,000,000
Revolving credit facility \| Pinnacle West \| Revolving credit facility maturing in 2019
Lines of Credit and Short-Term Borrowings
Amount committed	200,000,000		200,000,000
Unused amount	200,000,000
Commitment fees (as a percent)	0.18%
Revolving credit facility \| Pinnacle West \| Revolving credit facility maturing in 2016
Lines of Credit and Short-Term Borrowings
Amount committed		200,000,000		200,000,000
Unused amount		200,000,000
Commitment fees (as a percent)		17.50%
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Long-term line of credit	0	0
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2019
Lines of Credit and Short-Term Borrowings
Amount committed	500,000,000		500,000,000
Unused amount	500,000,000
Commitment fees (as a percent)	0.13%
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2018
Lines of Credit and Short-Term Borrowings
Amount committed	500,000,000	500,000,000			500,000,000
Unused amount	353,000,000	500,000,000
Commitment fees (as a percent)	0.13%	12.50%
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2016
Lines of Credit and Short-Term Borrowings
Amount committed		500,000,000		500,000,000
Unused amount		347,000,000
Commitment fees (as a percent)		12.50%
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing in 2015
Lines of Credit and Short-Term Borrowings
Amount committed						500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facilities maturing April 2018 and May 2019
Lines of Credit and Short-Term Borrowings
Number of credit facilities	2
Amount committed	1,000,000,000
Unused amount	853,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facilities maturing November 2016 and April 2018
Lines of Credit and Short-Term Borrowings
Number of credit facilities		2
Amount committed		1,000,000,000
Unused amount		$847,000,000

LongTerm_Debt_and_Liquidity_Ma2

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

12 Months Ended

0 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Jan. 10, 2014

Jun. 18, 2014

Dec. 30, 2013

Jul. 12, 2013

Oct. 11, 2013

1-May-14

14-May-14

Sep. 23, 2014

Jun. 01, 2014

30-May-14

Oct. 01, 2014

8-May-14

9-May-14

Jan. 12, 2015

Series

Long-Term Debt and Liquidity Matters [Line Items]

Repayments of long-term debt

$652,578,000

$122,828,000

$654,286,000

Debt Provisions

Total shareholder equity

4,367,493,000

4,194,470,000

ARIZONA PUBLIC SERVICE COMPANY

Long-Term Debt and Liquidity Matters [Line Items]

Gross long-term debt

3,294,000,000

Repayments of long-term debt

527,578,000

122,828,000

529,286,000

Debt Provisions

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

45.00%

Total shareholder equity

4,478,243,000

4,308,884,000

ARIZONA PUBLIC SERVICE COMPANY | SCE | Four Corners Units 4 and 5

Long-Term Debt and Liquidity Matters [Line Items]

Ownership interest acquired

48.00%

Number of tax-exempt indebtedness series re-acquired

ARIZONA PUBLIC SERVICE COMPANY | Pollution control revenue refunding bonds, 1994 series A

Long-Term Debt and Liquidity Matters [Line Items]

Gross long-term debt

33,000,000

ARIZONA PUBLIC SERVICE COMPANY | Pollution control revenue refunding bonds, 1994 series C

Long-Term Debt and Liquidity Matters [Line Items]

Gross long-term debt

32,000,000

ARIZONA PUBLIC SERVICE COMPANY | 4.70% unsecured senior notes that mature on January 15, 2044

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

250,000,000

Interest rate (as a percent)

4.70%

Pinnacle West

Long-Term Debt and Liquidity Matters [Line Items]

Gross long-term debt

3,419,000,000

Repayments of long-term debt

125,000,000

Debt Provisions

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

46.00%

Total shareholder equity

4,367,493,000

4,194,470,000

Line of credit | Pinnacle West | Term loan facility matures on 31 December, 2017

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

125,000,000

Debt instrument, bond | ARIZONA PUBLIC SERVICE COMPANY | Pollution control revenue refunding bonds, 2009 series A, series D and series E

Long-Term Debt and Liquidity Matters [Line Items]

Principal balance repaid

100,000,000

Debt instrument, bond | ARIZONA PUBLIC SERVICE COMPANY | Series A bonds 2009

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

36,000,000

Debt instrument, bond | ARIZONA PUBLIC SERVICE COMPANY | Series D and series E bonds 2009

Long-Term Debt and Liquidity Matters [Line Items]

Debt Instrument expected to be Issued in the next 12 months

64,000,000

Debt instrument, bond | ARIZONA PUBLIC SERVICE COMPANY | Pollution control revenue refunding bonds 2009 series A due 2034

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

38,000,000

13,000,000

Principal balance repaid

38,000,000

Debt instrument, bond | ARIZONA PUBLIC SERVICE COMPANY | Series B and series C bonds 2009

Long-Term Debt and Liquidity Matters [Line Items]

Principal balance repaid

64,000,000

Debt instrument, bond | ARIZONA PUBLIC SERVICE COMPANY | Series C bonds 2009

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

32,000,000

Debt instrument, bond | ARIZONA PUBLIC SERVICE COMPANY | Series B bonds 2009

Long-Term Debt and Liquidity Matters [Line Items]

Debt Instrument expected to be Issued in the next 12 months

32,000,000

Senior notes | ARIZONA PUBLIC SERVICE COMPANY | Unsecured senior notes 3.35 percent matures on 15 June, 2024

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

250,000,000

Interest rate (as a percent)

3.35%

Senior notes | ARIZONA PUBLIC SERVICE COMPANY | Unsecured senior notes 5.80 percent matures on 30 June, 2014

Long-Term Debt and Liquidity Matters [Line Items]

Interest rate (as a percent)

5.80%

Repayments of long-term debt

300,000,000

Revolving credit facility

Long-Term Debt and Liquidity Matters [Line Items]

Revolving credit facility, current borrowing capacity

1,200,000,000

Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing in 2016

Long-Term Debt and Liquidity Matters [Line Items]

Revolving credit facility, current borrowing capacity

500,000,000

Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing in 2019

Long-Term Debt and Liquidity Matters [Line Items]

Revolving credit facility, current borrowing capacity

500,000,000

Revolving credit facility | Pinnacle West | Revolving credit facility maturing in 2016

Long-Term Debt and Liquidity Matters [Line Items]

Revolving credit facility, current borrowing capacity

200,000,000

Revolving credit facility | Pinnacle West | Revolving credit facility maturing in 2019

Long-Term Debt and Liquidity Matters [Line Items]

Revolving credit facility, current borrowing capacity

200,000,000

Maximum

Debt Provisions

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

65.00%

ACC | ARIZONA PUBLIC SERVICE COMPANY

Debt Provisions

Total shareholder equity

4,500,000,000

Total capitalization

8,000,000,000

Dividend restrictions, shareholder equity required

3,200,000,000

ACC | Minimum | ARIZONA PUBLIC SERVICE COMPANY

Debt Provisions

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

40.00%

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

Long-Term Debt and Liquidity Matters [Line Items]

Notes issued

$250,000,000

Interest rate (as a percent)

2.20%

LongTerm_Debt_and_Liquidity_Ma3

Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Long-Term Debt and Liquidity Matters [Line Items]
Long-term debt	$3,415,000	$3,337,000
Long-term debt less current maturities	3,031,215	2,796,465
APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	3,294,000
Unamortized discount	-9,206	-8,732
Unamortized premium	4,866	5,047
Long-term debt	3,289,785	3,211,889
Less current maturities	-383,570	-540,424
Total long-term debt less current maturities	2,906,215	2,671,465
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	3,419,000
Long-term debt	125,000	125,000
Long-term debt less current maturities	125,000	125,000
Pollution Control Bonds - Variable \| APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	156,405	75,580
Less current maturities	-70,000
Pollution Control Bonds - Variable \| APS \| Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	0.27%	0.06%
Pollution Control Bonds - Variable \| APS \| Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	0.03%	0.03%
Pollution Control Bonds - Fixed \| APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	249,300	426,125
Interest Rates, low end of range (as a percent)	0.45%	0.45%
Interest Rates, high end of range (as a percent)	5.75%	5.75%
Total Pollution Control Bonds \| APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	405,705	501,705
Senior unsecured notes \| APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	2,875,000	2,675,000
Interest Rates, low end of range (as a percent)	3.35%	3.35%
Interest Rates, high end of range (as a percent)	8.75%	8.75%
Palo Verde sale leaseback lessor notes \| APS
Long-Term Debt and Liquidity Matters [Line Items]
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	13,420	38,869
Interest rate (as a percent)	8.00%	8.00%
Term loan facility \| Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Long-term debt	125,000	125,000
Weighted-average interest rate (as a percent)	1.02%	1.27%
Senior unsecured notes maturing through 2015 \| APS
Long-Term Debt and Liquidity Matters [Line Items]
Less current maturities	($300,000)

LongTerm_Debt_and_Liquidity_Ma4

Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) (USD $)	Dec. 31, 2014
ARIZONA PUBLIC SERVICE COMPANY
Principal payments due on long-term debt
2015	$384,000,000
2016	357,000,000
2017	32,000,000
2018	32,000,000
2019	500,000,000
Thereafter	1,989,000,000
Total	3,294,000,000
Pinnacle West
Principal payments due on long-term debt
2015	384,000,000
2016	357,000,000
2017	157,000,000
2018	32,000,000
2019	500,000,000
Thereafter	1,989,000,000
Total	$3,419,000,000

LongTerm_Debt_and_Liquidity_Ma5

Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Estimated fair value of long-term debt, including current maturities
Long-term debt	$3,415,000,000	$3,337,000,000
Long-term debt, fair value	3,839,000,000	3,579,000,000
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Long-term debt	125,000,000	125,000,000
Long-term debt, fair value	125,000,000	125,000,000
ARIZONA PUBLIC SERVICE COMPANY
Estimated fair value of long-term debt, including current maturities
Long-term debt	3,289,785,000	3,211,889,000
Long-term debt, fair value	$3,714,000,000	$3,454,000,000

Retirement_Plans_and_Other_Ben2

Retirement Plans and Other Benefits Retirement Plans and Other Benefits (Details) (USD $)	1 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 01, 2015
	Jul. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Age
Plan Design Changes [Abstract]
Assets for other postretirement benefits		$152,290,000	$0
Amount of other postretirement benefit trust assets for union employee medical costs		100,000,000
Amount of pension and other postretirement benefit costs deferred				14,000,000	11,000,000
Regulatory asset amortization period	3 years
Amortization of regulatory assets		8,000,000	8,000,000	4,000,000
Change in mortality assumptions impact on pension and other postretirement obligations		67,000,000
Partnership funding commitments, maximum contribution amount		75,000,000
Partnership funding commitments, funded amount		30,000,000
Pension Benefits
Plan Design Changes [Abstract]
Assets for other postretirement benefits		0	0
Expected long-term return on plan assets for next fiscal year (as a percent)		6.90%
Contributions
Employer's contributions under the plan		175,000,000	140,500,000	65,000,000
Minimum contributions under MAP-21
Minimum contributions under MAP-21		0
Expected employer contributions
Expected employer contributions		300,000,000
Pension Benefits \| Fixed income securities
Target asset allocation
Target allocation (as a percent)		58.00%
Target allocation, minimum (as a percent)		55.00%
Target allocation, maximum (as a percent)		61.00%
Actual asset allocation (as a percent)		61.00%
Pension Benefits \| Return-generating assets
Target asset allocation
Target allocation (as a percent)		42.00%
Target allocation, minimum (as a percent)		39.00%
Target allocation, maximum (as a percent)		45.00%
Actual asset allocation (as a percent)		39.00%
Pension Benefits \| Developed equities
Target asset allocation
Target allocation (as a percent)		22.00%
Pension Benefits \| Emerging equities
Target asset allocation
Target allocation (as a percent)		6.00%
Pension Benefits \| Alternative investments
Target asset allocation
Target allocation (as a percent)		14.00%
Other postretirement benefits
Plan Design Changes [Abstract]
Effect of plan amendment on net periodic benefit cost		10,000,000
Effect of plan amendment on expense		5,000,000
Effect of plan amendment on accumulated benefit obligation		316,000,000
Assets for other postretirement benefits		152,290,000	0
Regulatory liabilities		231,000,000
Expected long-term return on plan assets for next fiscal year (as a percent)		4.74%
Contributions
Employer's contributions under the plan		770,000	14,438,000	22,707,000
Expected employer contributions
2015		1,000,000
2016		100,000,000
2017		100,000,000
Other postretirement benefits \| Fixed income
Target asset allocation
Actual asset allocation (as a percent)		43.00%
Other postretirement benefits \| Non-fixed income
Target asset allocation
Actual asset allocation (as a percent)		57.00%
Maximum \| Pension Benefits
Expected employer contributions
2015		100,000,000
2016		100,000,000
2017		100,000,000
Subsequent event \| Other postretirement benefits
Plan Design Changes [Abstract]
Age eligible for benefit						65
Pinnacle West
Employee savings plan benefits
Expenses recorded for the defined contribution savings plan		9,000,000	9,000,000	8,000,000
ARIZONA PUBLIC SERVICE COMPANY
Plan Design Changes [Abstract]
Assets for other postretirement benefits		149,260,000	0
Employee savings plan benefits
APS's employees share of total cost of the plans (as a percent)		99.00%
ARIZONA PUBLIC SERVICE COMPANY \| Pension Benefits
Contributions
Employer's contributions under the plan		175,000,000	140,000,000	64,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Other postretirement benefits
Contributions
Employer's contributions under the plan		$1,000,000	$14,000,000	$22,000,000

Retirement_Plans_and_Other_Ben3

Retirement Plans and Other Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net periodic benefit costs and the portion of these costs charged to expense
Amortization of transition obligation	$0	$0
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	53,080	64,195	63,502
Interest cost on benefit obligation	129,194	112,392	119,586
Expected return on plan assets	-158,998	-146,333	-140,979
Amortization of transition obligation			0
Amortization of prior service cost (credit)	869	1,097	1,143
Amortization of net actuarial loss	10,963	39,852	44,250
Net periodic benefit cost	35,108	71,203	87,502
Portion of cost charged to expense	21,985	38,968	36,333
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	18,139	23,597	27,163
Interest cost on benefit obligation	41,243	41,536	46,467
Expected return on plan assets	-46,400	-45,717	-45,793
Amortization of transition obligation	0	0	452
Amortization of prior service cost (credit)	-9,626	-179	-179
Amortization of net actuarial loss	1,175	11,310	20,233
Net periodic benefit cost	4,531	30,547	48,343
Portion of cost charged to expense	$6,000	$18,469	$19,321

Retirement_Plans_and_Other_Ben4

Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	$2,646,530	$2,850,846
Service cost	53,080	64,195	63,502
Interest cost	129,194	112,392	119,586
Benefit payments	-128,550	-125,269
Actuarial (gain) loss	378,394	-255,634
Plan amendments	0	0
Benefit obligation at the end of the period	3,078,648	2,646,530	2,850,846
Change in Plan Assets
Balance at the beginning of the period	2,264,121	2,079,181
Actual return on plan assets	292,992	150,546
Employer's contributions under the plan	175,000	140,500	65,000
Benefit payments	-116,709	-106,106
Balance at the end of the period	2,615,404	2,264,121	2,079,181
Funded Status at the end of the period	-463,244	-382,409
Other Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	890,418	990,418
Service cost	18,139	23,597	27,163
Interest cost	41,243	41,536	46,467
Benefit payments	-29,054	-26,675
Actuarial (gain) loss	150,188	-138,458
Plan amendments	-388,599	0
Benefit obligation at the end of the period	682,335	890,418	990,418
Change in Plan Assets
Balance at the beginning of the period	748,339	684,221
Actual return on plan assets	105,223	76,995
Employer's contributions under the plan	770	14,438	22,707
Benefit payments	-19,707	-27,315
Balance at the end of the period	834,625	748,339	684,221
Funded Status at the end of the period	$152,290	($142,079)

Retirement_Plans_and_Other_Ben5

Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) (Pension Benefits, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
Projected benefit obligation	$3,078,648	$2,646,530
Accumulated benefit obligation	2,873,741	2,469,889
Fair value of plan assets	$2,615,404	$2,264,121

Retirement_Plans_and_Other_Ben6

Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Amounts recognized on the Consolidated Balance Sheets
Assets for other postretirement benefits	$152,290	$0
Noncurrent liability	-453,736	-513,628
Pension Benefits
Amounts recognized on the Consolidated Balance Sheets
Assets for other postretirement benefits	0	0
Current liability	-9,508	-10,860
Noncurrent liability	-453,736	-371,549
Net amount recognized	-463,244	-382,409
Other Benefits
Amounts recognized on the Consolidated Balance Sheets
Assets for other postretirement benefits	152,290	0
Current liability	0	0
Noncurrent liability	0	-142,079
Net amount recognized	$152,290	($142,079)

Retirement_Plans_and_Other_Ben7

Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Details related to accumulated other comprehensive loss
Accumulated other comprehensive loss	$57,756	$54,995
Other Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	148,006	57,816
Prior service cost (credit)	-379,269	-296
APS's portion recorded as a regulatory asset	230,916	-49,298
Income tax benefit	851	-2,528
Accumulated other comprehensive loss	504	5,694
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	5,651
Prior service cost (credit)	-37,968
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	-32,317
Pension Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	577,976	344,540
Prior service cost (credit)	1,203	2,072
APS's portion recorded as a regulatory asset	-485,037	-265,107
Income tax benefit	-36,890	-32,204
Accumulated other comprehensive loss	57,252	49,301
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	28,180
Prior service cost (credit)	595
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	$28,775

Retirement_Plans_and_Other_Ben8

Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) (USD $)	3 Months Ended	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Weighted-average assumptions used to determine benefit obligations
Rate of compensation increase (as a percent)	4.00%		4.00%	4.00%
Initial pre-65 healthcare cost trend rate (as a percent)			7.00%	7.50%
Initial post-65 healthcare cost trend rate (as a percent)			5.00%	7.50%
Ultimate health care cost trend rate (as a percent)			5.00%	5.00%
Number of years to ultimate trend rate (pre-65 participants)			4 years	4 years
Number of years to ultimate trend rate (post-65 participants)			0 years	4 years
Weighted-average assumptions used to determine net periodic benefit costs
Initial pre-65 health care cost trend rate (as a percent)	7.50%	7.50%		7.50%	7.50%
Initial post-65 health care cost trend rate (as a percent)	5.00%	7.50%		7.50%	7.50%
Ultimate healthcare cost trend rate (as a percent)	5.00%	5.00%		5.00%	5.00%
Number of years to ultimate trend rate (pre-65 participants)	4 years	4 years		4 years	4 years
Number of years to ultimate trend rate (post-65 participants)	0 years	4 years		4 years	4 years
Pension Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	4.02%		4.02%	4.88%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.88%	4.88%		4.01%	4.42%
Rate of compensation increase (as a percent)	4.00%	4.00%		4.00%	4.00%
Expected long-term return on plan assets (as a percent)	6.90%	6.90%		7.00%	7.75%
Other Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	4.14%		4.14%	5.10%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.41%	5.10%		4.20%	4.59%
Expected long-term return on plan assets (as a percent)	4.25%	6.80%		7.00%	7.75%
Effects of one percentage point change in the assumed initial and ultimate health care cost trend rates
Effect of 1% increase on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants			10
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants			-4
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs			12
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs			-9
Effect of 1% increase on the accumulated other postretirement benefit obligation			110
Effect of 1% decrease on the accumulated other postretirement benefit obligation			-88

Retirement_Plans_and_Other_Ben9

Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	$2,615,404	$2,264,121	$2,079,181
Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	16,883	250
Fair value of plan assets	2,615,404	2,264,121
Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	556,660	490,559
Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	2,013,932	1,764,652
Pension Benefits \| Significant Unobservable Inputs (Level 3) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	27,929	8,660
Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	834,625	748,339	684,221
Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	4,100	2,430
Fair value of plan assets	834,625	748,339
Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	414,204	371,777
Other Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	416,321	374,132
Other Benefits \| Significant Unobservable Inputs (Level 3) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	0	0
Cash and cash equivalent funds \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	387	504
Cash and cash equivalent funds \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	387	504
Cash and cash equivalent funds \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	318
Cash and cash equivalent funds \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	318
Corporate debt \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	1,162,096	898,621
Corporate debt \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,162,096	898,621
Corporate debt \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	187,961	153,888
Corporate debt \| Other Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	187,961	153,888
U.S. Treasury \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	291,817	231,590
U.S. Treasury \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	291,817	231,590
U.S. Treasury \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	130,967	98,704
U.S. Treasury \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	130,967	98,704
Other \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	113,265	84,011
Other \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	113,265	84,011
Other \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	35,291	27,936
Other \| Other Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	35,291	27,936
U.S. companies, equities \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	246,387	239,036
U.S. companies, equities \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	246,387	239,036
U.S. companies, equities \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	265,106	252,181
U.S. companies, equities \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	265,106	252,181
International companies, equities \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	18,069	19,429
International companies, equities \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	18,069	19,429
International companies, equities \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	17,813	20,892
International companies, equities \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	17,813	20,892
U.S. Equities \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	127,336	116,150
U.S. Equities \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	127,336	116,150
U.S. Equities \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	88,258	80,751
U.S. Equities \| Other Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	88,258	80,751
International equities \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	317,167	367,551
International equities \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	317,167	367,551
International equities \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	85,746	92,382
International equities \| Other Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	85,746	92,382
Fixed income securities \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets		137,520
Fixed income securities \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets		137,520
Real estate \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	129,715	119,739
Real estate \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	129,715	119,739
Real estate \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	11,657	10,761
Real estate \| Other Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	11,657	10,761
Partnerships \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	166,266	8,660
Partnerships \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	138,337	0
Partnerships \| Pension Benefits \| Significant Unobservable Inputs (Level 3) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	27,929	8,660
Short-term investments and other \| Pension Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	16,883	250
Fair value of plan assets	42,899	41,310
Short-term investments and other \| Pension Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	26,016	41,060
Short-term investments and other \| Pension Benefits \| Significant Unobservable Inputs (Level 3)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	27,929	8,660	2,419
Short-term investments and other \| Other Benefits \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Net receivables (payables)	4,100	2,430
Fair value of plan assets	11,508	10,844
Short-term investments and other \| Other Benefits \| Significant Other Observable Inputs (Level 2) \| Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	$7,408	$8,414

Recovered_Sheet1

Retirement Plans and Other Benefits - Changes in Fair Value (Details) (Pension Benefits, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in fair value for assets that are measured at fair value on a recurring basis
Balance at the beginning of the period			$2,079,181
Balance at the end of the period	2,615,404	2,264,121	2,079,181
Short-term investments and other \| Significant Unobservable Inputs (Level 3)
Changes in fair value for assets that are measured at fair value on a recurring basis
Balance at the beginning of the period	8,660	2,419
Actual return on assets still held	927	-498
Purchases	19,984	7,377
Sales	-1,642	-638
Transfers in and/or out of Level 3	0	0
Balance at the end of the period	$27,929	$8,660

Recovered_Sheet2

Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Pension Benefits
Estimated Future Benefit Payments
2015	$139,013
2016	155,968
2017	160,080
2018	167,600
2019	177,470
Years 2020-2024	983,557
Other Benefits
Estimated Future Benefit Payments
2015	25,134
2016	27,311
2017	29,253
2018	31,258
2019	33,190
Years 2020-2024	$184,772

Leases_Details

Leases (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 1986
	Trust	Dec. 31, 2013	Dec. 31, 2012	Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2015	$18
2016	6
2017	5
2018	4
2019	3
Thereafter	63
Total future lease commitments	99
Lease expense	18	18	19
APS
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2015	15
2016	6
2017	5
2018	4
2019	3
Thereafter	62
Total future lease commitments	95
Lease expense	$15	$15	$16
Number of VIE lessor trusts	3			3
Palo Verde Lessor Trusts
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Number of VIE lessor trusts				3

JointlyOwned_Facilities_Detail

Jointly-Owned Facilities (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Palo Verde Units 1 and 3
Interests in jointly-owned facilities
Percent Owned	29.10%
Plant in Service	$1,734,918
Accumulated Depreciation	1,051,670
Construction Work in Progress	16,955
Palo Verde Unit 2
Interests in jointly-owned facilities
Percent Owned	16.80%
Plant in Service	556,472
Accumulated Depreciation	349,960
Construction Work in Progress	13,710
Palo Verde Common
Interests in jointly-owned facilities
Percent Owned	28.00%
Plant in Service	612,190
Accumulated Depreciation	224,208
Construction Work in Progress	68,896
Palo Verde Sale Leaseback
Interests in jointly-owned facilities
Plant in Service	351,050
Accumulated Depreciation	229,795
Construction Work in Progress	0
Four Corners Units 4, 5 and Common
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	811,648
Accumulated Depreciation	578,772
Construction Work in Progress	33,150
Navajo Generating Station Units 1, 2 and 3
Interests in jointly-owned facilities
Percent Owned	14.00%
Plant in Service	272,208
Accumulated Depreciation	159,198
Construction Work in Progress	2,716
Cholla common facilities
Interests in jointly-owned facilities
Percent Owned	63.30%
Plant in Service	155,856
Accumulated Depreciation	49,954
Construction Work in Progress	866
ANPP 500kV System
Interests in jointly-owned facilities
Percent Owned	33.60%
Plant in Service	106,369
Accumulated Depreciation	35,035
Construction Work in Progress	3,731
Navajo Southern System
Interests in jointly-owned facilities
Percent Owned	22.50%
Plant in Service	59,994
Accumulated Depreciation	18,119
Construction Work in Progress	1,113
Palo Verde - Yuma 500kV System
Interests in jointly-owned facilities
Percent Owned	18.20%
Plant in Service	12,925
Accumulated Depreciation	4,943
Construction Work in Progress	12
Four Corners Switchyards
Interests in jointly-owned facilities
Percent Owned	47.50%
Plant in Service	33,034
Accumulated Depreciation	10,035
Construction Work in Progress	386
Phoenix - Mead System
Interests in jointly-owned facilities
Percent Owned	17.10%
Plant in Service	39,777
Accumulated Depreciation	12,843
Construction Work in Progress	105
Palo Verde - Estrella 500kV System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	89,572
Accumulated Depreciation	16,491
Construction Work in Progress	736
Morgan-Pinnacle Peak System
Interests in jointly-owned facilities
Percent Owned	64.40%
Plant in Service	130,840
Accumulated Depreciation	8,970
Construction Work in Progress	1,690
Round Valley System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	497
Accumulated Depreciation	276
Construction Work in Progress	1
Palo Verde - Morgan System
Interests in jointly-owned facilities
Percent Owned	90.00%
Plant in Service	0
Accumulated Depreciation	0
Construction Work in Progress	69,377
Hassayampa - North Gila System
Interests in jointly-owned facilities
Percent Owned	80.00%
Plant in Service	8,902
Accumulated Depreciation	3,634
Construction Work in Progress	$142,645

Commitments_and_Contingencies_1

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended
	Jul. 07, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 18, 2014	Dec. 31, 1986
	Jul. 07, 2014	Trust	Dec. 31, 2013	Dec. 31, 2012	Aug. 18, 2014	Trust
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Litigation settlement, amount	$3,250,000
Maximum insurance against public liability per occurrence for a nuclear incident		13,600,000,000
Maximum available nuclear liability insurance		375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program		13,200,000,000
Maximum assessment per reactor for each nuclear incident		127,300,000
Annual limit per incident with respect to maximum assessment		19,000,000
Number of VIE lessor trusts		3				3
Maximum potential retrospective assessment per incident of APS		111,000,000
Annual payment limitation with respect to maximum potential retrospective assessment		16,500,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde		2,750,000,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment		20,000,000
Collateral assurance provided based on rating triggers		53,000,000
Period to provide collateral assurance based on rating triggers		20 days
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2015		723,000,000
2016		747,000,000
2017		630,000,000
2018		610,000,000
2019		583,000,000
Thereafter		8,200,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Coal take-or-pay commitments
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2015		151,000,000
2016		171,000,000
2017		195,000,000
2018		190,000,000
2019		194,000,000
Thereafter		2,469,000,000
Total obligation		3,400,000,000
Present value of commitments		2,200,000,000
Total purchases		237,000,000	188,000,000	196,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Renewable energy credits
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2015		46,000,000
2016		42,000,000
2017		42,000,000
2018		42,000,000
2019		42,000,000
Thereafter		448,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2015		1,000,000
2016		15,000,000
2017		17,000,000
2018		18,000,000
2019		19,000,000
Thereafter		281,000,000
Total obligation		198,000,000	207,000,000
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Palo Verde Nuclear Generating Station [Abstract]
Litigation settlement, amount					57,400,000
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste \| ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Litigation settlement, amount					$16,700,000

Commitments_and_Contingencies_2

Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	0 Months Ended			12 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Jul. 07, 2014	Jan. 22, 2014	Sep. 08, 2011	Dec. 31, 2014	Aug. 06, 2013
	Requirement	Entity	MW		Defendant
		Requirement	kV
			Customer
Superfund
Costs related to investigation and study under Superfund site				$2
Southwest Power Outage
Power outage capacity of transmission line that tripped out of service			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			69,700
Capacity of firm load that were reported to have been affected due to outages affecting portions of southern Arizona, southern California and northern Mexico (in MW)			7,900
Number of customers that were reported to have been affected due to outages			2,700,000
Number of entities alleged		6
Number of reliability standard requirements violations		7
Number of reliability standard requirements neither admitted nor denied violations in settlement	4
Amount of civil penalty agreed in settlement	3.25
Civil penalty amount required to be paid in equal parts	2
Civil penalty amount offset in exchange for completing certain reliability enhancements	$1.25
Contaminated groundwater wells
Superfund
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit					24

Commitments_and_Contingencies_3

Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	23-May-13
Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost	$15,000,000
Cholla \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost	85,000,000
Cholla Units 1-3 \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost	130,000,000
New Mexico Tax Matter \| Four Corners
Environmental Matters [Abstract]
Coal severance surtax, penalty, and interest		30,000,000
New Mexico Tax Matter \| Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Share of the assessment		12,000,000
Letter of credit \| ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit	109,000,000
Equity Lessors Sale Leaseback Letter of Credit \| ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit	23,000,000
Natural Gas Tolling Letter of Credit \| ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit	5,000,000
Four Corners Units 4 and 5 \| Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost	40,000,000
Four Corners Units 4 and 5 \| Navajo Plant \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost	200,000,000
Four Corners Units 4 and 5 \| Cholla \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost	200,000,000
Four Corners Units 4 and 5 \| Natural Gas Tolling Letter of Credit \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Percentage of share of cost of control	63.00%
Additional percentage share of cost of control	7.00%
Minimum \| Four Corners Units 4 and 5 \| Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost	$350,000,000

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
Asset Retirement Obligations (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Changes attributable to:
Asset retirement obligations, current	$32,462,000	$32,896,000
ARIZONA PUBLIC SERVICE COMPANY
Change in asset retirement obligations
Beginning balance	347,000,000	357,000,000
Changes attributable to:
Accretion expense	24,000,000	24,000,000
Settlements	-30,000,000	-12,000,000
Assumed SCE's obligation	0	34,000,000
Estimated cash flow revisions	44,000,000	-56,000,000
Newly incurred obligation	6,000,000	0
Ending balance	391,000,000	347,000,000
Asset retirement obligations, current	32,462,000	32,896,000
Four Corners Units 1 Through 3 \| ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Estimated cash flow revisions	24,000,000	4,000,000
Solar Facility \| ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Newly incurred obligation	6,000,000
Palo Verde Nuclear Facilities and Certain other Generation Transmission and Distribution Assets \| ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Estimated cash flow revisions	20,000,000	52,000,000
Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Assumed SCE's obligation		$34,000,000

Selected_Quarterly_Financial_D2

Selected Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES	$726,450	$1,172,667	$906,264	$686,251	$699,762	$1,152,392	$915,822	$686,652	$3,491,632	$3,454,628	$3,301,804
Operations and maintenance	260,503	223,418	211,222	212,882	238,854	233,323	229,300	223,250	908,025	924,727	884,769
Operating income	60,184	421,775	254,113	75,170	83,900	415,688	259,812	86,923	811,242	846,323	851,755
Income taxes	5,007	134,753	74,540	6,405	9,167	131,912	77,043	12,469	220,705	230,591	237,317
Income from continuing operations	9,535	248,086	141,384	24,691	32,814	234,718	139,598	32,836	423,696	439,966	418,993
Net income attributable to common shareholders	5,410	243,961	132,458	15,766	24,260	226,163	131,207	24,444	397,595	406,074	381,542
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$0.05	$2.20	$1.20	$0.14	$0.22	$2.06	$1.19	$0.22	$3.59	$3.69	$3.48
Net income attributable to common shareholders â€” diluted (in dollars per share)	$0.05	$2.20	$1.19	$0.14	$0.22	$2.04	$1.18	$0.22	$3.58	$3.66	$3.45
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Electric domestic regulated revenue	725,633	1,172,190	905,578	685,545	698,824	1,151,535	915,065	685,827	3,488,946	3,451,251	3,293,489
Operations and maintenance	253,668	212,430	208,059	208,285	229,505	222,617	224,950	220,752	882,442	897,824	873,916
Operating income	54,835	287,928	180,394	69,635	79,024	284,251	183,728	74,862	592,792	621,865	605,529
Income taxes									237,360	245,095	244,396
Net income attributable to common shareholders	$15,738	$251,047	$134,916	$19,518	$30,024	$234,954	$133,949	$26,042	$421,219	$424,969	$395,497

Fair_Value_Measurements_Fair_V

Fair Value Measurements - Fair Value of Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Assets
Nuclear decommissioning trust	$713,866,000	$642,007,000
Total assets	33,000,000	41,000,000
Fair value measurement on a recurring basis
Assets
Other	-23,000,000	-9,000,000
Derivative assets	31,000,000	41,000,000
Other	-7,000,000	-3,000,000
Nuclear decommissioning trust	714,000,000	642,000,000
Other	-30,000,000	-12,000,000
Total assets	745,000,000	683,000,000
Liabilities
Other	59,000,000	21,000,000
Derivative Liability	-110,000,000	-102,000,000
Fair value measurement on a recurring basis \| US commingled equity funds
Assets
Nuclear decommissioning trust	310,000,000	272,000,000
Fair value measurement on a recurring basis \| U.S. Treasury
Assets
Nuclear decommissioning trust	119,000,000	107,000,000
Fair value measurement on a recurring basis \| Cash and cash equivalent funds
Assets
Other	-7,000,000	-3,000,000
Nuclear decommissioning trust	4,000,000	8,000,000
Fair value measurement on a recurring basis \| Corporate debt
Assets
Nuclear decommissioning trust	109,000,000	88,000,000
Fair value measurement on a recurring basis \| Mortgage-backed securities
Assets
Nuclear decommissioning trust	89,000,000	85,000,000
Fair value measurement on a recurring basis \| Municipality bonds
Assets
Nuclear decommissioning trust	69,000,000	71,000,000
Fair value measurement on a recurring basis \| Other
Assets
Nuclear decommissioning trust	14,000,000	11,000,000
Fair value measurement on a recurring basis \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Decommissioning fund investments, gross fair value	119,000,000	107,000,000
Gross assets, fair value disclosure	119,000,000	107,000,000
Fair value measurement on a recurring basis \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	119,000,000	107,000,000
Fair value measurement on a recurring basis \| Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	21,000,000	9,000,000
Decommissioning fund investments, gross fair value	602,000,000	538,000,000
Gross assets, fair value disclosure	623,000,000	547,000,000
Liabilities
Gross derivative liability	-95,000,000	-33,000,000
Fair value measurement on a recurring basis \| Significant Other Observable Inputs (Level 2) \| US commingled equity funds
Assets
Decommissioning fund investments, gross fair value	310,000,000	272,000,000
Fair value measurement on a recurring basis \| Significant Other Observable Inputs (Level 2) \| Cash and cash equivalent funds
Assets
Decommissioning fund investments, gross fair value	11,000,000	11,000,000
Fair value measurement on a recurring basis \| Significant Other Observable Inputs (Level 2) \| Corporate debt
Assets
Decommissioning fund investments, gross fair value	109,000,000	88,000,000
Fair value measurement on a recurring basis \| Significant Other Observable Inputs (Level 2) \| Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	89,000,000	85,000,000
Fair value measurement on a recurring basis \| Significant Other Observable Inputs (Level 2) \| Municipality bonds
Assets
Decommissioning fund investments, gross fair value	69,000,000	71,000,000
Fair value measurement on a recurring basis \| Significant Other Observable Inputs (Level 2) \| Other
Assets
Decommissioning fund investments, gross fair value	14,000,000	11,000,000
Fair value measurement on a recurring basis \| Significant Unobservable Inputs (Level 3)
Assets
Gross derivative assets	33,000,000	41,000,000
Gross assets, fair value disclosure	33,000,000	41,000,000
Liabilities
Gross derivative liability	($74,000,000)	($90,000,000)

Fair_Value_Measurements_Level_

Fair Value Measurements - Level 3 Quantative Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$33	$41
Liabilities	74	90
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	30	40
Liabilities	56	66
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)	19.51	24.89
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)	56.72	65.04
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)	35.27	41.09
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	15	19
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)	32.14	39.91
Natural gas forward price (per MMbtu)	3.18	3.57
Implied electricity price volatilities (as a percent)	23.00%	35.00%
Implied natural gas price volatilities (as a percent)	23.00%	22.00%
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)	66.09	85.41
Natural gas forward price (per MMbtu)	3.29	3.8
Implied electricity price volatilities (as a percent)	63.00%	94.00%
Implied natural gas price volatilities (as a percent)	41.00%	36.00%
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)	45.83	58.7
Natural gas forward price (per MMbtu)	3.25	3.71
Implied electricity price volatilities (as a percent)	41.00%	59.00%
Implied natural gas price volatilities (as a percent)	31.00%	27.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	3	1
Liabilities	$3	$5
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)	2.98	3.47
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)	4.13	4.31
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)	3.45	3.87

Fair_Value_Measurements_Fair_V1

Fair Value Measurements Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Total net gains (losses) realized/unrealized:
Net derivative beginning balance	($49,000,000)	($48,000,000)
Included in earnings	0	0
Included in OCI	0	0
Deferred as a regulatory asset or liability	0	-10,000,000
Settlements	12,000,000	10,000,000
Transfers into Level 3 from Level 2	-2,000,000	0
Transfers from Level 3 into Level 2	-2,000,000	-1,000,000
Net derivative ending balance	-41,000,000	-49,000,000
Net unrealized gains included in earnings related to instruments still held at end of period	0	0
Significant level 1 transfers	$0

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Income from continuing operations attributable to common shareholders	$397,595	$406,074	$387,380
Average common shares outstanding â€” basic (in shares)	110,626	109,984	109,510
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Contingently issuable performance shares and restricted stock units	552	822	1,017
Average common shares outstanding â€” diluted	111,178	110,806	110,527
Income from continuing operations attributable to common shareholders â€” basic (in dollars per share)	$3.59	$3.69	$3.54
Income from continuing operations attributable to common shareholders â€” diluted (in dollars per share)	$3.58	$3.66	$3.50

StockBased_Compensation_StockB

Stock-Based Compensation Stock-Based Compensation - Summary of Restricted Stock and Stock Units Grants (Details) (Restricted stock units and stock grants, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted stock units and stock grants
Stocks granted and the weighted average fair value
Units granted (in shares)	130,273	129,620	202,278
Grant date fair value (in dollars per share)	$54.91	$55.21	$49.31

StockBased_Compensation_StockB1

Stock-Based Compensation Stock-Based Compensation - Status of Restricted Stock Units and Stock Grants (Details) (Restricted stock units and stock grants, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted stock units and stock grants
Nonvested shares
Balance at the beginning of the period (in shares)	397,976
Granted (in shares)	130,273
Vested (in shares)	-161,283
Forfeited (in shares)	-13,067
Balance at the end of the period (in shares)	353,899	397,976
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$47.74
Granted (in dollars per share)	$54.91	$55.21	$49.31
Vested (in dollars per share)	$45.55
Forfeited (in dollars per share)	$51.53
Balance at the end of the period (in dollars per share)	$51.23	$47.74

StockBased_Compensation_StockB2

Stock-Based Compensation Stock-Based Compensation - Cash Required to Settle Payments on Restricted Stock Units (Details) (Restricted stock units and stock grants, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
2008 Grant
Stock-Based Compensation
Cash required to settle the payment for grant	$0	$0	$1.90
2009 Grant
Stock-Based Compensation
Cash required to settle the payment for grant	0	3	1.7
2010 Grant
Stock-Based Compensation
Cash required to settle the payment for grant	2.3	2.3	0.6
2011 Grant
Stock-Based Compensation
Cash required to settle the payment for grant	2.4	2.5	0.7
2012 Grant
Stock-Based Compensation
Cash required to settle the payment for grant	2.1	2.2	0
2013 Grant
Stock-Based Compensation
Cash required to settle the payment for grant	$2.10	$0	$0

StockBased_Compensation_StockB3

Stock-Based Compensation Stock-Based Compensation - Summary of Performance Shares (Details) (Performance Share Awards, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Performance Share Awards
Stock-Based Compensation
Units granted (in shares)	166,244	176,332	185,878
Grant date fair value (in dollars per share)	$54.86	$55.45	$47.40

StockBased_Compensation_StockB4

Stock-Based Compensation Stock-Based Compensation - Performance Shares Roll-Forward (Details) (Performance Share Awards, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Performance Share Awards
Nonvested shares
Balance at the beginning of the period (in shares)	344,396
Granted (in shares)	166,244
Increase in performance factor	86,558
Vested (in shares)	-258,224
Forfeited (in shares)	-14,744
Balance at the end of the period (in shares)	324,230	344,396
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$51.13
Grant date fair value (in dollars per share)	$54.86	$55.45	$47.40
Increase in performance factor (in dollars per share)	$47.40
Vested (in dollars per share)	$47.40
Forfeited (in dollars per share)	$53.30
Balance at the end of the period (in dollars per share)	$54.92	$51.13

StockBased_Compensation_Detail

Stock-Based Compensation (Details) (USD $)	12 Months Ended			0 Months Ended		1 Months Ended	0 Months Ended	3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 15, 2014	Feb. 15, 2013	Dec. 31, 2012	Feb. 15, 2015	Mar. 31, 2014	16-May-12
Stock Options
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted	$15
Expected weighted-average period of recognition of unrecognized compensation cost	2 years
Total fair value of shares vested	20	20	19
Compensation cost that has been charged against income	33	25	32
Total income tax benefit recognized	13	10	13
2013 Grant
Stock-Based Compensation
Common shares to be available for grant under the 2012 Long Term Incentive Plan									4,595,500
Restricted stock unit awards
Restricted Stock Unit Awards and Stock Grants
Percentage of cash that the participant may elect as a dividend for the first option available under the plan	50.00%
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan	50.00%
Percentage of cash that the participant may elect as a dividend equivalent deferral under the first option available under the plan	50.00%
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan	50.00%
Percentage of cash that the participant may elect as a dividend equivalent deferral under the first option available under the plan	50.00%
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan	50.00%
Vesting period	4 years
Percentage of awards vesting on February 15, 2013					50.00%
Percentage of awards vesting on February 15, 2014				25.00%
Restricted stock units and stock grants
Restricted Stock Unit Awards and Stock Grants
Granted (in shares)	130,273
Performance Share Awards
Restricted Stock Unit Awards and Stock Grants
Granted (in shares)	166,244
Performance Share Awards \| 2013 Grant
Performance Shares
Performance period			3 years
Percentage of the awards that vest based on a percentile ranking of total shareholder return		50.00%
Percentage of the awards that vest based on non-financial separate performance metrics		50.00%
Number of non-financial separate performance metrics based on which awards vest		6
Performance Share Awards \| 2013 Grant \| Maximum
Performance Shares
Exact number of shares issued as a percentage of the target award			200.00%
Performance Share Awards \| 2013 Grant \| Minimum
Performance Shares
Exact number of shares issued as a percentage of the target award			0.00%
Performance Share Awards \| 2008 Grant
Performance Shares
Number of performance element criteria	2
Performance period	3 years
Performance Share Awards \| 2012 Grant
Performance Shares
Percentage of the awards that vest based on a percentile ranking of total shareholder return	50.00%
Percentage of the awards that vest based on non-financial separate performance metrics	50.00%
Number of non-financial separate performance metrics based on which awards vest	6
Performance Share Awards \| 2012 Grant \| Maximum
Performance Shares
Exact number of shares issued as a percentage of the target award		200.00%
Performance Share Awards \| 2012 Grant \| Minimum
Performance Shares
Exact number of shares issued as a percentage of the target award		0.00%
Performance Share Awards \| 2014 Grant
Performance Shares
Performance period		3 years
Percentage of the awards that vest based on a percentile ranking of total shareholder return			50.00%
Percentage of the awards that vest based on non-financial separate performance metrics			50.00%
Number of non-financial separate performance metrics based on which awards vest			6
Performance Share Awards \| 2014 Grant \| Maximum
Performance Shares
Exact number of shares issued as a percentage of the target award	200.00%
Performance Share Awards \| 2014 Grant \| Minimum
Performance Shares
Exact number of shares issued as a percentage of the target award	0.00%
Retention Units
Restricted Stock Unit Awards and Stock Grants
Granted (in shares)						50,617
Additional shares to be granted as retention award if performance requirements are met						33,745
ARIZONA PUBLIC SERVICE COMPANY
Stock Options
Compensation cost that has been charged against income	$33	$25	$32
Subsequent event \| Restricted stock unit awards
Restricted Stock Unit Awards and Stock Grants
Percentage of awards vesting on February 15, 2015							25.00%
Chief Executive Officer \| Restricted stock unit awards
Restricted Stock Unit Awards and Stock Grants
Number of shares of stock awarded for each unit	1
Officer \| Restricted stock unit awards
Restricted Stock Unit Awards and Stock Grants
Number of shares of stock awarded for each unit								1

Derivative_Accounting_Details

Derivative Accounting (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Counterparty	Dec. 31, 2013
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%
Designated as Hedging Instruments
Derivative Accounting
Derivative Liability	$4,000,000	$5,000,000
ARIZONA PUBLIC SERVICE COMPANY
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change	100.00%
Commodity Contracts
Derivative Accounting
Derivative Liability	110,278,000	102,207,000
Concentration of credit risk, number of counterparties	1
Concentration risk	90.00%
Derivative assets	31,405,000	40,984,000
Additional collateral to counterparties for energy related non-derivative instrument contracts	175,000,000
Commodity Contracts \| Designated as Hedging Instruments
Derivative Accounting
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income	($6,000,000)

Derivative_Accounting_Outstand

Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details)	Dec. 31, 2014
	GW
Commodity - Power
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	3,915
Commodity - Gas
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	136,000

Derivative_Accounting_Gains_an

Derivative Accounting - Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Designated as Hedging Instruments
Derivative Instruments in Designated Cash Flows Hedges
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	($372,000)	($353,000)	($37,663,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)	-21,415,000	-44,219,000	-99,007,000
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0	0	117,000
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	0	0	1,800,000
Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	-66,043,000	-10,160,000	-2,644,000
Revenue \| Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	324,000	289,000	103,000
Fuel and purchased power \| Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	($66,367,000)	($10,449,000)	($2,747,000)

Derivative_Accounting_Derivati

Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Commodity Contracts
Assets
Gross Recognized Derivatives	$53,372	$49,951
Amounts Offset	-22,317	-8,974
Net Recognized Derivatives	31,055	40,977
Other	350	7
Amount Reported on Balance Sheet	31,405	40,984
Liabilities
Gross Recognized Derivatives	-169,052	-122,663
Amounts Offset	66,217	27,974
Net Recognized Derivatives	-102,835	-94,689
Other	-7,443	-7,518
Amount Reported on Balance Sheet	-110,278	-102,207
Assets and Liabilities
Gross Recognized Derivatives	-115,680	-72,712
Amounts Offset	43,900	19,000
Net Recognized Derivatives	-71,780	-53,712
Other	-7,093	-7,511
Amount Reported on Balance Sheet	-78,873	-61,223
Commodity Contracts \| Current Assets
Assets
Gross Recognized Derivatives	28,562	24,587
Amounts Offset	-15,127	-7,425
Net Recognized Derivatives	13,435	17,162
Other	350	7
Amount Reported on Balance Sheet	13,785	17,169
Commodity Contracts \| Investments and Other Assets
Assets
Gross Recognized Derivatives	24,810	25,364
Amounts Offset	-7,190	-1,549
Net Recognized Derivatives	17,620	23,815
Other	0	0
Amount Reported on Balance Sheet	17,620	23,815
Commodity Contracts \| Current Liabilities
Liabilities
Gross Recognized Derivatives	-86,062	-50,540
Amounts Offset	33,829	26,166
Net Recognized Derivatives	-52,233	-24,374
Other	-7,443	-7,518
Amount Reported on Balance Sheet	-59,676	-31,892
Assets and Liabilities
Amounts Offset	43,900	19,000
Commodity Contracts \| Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	-82,990	-72,123
Amounts Offset	32,388	1,808
Net Recognized Derivatives	-50,602	-70,315
Other	0	0
Amount Reported on Balance Sheet	-50,602	-70,315
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	($4,000)	($5,000)

Derivative_Accounting_Credit_R

Derivative Accounting - Credit Risk and Related Contingent Features (Details) (Commodity Contracts, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Commodity Contracts
Credit Risk and Credit-Related Contingent Features
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$169
Cash Collateral Posted	44
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	$80

Other_Income_and_Other_Expense2

Other Income and Other Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other income:
Interest income	$1,010	$1,629	$1,239
Investment gains - net	8,386		0
Miscellaneous	212	75	367
Total other income	9,608	1,704	1,606
Other expense:
Non-operating costs	-9,657	-8,207	-7,777
Investment loss - net	-9,426	-3,711	-2,453
Miscellaneous	-2,663	-4,106	-9,612
Total other expense	-21,746	-16,024	-19,842
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	689	1,234	310
Investment gains - net	8,386	0	0
Miscellaneous	2,220	2,662	2,558
Total other income	11,295	3,896	2,868
Other expense:
Non-operating costs	-10,397	-9,626	-8,706
Asset dispositions	-615	-4,992	-1,511
Miscellaneous	-2,391	-5,831	-10,933
Total other expense	($13,403)	($20,449)	($21,150)

Palo_Verde_Sale_Leaseback_Vari2

Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 07, 2014	Dec. 31, 1986
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Lease	Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$26,101,000	$33,892,000	$31,622,000
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts	3				3
Annual lease payments	49,000,000
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	26,101,000	33,892,000	31,613,000
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	26,000,000	34,000,000	32,000,000
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events	123,000,000
VIE debt to be assumed upon the occurrence of certain unlikely events	13,000,000
Period Through 2023 \| ARIZONA PUBLIC SERVICE COMPANY \| Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained				1
Period Through 2033 \| ARIZONA PUBLIC SERVICE COMPANY \| Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained				2
Period 2016 through 2023 \| ARIZONA PUBLIC SERVICE COMPANY \| Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments	23,000,000
Period 2024 through 2033 \| ARIZONA PUBLIC SERVICE COMPANY \| Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments	$16,000,000
Maximum \| Period 2024 through 2033 \| ARIZONA PUBLIC SERVICE COMPANY \| Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Lease period				2 years

Palo_Verde_Sale_Leaseback_Vari3

Palo Verde Sale Leaseback Variable Interest Entities Palo Verde Leaseback Variable Interest Entities - Schedule of VIEs (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$121,255	$125,125
Current maturities of long-term debt (Note 6)	383,570	540,424
Equity - noncontrolling interests	151,609	145,990
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	121,255	125,125
Current maturities of long-term debt (Note 6)	383,570	540,424
Equity - noncontrolling interests	151,609	145,990
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	121,000	125,000
Current maturities of long-term debt (Note 6)	13,000	26,000
Long-term debt excluding current maturities	0	13,000
Equity - noncontrolling interests	$152,000	$146,000

Nuclear_Decommissioning_Trusts2

Nuclear Decommissioning Trusts (Details) (USD $)	12 Months Ended
Nuclear Decommissioning Trusts (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Nuclear decommissioning trust fund assets
Fair Value	$713,866,000	$642,007,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities	356,195,000	446,025,000	417,603,000
Fair value of fixed income securities, summarized by contractual maturities
Total	713,866,000	642,007,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	713,866,000	642,007,000
Unrealized Gains	176,000,000	140,000,000
Unrealized Losses	-1,000,000	-6,000,000
Net payables for securities purchases	-7,000,000	-3,000,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	5,000,000	6,000,000	7,000,000
Realized losses	-5,000,000	-7,000,000	-4,000,000
Proceeds from the sale of securities	356,195,000	446,025,000	417,603,000
Fair value of fixed income securities, summarized by contractual maturities
Total	713,866,000	642,007,000
ARIZONA PUBLIC SERVICE COMPANY \| Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	310,000,000	272,000,000
Unrealized Gains	159,000,000	129,000,000
Fair value of fixed income securities, summarized by contractual maturities
Total	310,000,000	272,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	411,000,000	373,000,000
Unrealized Gains	17,000,000	11,000,000
Unrealized Losses	-1,000,000	-6,000,000
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	14,000,000
1 year - 5 years	116,000,000
5 years - 10 years	122,000,000
Greater than 10 years	159,000,000
Total	$411,000,000	$373,000,000

Changes_in_Accumulated_Other_C2

Changes in Accumulated Other Comprehensive Loss (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	($78,053)	($114,008)
OCI (loss) before reclassifications	-6,229	5,381
Amounts reclassified from accumulated other comprehensive loss	16,141	30,574
Total other comprehensive income	9,912	35,955	38,155
Ending balance	-68,141	-78,053	-114,008
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-23,058	-49,592
OCI (loss) before reclassifications	-810	-213
Amounts reclassified from accumulated other comprehensive loss	13,483	26,747
Total other comprehensive income	12,673	26,534
Ending balance	-10,385	-23,058
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-54,995	-64,416
OCI (loss) before reclassifications	-5,419	5,594
Amounts reclassified from accumulated other comprehensive loss	2,658	3,827
Total other comprehensive income	-2,761	9,421
Ending balance	-57,756	-54,995
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-53,372	-89,095
OCI (loss) before reclassifications	-11,224	5,173
Amounts reclassified from accumulated other comprehensive loss	16,263	30,550
Total other comprehensive income	5,039	35,723	36,496
Ending balance	-48,333	-53,372	-89,095
ARIZONA PUBLIC SERVICE COMPANY \| Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-23,059	-49,592
OCI (loss) before reclassifications	-809	-214
Amounts reclassified from accumulated other comprehensive loss	13,483	26,747
Total other comprehensive income	12,674	26,533
Ending balance	-10,385	-23,059
ARIZONA PUBLIC SERVICE COMPANY \| Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-30,313	-39,503
OCI (loss) before reclassifications	-10,415	5,387
Amounts reclassified from accumulated other comprehensive loss	2,780	3,803
Total other comprehensive income	-7,635	9,190
Ending balance	($37,948)	($30,313)

SCHEDULE_I_CONDENSED_FINANCIAL1

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Statement of Comprehensive Income (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONDENSED FINANCIAL STATEMENTS
Operating revenues	$726,450	$1,172,667	$906,264	$686,251	$699,762	$1,152,392	$915,822	$686,652	$3,491,632	$3,454,628	$3,301,804
Operating expenses									2,680,390	2,608,305	2,450,049
OPERATING INCOME	60,184	421,775	254,113	75,170	83,900	415,688	259,812	86,923	811,242	846,323	851,755
Other
Total									18,652	11,261	4,200
Interest expense									200,950	201,888	214,616
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									644,401	670,557	656,310
Income tax benefit	5,007	134,753	74,540	6,405	9,167	131,912	77,043	12,469	220,705	230,591	237,317
INCOME FROM CONTINUING OPERATIONS	9,535	248,086	141,384	24,691	32,814	234,718	139,598	32,836	423,696	439,966	418,993
Income (loss) from discontinued operations - net of income taxes									0	0	-5,829
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	5,410	243,961	132,458	15,766	24,260	226,163	131,207	24,444	397,595	406,074	381,542
Other comprehensive income									9,912	35,955	38,155
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									407,507	442,029	419,697
Pinnacle West
CONDENSED FINANCIAL STATEMENTS
Operating revenues									642	799	6,133
Operating expenses									23,507	24,930	12,125
OPERATING INCOME									-22,865	-24,131	-5,992
Other
Equity in earnings of subsidiaries									411,528	420,926	391,528
Other expense									-3,276	-1,999	-2,001
Total									408,252	418,927	389,527
Interest expense									3,663	3,226	4,868
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									381,724	391,570	378,667
Income tax benefit									-15,871	-14,504	-7,079
INCOME FROM CONTINUING OPERATIONS									397,595	406,074	385,746
Income (loss) from discontinued operations - net of income taxes										0	-4,204
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									397,595	406,074	381,542
Other comprehensive income									9,912	35,955	38,155
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									$407,507	$442,029	$419,697

SCHEDULE_I_CONDENSED_FINANCIAL2

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT- Consolidated Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current assets
Cash and cash equivalents	$7,604	$9,526	$26,202	$33,583
Accounts receivable	297,740	299,904
Income tax receivable	3,098	135,517
Other current assets	38,817	39,895
Total current assets	973,435	1,043,609
Investments and other assets
Other assets	54,047	60,875
Total investments and other assets	785,533	726,697
Total Assets	14,313,532	13,508,686
Current liabilities
Accounts payable	295,211	284,516
Accrued taxes (Note 4)	140,613	130,998
Common dividends payable	65,790	62,528
Other current liabilities	178,962	158,540
Total current liabilities	1,559,143	1,618,644
Long-term debt less current maturities	3,031,215	2,796,465
Deferred credits and other
Deferred income taxes	2,582,636	2,351,882
Pension and other postretirement liabilities	453,736	513,628
Other	188,286	185,659
Total deferred credits and other	5,204,072	4,753,117
Common stock equity
Common stock	2,512,970	2,491,558
Accumulated other comprehensive loss	-68,141	-78,053	-114,008
Retained earnings	1,926,065	1,785,273
Total shareholdersâ€™ equity	4,367,493	4,194,470
Noncontrolling interests	151,609	145,990
Total equity	4,519,102	4,340,460	4,102,289	3,930,586
Total Liabilities and Equity	14,313,532	13,508,686
Pinnacle West
Current assets
Cash and cash equivalents	3,088	5,798	22,679	12,710
Accounts receivable	99,958	80,108
Current deferred income taxes	66,979	93,185
Income tax receivable	7,329	1,853
Other current assets	124	242
Total current assets	177,478	181,186
Investments and other assets
Investments in subsidiaries	4,630,570	4,455,049
Other assets	43,051	13,789
Total investments and other assets	4,673,621	4,468,838
Total Assets	4,851,099	4,650,024
Current liabilities
Accounts payable	5,250	3,279
Accrued taxes (Note 4)	12,220	8,538
Common dividends payable	65,790	62,528
Other current liabilities	38,992	31,295
Total current liabilities	122,252	105,640
Long-term debt less current maturities	125,000	125,000
Deferred credits and other
Deferred income taxes	12,055	4,158
Pension and other postretirement liabilities	29,228	37,611
Other	43,462	37,155
Total deferred credits and other	84,745	78,924
Common stock equity
Common stock	2,509,569	2,487,250
Accumulated other comprehensive loss	-68,141	-78,053
Retained earnings	1,926,065	1,785,273
Total shareholdersâ€™ equity	4,367,493	4,194,470
Noncontrolling interests	151,609	145,990
Total equity	4,519,102	4,340,460
Total Liabilities and Equity	$4,851,099	$4,650,024

SCHEDULE_I_CONDENSED_FINANCIAL3

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Statements of Cash Flows (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities
Net Income	$423,696,000	$439,966,000	$413,164,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	496,487,000	492,322,000	481,262,000
Deferred income taxes	159,023,000	249,296,000	187,023,000
Accounts receivable	-52,672,000	-44,991,000	14,587,000
Accounts payable	-353,000	45,414,000	-96,600,000
Net cash flow provided by operating activities	1,099,627,000	1,153,307,000	1,171,122,000
Cash flows from investing activities
Net cash flow used for investing activities	-922,668,000	-1,009,401,000	-872,994,000
Cash flows from financing activities
Issuance of long-term debt	731,126,000	136,307,000	476,081,000
Dividends paid on common stock	-246,671,000	-235,244,000	-225,075,000
Repayment of long-term debt	-652,578,000	-122,828,000	-654,286,000
Common stock equity issuance	15,288,000	17,319,000	15,955,000
Other	161,000	299,000	170,000
Net cash flow used for financing activities	-178,881,000	-160,582,000	-305,509,000
NET DECREASE IN CASH AND CASH EQUIVALENTS	-1,922,000	-16,676,000	-7,381,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	9,526,000	26,202,000	33,583,000
CASH AND CASH EQUIVALENTS AT END OF YEAR	7,604,000	9,526,000	26,202,000
Pinnacle West
Cash Flows from Operating Activities
Net Income	397,595,000	406,074,000	381,542,000
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries - net	-411,528,000	-420,926,000	-391,528,000
Depreciation and amortization	94,000	95,000	94,000
Deferred income taxes	4,406,000	-28,806,000	-15,135,000
Accounts receivable	-22,945,000	21,671,000	28,763,000
Accounts payable	2,017,000	-2,449,000	879,000
Accrued taxes and income tax receivable - net	-1,795,000	1,402,000	-3,103,000
Dividends received from subsidiaries	253,600,000	242,100,000	222,200,000
Other	18,432,000	-15,065,000	-4,589,000
Net cash flow provided by operating activities	239,876,000	204,096,000	219,123,000
Cash flows from investing activities
Investments in subsidiaries	-10,236,000	-3,400,000	0
Repayments of loans from subsidiaries	322,000	2,149,000	996,000
Advances of loans to subsidiaries	-1,450,000	-2,099,000	-1,200,000
Net cash flow used for investing activities	-11,364,000	-3,350,000	-204,000
Cash flows from financing activities
Issuance of long-term debt	125,000,000	0	125,000,000
Dividends paid on common stock	-246,671,000	-235,244,000	-225,075,000
Repayment of long-term debt	-125,000,000	0	-125,000,000
Common stock equity issuance	15,288,000	17,319,000	15,955,000
Other	161,000	298,000	170,000
Net cash flow used for financing activities	-231,222,000	-217,627,000	-208,950,000
NET DECREASE IN CASH AND CASH EQUIVALENTS	-2,710,000	-16,881,000	9,969,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	5,798,000	22,679,000	12,710,000
CASH AND CASH EQUIVALENTS AT END OF YEAR	$3,088,000	$5,798,000	$22,679,000

SCHEDULE_II_RESERVE_FOR_UNCOLL1

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) (Reserve for uncollectibles., USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ARIZONA PUBLIC SERVICE COMPANY
Changes in reserve for uncollectibles
Balance at beginning of period	$3,203	$3,340	$3,748
Additions, Charged to cost and expenses	3,942	4,923	5,290
Additions, Charged to other accounts	0	0	0
Deductions	4,051	5,060	5,698
Balance at end of period	3,094	3,203	3,340
Pinnacle West
Changes in reserve for uncollectibles
Balance at beginning of period	3,203	3,340	3,748
Additions, Charged to cost and expenses	3,942	4,923	5,290
Additions, Charged to other accounts	0	0	0
Deductions	4,051	5,060	5,698
Balance at end of period	$3,094	$3,203	$3,340