Pinnacle West Capital (PNW) 10-Q 31 Oct 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 21, 2013
Document and Entity Information
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	764622
Document Type	10-Q
Document Period End Date	30-Sep-13
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		110,044,952
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
OPERATING REVENUES	$1,152,392	$1,109,475	$2,754,866	$2,608,682
OPERATING EXPENSES
Fuel and purchased power	350,953	302,894	859,216	783,926
Operations and maintenance	233,323	220,729	685,873	647,628
Depreciation and amortization	107,388	100,353	317,410	301,068
Taxes other than income taxes	43,256	36,507	124,091	120,271
Other expenses	1,784	1,022	5,853	5,323
Total	736,704	661,505	1,992,443	1,858,216
OPERATING INCOME	415,688	447,970	762,423	750,466
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,569	5,708	18,698	15,639
Other income (Note 10)	160	420	1,387	1,357
Other expense (Note 10)	-7,435	-5,696	-13,421	-12,433
Total	-1,706	432	6,664	4,563
INTEREST EXPENSE
Interest charges	50,587	52,242	151,372	162,209
Allowance for borrowed funds used during construction	-3,235	-3,830	-10,861	-10,428
Total	47,352	48,412	140,511	151,781
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	366,630	399,990	628,576	603,248
INCOME TAXES	131,912	147,116	221,424	219,160
INCOME FROM CONTINUING OPERATIONS	234,718	252,874	407,152	384,088
LOSS FROM DISCONTINUED OPERATIONS
Net of income tax benefit of $7 for three months ended September 30, 2012 and $1,047 for nine months ended September 30, 2012		-11		-1,595
NET INCOME	234,718	252,863	407,152	382,493
Less: Net income attributable to noncontrolling interests (Note 6)	8,555	8,040	25,338	23,582
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	226,163	244,823	381,814	358,911
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	110,009	109,555	109,935	109,449
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	111,053	110,655	110,913	110,420
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders - basic (in dollars per share)	$2.06	$2.23	$3.47	$3.29
Net income attributable to common shareholders - basic (in dollars per share)	$2.06	$2.23	$3.47	$3.28
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)	$2.04	$2.21	$3.44	$3.26
Net income attributable to common shareholders - diluted (in dollars per share)	$2.04	$2.21	$3.44	$3.25
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$0		$1.09	$1.57
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	226,163	244,834	381,814	360,515
Discontinued operations, net of tax		-11		-1,604
Net income attributable to common shareholders	$226,163	$244,823	$381,814	$358,911

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)	3 Months Ended	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2012	Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Income tax benefit on discontinued operations	$7	$1,047

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$234,718	$252,863	$407,152	$382,493
Derivative instruments:
Net unrealized loss, net of tax benefit of $95 and $47 for three months ended September 30, 2013 and 2012 and of $162 and $14,817 for nine months ended September 30, 2013 and 2012	-145	-72	-247	-22,696
Reclassification of net realized loss, net of tax benefit of $9,348 and $19,543 for three months ended September 30, 2013 and 2012 and $15,471 and $34,361 for nine months ended September 30, 2013 and 2012	14,310	29,935	23,685	52,632
Pension and other postretirement benefits activity, net of tax (expense) of $(625) and $(640) for three months ended September 30, 2013 and 2012 and $(807) and $(1,797) for nine months ended September 30, 2013 and 2012	957	980	1,235	2,752
Total other comprehensive income	15,122	30,843	24,673	32,688
COMPREHENSIVE INCOME	249,840	283,706	431,825	415,181
Less: Comprehensive income attributable to noncontrolling interests	8,555	8,040	25,338	23,582
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$241,285	$275,666	$406,487	$391,599

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net unrealized loss, tax benefit	$95	$47	$162	$14,817
Reclassification of net realized loss, tax benefit	9,348	19,543	15,471	34,361
Pension and other postretirement benefits activity, tax (expense)	($625)	($640)	($807)	($1,797)

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
CURRENT ASSETS
Cash and cash equivalents	$135,457	$26,202
Customer and other receivables	427,370	277,225
Accrued unbilled revenues	132,555	94,845
Allowance for doubtful accounts	-3,768	-3,340
Materials and supplies (at average cost)	223,385	218,096
Fossil fuel (at average cost)	34,959	31,334
Deferred income taxes	87,490	152,191
Income tax receivable (Note 5)	133,551	2,423
Assets from risk management activities (Note 7)	22,741	25,699
Deferred fuel and purchased power regulatory asset (Note 3)	37,383	72,692
Other regulatory assets (Note 3)	82,558	71,257
Other current assets	36,805	37,102
Total current assets	1,350,486	1,005,726
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	26,046	35,891
Nuclear decommissioning trust (Note 13)	612,640	570,625
Other assets	60,219	62,694
Total investments and other assets	698,905	669,210
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,597,995	14,346,367
Accumulated depreciation and amortization	-5,101,498	-4,929,613
Net	9,496,497	9,416,754
Construction work in progress	605,987	565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	126,092	128,995
Intangible assets, net of accumulated amortization	160,134	162,150
Nuclear fuel, net of accumulated amortization	140,356	122,778
Total property, plant and equipment	10,529,066	10,396,393
DEFERRED DEBITS
Regulatory assets (Note 3)	1,105,882	1,099,900
Income tax receivable (Note 5)		70,389
Other	138,332	137,997
Total deferred debits	1,244,214	1,308,286
TOTAL ASSETS	13,822,671	13,379,615
CURRENT LIABILITIES
Accounts payable	250,023	221,312
Accrued taxes (Note 5)	183,858	124,939
Accrued interest	45,811	49,380
Common dividends payable		59,789
Short-term borrowings		92,175
Current maturities of long-term debt (Note 2)	566,481	122,828
Customer deposits	77,254	79,689
Liabilities from risk management activities (Note 7)	53,468	73,741
Regulatory liabilities (Note 3)	88,409	88,116
Other current liabilities	181,639	171,573
Total current liabilities	1,446,943	1,083,542
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
Long-term debt less current maturities	2,782,901	3,160,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414	38,869
Total long-term debt less current maturities	2,820,315	3,199,088
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,363,783	2,151,371
Regulatory liabilities (Note 3)	798,226	759,201
Liability for asset retirements	364,635	357,097
Liabilities for pension and other postretirement benefits (Note 4)	939,414	1,058,755
Deferred investment tax credit	115,984	99,819
Liabilities from risk management activities (Note 7)	67,662	85,264
Customer advances	109,667	109,359
Coal mine reclamation	114,764	118,860
Unrecognized tax benefits (Note 5)	81,797	71,135
Other	178,053	183,835
Total deferred credits and other	5,133,985	4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 8)
Common stock, no par value	2,489,180	2,466,923
Treasury stock	-10,079	-4,211
Total common stock	2,479,101	2,462,712
Retained earnings	1,886,038	1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits	-63,181	-64,416
Derivative instruments	-26,154	-49,592
Total accumulated other comprehensive loss	-89,335	-114,008
Total shareholders' equity	4,275,804	3,972,806
Noncontrolling interests (Note 6)	145,624	129,483
Total equity	4,421,428	4,102,289
TOTAL LIABILITIES AND EQUITY	$13,822,671	$13,379,615

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
EQUITY (Note 8)
Common stock, par value

CONDENSED_CONSOLIDATED_STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$407,152	$382,493
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	377,971	360,570
Deferred fuel and purchased power	13,093	51,533
Deferred fuel and purchased power amortization	23,158	-91,894
Allowance for equity funds used during construction	-18,698	-15,639
Deferred income taxes	256,132	197,527
Deferred investment tax credit	16,164	8,974
Change in derivative instruments fair value	537	-943
Changes in current assets and liabilities:
Customer and other receivables	-178,029	-76,697
Accrued unbilled revenues	-37,710	-11,186
Materials, supplies and fossil fuel	-8,914	-23,873
Income tax receivable	-131,128	6,466
Other current assets	-12,246	-10,035
Accounts payable	44,704	-69,776
Accrued taxes	58,919	69,899
Other current liabilities	4,096	17,071
Change in margin and collateral accounts - assets	-327	1,980
Change in long-term income tax receivable	137,270	-1,320
Change in unrecognized tax benefits	-57,585	-3,554
Change in other long-term assets	-24,345	-13,885
Change in other long-term liabilities	-2,884	37,181
Change in margin and collateral accounts - liabilities	15,000	114,579
Net cash flow provided by operating activities	882,330	929,471
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	-581,515	-670,684
Contributions in aid of construction	34,910	41,451
Allowance for borrowed funds used during construction	-10,861	-10,428
Proceeds from nuclear decommissioning trust sales	363,944	295,126
Investment in nuclear decommissioning trust	-376,881	-308,063
Other	-1,553	-520
Net cash flow used for investing activities	-571,956	-653,118
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	351,081
Repayment of long-term debt	-72,777	-421,703
Short-term borrowings and payments - net	-92,175
Dividends paid on common stock	-174,485	-167,074
Common stock equity issuance	10,396	9,684
Distributions to noncontrolling interests	-9,197	-2,630
Other	812	185
Net cash flow used for financing activities	-201,119	-230,457
NET INCREASE IN CASH AND CASH EQUIVALENTS	109,255	45,896
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	26,202	33,583
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$135,457	$79,479

Consolidation_and_Nature_of_Op

Consolidation and Nature of Operations	9 Months Ended
	Sep. 30, 2013
Consolidation and Nature of Operations
Consolidation and Nature of Operations	1.                                      Consolidation and Nature of Operations
	The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS and El Dorado Investment Company (“El Dorado”) and formerly SunCor Development Company (“SunCor”).  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”) (see Note 6 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
	Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.
	Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.  These condensed consolidated financial statements and notes have been prepared consistently with the 2012 Form 10-K, with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.
	The following tables show the impact of the reclassifications to prior year (previously reported) amounts of the deferred investment tax credit and income tax receivables which have become more material in 2013 (dollars in thousands):
	Balance Sheets - December 31, 2012	As			Reclassifications			Amount
		previously						reported after
		reported						reclassifications
	Deferred investment tax credit	$	—		$	99,819		$	99,819
	Deferred credits — other	283,654			(99,819		)	183,835
	Statement of Cash Flows for the Nine	As			Reclassifications			Amount
	Months Ended September 30, 2012	previously						reported after
		reported						reclassifications
	Cash Flows from Operating Activities
	Deferred income taxes	$	206,501		$	(8,974	)	$	197,527
	Deferred investment tax credit	—			8,974			8,974
	Income tax receivable	—			6,466			6,466
	Accrued taxes	76,365			(6,466		)	69,899
	Change in long-term income tax receivable	—			(1,320		)	(1,320		)
	Change in other long-term assets	(15,205		)	1,320			(13,885		)
	Supplemental Cash Flow Information
	The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
		Nine Months Ended
		September 30,
		2013			2012
	Cash paid during the period for:
	Income taxes, net of (refunds)	$	3,412		$	(651	)
	Interest, net of amounts capitalized	141,047			152,582
	Significant non-cash investing and financing activities:
	Accrued capital expenditures	$	11,377		$	11,281

LongTerm_Debt_and_Liquidity_Ma

Long-Term Debt and Liquidity Matters	9 Months Ended
	Sep. 30, 2013
Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters	2.                                      Long-Term Debt and Liquidity Matters
	Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.
	Pinnacle West
	At September 30, 2013, Pinnacle West’s $200 million 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 September 30, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding, and no commercial paper borrowings.
	APS
	On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.
	On April 9, 2013, APS replaced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility.  The new revolving credit facility terminates in April 2018.
	On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029.  On May 28, 2013, we remarketed the bonds.  The interest rate for these bonds was set to a new term rate.  The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018.  During this time, the bonds will bear interest at a rate of 1.75% per annum.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2013 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.
	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.  These bonds were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.
	At September 30, 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 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 September 30, 2013, APS had no commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.
	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.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012.
	See “Financial Assurances” in Note 9 for a discussion of APS’s separate outstanding letters of credit.
	Debt Fair Value
	Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy.  See Note 12 for a discussion of the fair value hierarchy.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):
		As of				As of
		September 30, 2013				December 31, 2012
		Carrying		Fair Value		Carrying		Fair Value
		Amount				Amount
	Pinnacle West	$	125	$	125	$	125	$	125
	APS	3,262		3,538		3,197		3,750
	Total	$	3,387	$	3,663	$	3,322	$	3,875
	Debt Provisions
	An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At September 30, 2013, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.4 billion, and total capitalization was approximately $7.6 billion.  APS would be prohibited from paying dividends if payment would reduce its total shareholder equity below approximately $3.0 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 cash needs.

Regulatory_Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2013
Regulatory Matters
Regulatory Matters	3.                                      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 approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.
	Settlement Agreement
	The Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs (“Base Fuel Rate”) from $0.03757 to $0.03207 per kilowatt hour (“kWh”); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff (“RES”) surcharge to base rates in an estimated amount of $36.8 million.
	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 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 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 Settlement Agreement.
	Other key provisions of the 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 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 proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant (“Four Corners”);
	·                                          Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;
	·                                          Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
	·                                          Modifications to the Power Supply Adjustor (“PSA”), including the elimination of the 90/10 sharing provision;
	·                                          A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge (“DSMAC”) to recoup capital expenditures not required under the terms of the 2008 rate case 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 transmission cost adjustor (“TCA”) to streamline the process for future transmission-related rate changes; and
	·                                          Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
	The 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 2008 rate case settlement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.
	2008 General Retail Rate Case On-Going Impacts
	On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008.  The settlement agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:
	·                                          A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;
	·                                          Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and
	·                                          Various modifications to the existing energy efficiency, demand side management and renewable energy programs that require APS to, among other things, expand its conservation and demand side management programs through 2012 and its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand side management costs and incentives.
	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 December 14, 2011, the ACC voted to approve APS’s 2012 RES plan covering the 2012-2016 timeframe and authorized a total 2012 RES budget of $110 million.  On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requested 2013 RES funding of between $97 million and $107 million.  In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan.  That budget included $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for new commercial distributed energy production-based incentives beyond those for previously approved programs.  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.  In those proceedings, the ACC staff proposed a process whereby if a customer installs distributed generation without an incentive, the customer keeps the renewable energy credits generated and the RES distributed generation requirement is adjusted downward to reflect how much load is being served by renewable generation.  APS has endorsed the ACC staff’s proposed solution.  Finally, the ACC authorized an APS-led multi-session technical conference to consider APS’s net metering policy and the cost and benefits of distributed energy.  The multi-session technical conference concluded on May 28, 2013.
	On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either:  (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price.  APS also proposed that the ACC:  (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.  In its September 30, 2013 report, the ACC staff recognized that net metering shifts costs from solar customers to non-solar customers.  The staff recommended that the ACC wait until APS’s next rate case to address the issue.  As an alternative, the ACC staff recommended that the ACC assess one of two modest charges on new solar customers with a mechanism to return all incremental revenue collected from such charges to customers.
	On July 12, 2013, APS filed its annual RES implementation plan covering the 2014-2018 timeframe.  The plan requests a budget for 2014 of approximately $143 million.  The plan does not propose any new programs.  Rather, the plan requests the funding necessary to fulfill previously approved projects and commitments which are needed to comply with the RES targets and APS’s obligations under its 2008 rate case settlement agreement approved by the ACC, including the remaining 50 megawatts (“MW”) of the AZ Sun Program.  AZ Sun is a program that contemplates the development of photovoltaic solar plants which APS owns or will own.  On September 30, 2013, the ACC staff issued a report recommending approval of APS’s plan and proposed budget.
	Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC.
	On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011.  The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year.  This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (2.75% of total energy resources for the same two-year period).  The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs.  This amount will be recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).
	On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards require 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.  APS expects to receive a decision from the ACC in late 2013 or early 2014.
	On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards (including cost recovery methodology, incentives, and the determination of cost effectiveness) should be modified or abolished.
	PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.
	The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2013 and 2012 (dollars in millions):
		Nine Months Ended
		September 30,
		2013			2012
	Beginning balance	$	73		$	28
	Deferred fuel and purchased power costs — current period	(13		)	(52		)
	Amounts (collected from) credited to customers	(23		)	92
	Ending balance	$	37		$	68
	The PSA rate for the PSA year beginning February 1, 2013 is $0.0013 per kWh as compared to ($0.0042) per kWh for the prior year.  This represents a $0.0055 per kWh increase over the 2012 PSA charge.  This new rate is comprised of a forward component of ($0.0010) per kWh and a historical component of $0.0023 per kWh.  The Settlement Agreement allowed APS to exceed the $0.004 per kWh cap to PSA rate changes in this instance.  Any uncollected (overcollected) deferrals during the 2013 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2014.
	Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the United States Federal Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”).  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 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, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula.
	Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula.  Pursuant to the Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover the FERC-approved transmission charges went into effect automatically on June 1, 2013.
	As part of APS’s proposed acquisition of Southern California Edison’s (“SCE”) interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing transmission agreement between the parties that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California.  On May 1, 2013, APS submitted a request with FERC seeking authorization to cancel the transmission agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 10-year period.  On September 13, 2013, FERC issued an Order accepting the notice of cancellation, but denying APS’s request for rate recovery of the costs associated with the cancellation.  In accordance with its termination agreement with SCE (the “Termination Agreement”), APS believes that the denial by FERC of such rate recovery constitutes the failure of a condition that relieves APS of its obligations under the Termination Agreement.  The parties are in discussions concerning this matter.  If the matter is not resolved by negotiation, the Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter.
	Lost Fixed Cost Recovery (“LFCR”) 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 roof-top solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the recent rate case and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  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 its LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved an LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the Settlement Agreement went into effect on July 1, 2012.
	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 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.
	Regulatory Assets and Liabilities
	The detail of regulatory assets is as follows (dollars in millions):
		Remaining		September 30, 2013					December 31, 2012
		Amortization
		Period		Current			Non-Current		Current		Non-Current
	Pension and other postretirement benefits		(a)	$	—		$	754	$	—	$	780
	Income taxes — allowance for equity funds used during construction	2043		4			105		4		92
	Deferred fuel and purchased power — mark-to-market (Note 7)	2016		15			24		19		21
Transmission vegetation management	2016		9			16		9		23
Coal reclamation	2038		8			20		8		24
Palo Verde VIEs (Note 6)	2046		—			40		—		38
Deferred compensation	2036		—			36		—		34
Deferred fuel and purchased power (b) (c)	2013		37			—		73		—
Retired power plant costs	2020		3			19		—		—
Tax expense of Medicare subsidy	2024		2			15		2		17
Loss on reacquired debt	2034		1			17		2		18
Income taxes — investment tax credit basis adjustment	2042		1			30		1		26
Pension and other postretirement benefits deferral	2015		8			6		8		13
Lost fixed cost recovery (b)	2014		19			—		7		—
Transmission cost adjustor (b)	2014		12			2		10		—
Other	Various		1			22		1		14
Total regulatory assets (d)			$	120		$	1,106	$	144	$	1,100
(a)                                 This asset represents the future recovery of under-funded pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future revenues.
(b)                                 See “Cost Recovery Mechanisms” discussion above.
(c)                                  Subject to a carrying charge.
(d)                                 There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”
The detail of regulatory liabilities is as follows (dollars in millions):
	Remaining		September 30, 2013					December 31, 2012
	Amortization
	Period		Current			Non-Current		Current		Non-Current
Removal costs		(a)	$	26		$	311	$	27	$	321
Asset retirement obligations		(a)	—			272		—		256
Renewable energy standard (b)	2014		27			22		43		—
Income taxes — change in rates	2042		—			68		—		66
Spent nuclear fuel	2047		5			37		10		36
Deferred gains on utility property	2019		2			11		2		12
Income taxes — deferred investment tax credit	2042		2			60		2		52
Demand side management (b)	2014		26			—		4		—
Other	Various		—			17		—		16
Total regulatory liabilities			$	88		$	798	$	88	$	759
(a)                                 In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)                                 See “Cost Recovery Mechanisms” discussion above.

Retirement_Plans_and_Other_Ben

Retirement Plans and Other Benefits	9 Months Ended
	Sep. 30, 2013
Retirement Plans and Other Benefits
Retirement Plans and Other Benefits	4.                                      Retirement Plans and Other Benefits
	Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.
	Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred through June 30, 2012 as a regulatory asset for future recovery, pursuant to an ACC regulatory order.  We deferred pension and other postretirement benefit costs of approximately $14 million in 2012.  Pursuant to an ACC regulatory order, we began amortizing the regulatory asset in July 2012.  We amortized approximately $2 million for the three months ended September 30, 2013, and 2012, and approximately $6 million and $2 million for the nine months ended September 30, 2013 and 2012, respectively.  The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):
		Pension Benefits												Other Benefits
		Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
		September 30,						September 30,						September 30,						September 30,
		2013			2012			2013			2012			2013			2012			2013			2012
	Service cost — benefits earned during the period	$	16		$	16		$	48		$	48		$	6		$	7		$	18		$	20
	Interest cost on benefit obligation	28			30			84			90			10			12			31			35
	Expected return on plan assets	(36		)	(35		)	(110		)	(106		)	(11		)	(12		)	(34		)	(34		)
	Amortization of:
	Prior service cost	—			—			1			1			—			—			—			—
	Net actuarial loss	10			11			30			33			3			5			8			15
	Net periodic benefit cost	$	18		$	22		$	53		$	66		$	8		$	12		$	23		$	36
	Portion of cost charged to expense	$	10		$	12		$	29		$	25		$	5		$	7		$	14		$	13
	Contributions
	We have made voluntary contributions of $141 million to our pension plan in 2013.  The minimum contributions for the pension plan due in 2013, 2014, and 2015 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero, $89 million, and $112 million, respectively.  We expect to make contributions to the pension plan up to approximately $175 million each year in 2014 and 2015.  We have contributed $11 million to our other postretirement benefit plans in 2013.  The total contributions to our other postretirement benefit plans are expected to be approximately $14 million in 2013 and approximately $20 million each year in 2014 and 2015.

Income_Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2013
Income Taxes
Income Taxes	5.                                      Income Taxes
	The $70 million long-term income tax receivable on the Condensed Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  The $137 million anticipated refund is expected to be received within the next twelve months and has been reclassified to current income tax receivable as of September 30, 2013.
	Finalization of the current IRS examination of tax returns for the years ended December 31, 2008 and 2009 is likely to occur within the next twelve months.  As a result, the $137 million anticipated refund has been reduced by approximately $4 million to reflect the likely ultimate outcome of this examination.  Additionally, it is possible that uncertain tax positions could decrease by approximately $35 million.  This decrease would be materially offset by an increase in deferred tax liabilities.
	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 will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment.  To account for the adoption of these regulations, for the quarter ended September 30, 2013, plant-related long-term deferred tax liabilities decreased by $80 million, with the offsetting decrease to current deferred income tax assets. Prior to the issuance of these regulations, this $80 million would have been repaid over 20 years through lower tax depreciation deductions.
	Net Income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 6).  As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.
	The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions making qualified property placed into service in 2013 eligible for 50% bonus depreciation for federal income tax purposes.  Full recognition of the cash benefit of this provision delayed realization of approximately $78 million in federal general business income tax credit carryforwards which were classified as current deferred income taxes as of December 31, 2012.  However, as of September 30, 2013, the $78 million in federal general business tax credit carryforwards are expected to be realized within the next twelve months.
	As of September 30, 2013, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS.  With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.

Palo_Verde_Sale_Leaseback_Vari

Palo Verde Sale Leaseback Variable Interest Entities	9 Months Ended
	Sep. 30, 2013
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities	6.                                      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 per year for the years 2013 to 2015 related to these leases.  The lease agreements include fixed rate renewal periods, which gives APS the ability to utilize the asset 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 December 31, 2012, APS notified the lessor trust entities that APS would retain the assets beyond 2015 by either exercising the fixed rate lease renewals or by purchasing the assets.  If APS elects to purchase the assets, the purchase price will be based on the fair market value of the assets at the end of 2015.  If APS elects to extend the leases, we will be required to make payments beginning in 2016 of approximately $23 million annually.  The length of the lease extensions is unknown at this time as it must be determined through an appraisal process.  APS must give notice to the lessor trusts by June 30, 2014 notifying them which of these two options (lease renewal or purchasing the assets) it will exercise.  The December 31, 2012 notification does not impact APS’s consolidation of the VIEs, as APS continues to be deemed the primary beneficiary of the VIEs.
	As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three and nine months ended September 30, 2013 of $9 million and $25 million, respectively, and for the three and nine months ended September 30, 2012 of $8 million and $24 million, respectively, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders remains the same.  Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.
	Our Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):
		September 30,		December 31,
		2013		2012
	Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	126	$	129
	Current maturities of long-term debt	20		27
	Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	37		39
	Equity — Noncontrolling interests	146		129
	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 to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of September 30, 2013, APS would have been required to pay the noncontrolling equity participants approximately $142 million and assume $57 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.
	For regulatory ratemaking purposes, the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

Derivative_Accounting

Derivative Accounting	9 Months Ended
	Sep. 30, 2013
Derivative Accounting
Derivative Accounting	7.                                      Derivative Accounting
	We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
	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 accounting 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 other comprehensive income (“OCI”), but are deferred through the PSA.  The amounts previously recorded in accumulated OCI (“AOCI”) relating to these instruments will remain in AOCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.
	Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 12 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 normal 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.
	Prior to the Settlement Agreement, for its regulated operations, APS deferred for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Due to the Settlement Agreement, for its regulated operations, APS now defers for future rate treatment 100% of the unrealized gains and losses for delivery periods after June 30, 2012 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 September 30, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
	Commodity	Quantity
	Power	6,498		gigawatt hours
	Gas	112		Bcfs (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 (dollars in thousands):
				Three Months Ended						Nine Months Ended
				September 30,						September 30,
	Commodity Contracts	Financial Statement Location		2013			2012			2013			2012
	Loss recognized in OCI on derivative instruments (effective portion)	Other comprehensive income (loss) — derivative instruments		$	(240	)	$	(119	)	$	(409	)	$	(37,513	)
	Loss reclassified from AOCI into income (effective portion realized) (a)	Fuel and purchased power (b)		(23,658		)	(49,478		)	(39,156		)	(86,993		)
	Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)	Fuel and purchased power (b)		—			—			—			117
	(a)         During the three and nine months ended September 30, 2013 and three months ended September 30, 2012, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.  During the nine months ended September 30, 2012, we had $1.8 million of losses reclassified from AOCI 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 $23 million before income taxes will be reclassified from AOCI 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 three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
				Three Months Ended						Nine Months Ended
				September 30,						September 30,
	Commodity Contracts	Financial Statement Location		2013			2012			2013			2012
	Net gain recognized in income	Operating revenues (a)		$	196		$	258		$	400		$	19
	Net gain (loss) recognized in income	Fuel and purchased power expense (a)		(1,341		)	12,870			(11,750		)	13,860
	Total			$	(1,145	)	$	13,128		$	(11,350	)	$	13,879
	(a)         Amounts are before the effect of PSA deferrals.
	Derivative Instruments in the Condensed Consolidated Balance Sheets
	Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and in the event of a default would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
	We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
	The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012, include gross liabilities of $5 million 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 September 30, 2013 and December 31, 2012.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.
	As of September 30, 2013:	Gross			Amounts			Net			Other			Amount
	(dollars in thousands)	Recognized			Offset			Recognized			(c)			Reported on
		Derivatives			(b)			Derivatives						Balance Sheet
		(a)
	Current Assets	$	32,201		$	(9,605	)	$	22,596		$	145		$	22,741
	Investments and Other Assets	27,905			(1,859		)	26,046			—			26,046
	Total Assets	60,106			(11,464		)	48,642			145			48,787
	Current Liabilities	(66,680		)	32,675			(34,005		)	(19,463		)	(53,468		)
	Deferred Credits and Other	(74,751		)	7,089			(67,662		)	—			(67,662		)
	Total Liabilities	(141,431		)	39,764			(101,667		)	(19,463		)	(121,130		)
	Total	$	(81,325	)	$	28,300		$	(53,025	)	$	(19,318	)	$	(72,343	)
	(a)         All of our gross recognized derivative instruments were subject to master netting arrangements.
	(b)         Includes cash collateral provided to counterparties of $28,300.
	(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 $19,463, and cash margin provided to counterparties of $145.
	As of December 31, 2012:	Gross			Amounts			Net			Other			Amount
	(dollars in thousands)	Recognized			Offset			Recognized			(c)			Reported on
		Derivatives			(b)			Derivatives						Balance Sheet
		(a)
	Current Assets	$	42,495		$	(17,797	)	$	24,698		$	1,001		$	25,699
	Investments and Other Assets	41,563			(5,672		)	35,891			—			35,891
	Total Assets	84,058			(23,469		)	60,589			1,001			61,590
	Current Liabilities	(105,324		)	57,046			(48,278		)	(25,463		)	(73,741		)
	Deferred Credits and Other	(100,986		)	15,722			(85,264		)	—			(85,264		)
	Total Liabilities	(206,310		)	72,768			(133,542		)	(25,463		)	(159,005		)
	Total	$	(122,252	)	$	49,299		$	(72,953	)	$	(24,462	)	$	(97,415	)
	(a)         All of our gross recognized derivative instruments were subject to master netting arrangements.
	(b)         Includes cash collateral provided to counterparties of $49,299.
	(c)          Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions.  Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463.  This amount is not subject to offsetting.
	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 two counterparties for which our exposure represents approximately 90% of Pinnacle West’s $49 million of risk management assets as of September 30, 2013.  This exposure relates to long-term traditional wholesale contracts with counterparties that have 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 a subjective event and/or condition.  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 September 30, 2013 (dollars in millions):
	September 30,
	2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	141
Cash Collateral Posted	28
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	88
(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.

Changes_in_Equity

Changes in Equity	9 Months Ended
	Sep. 30, 2013
Changes in Equity
Changes in Equity	8.                                      Changes in Equity
	The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended September 30, 2013									Three Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, July 1	$	4,032,165		$	137,069		$	4,169,234		$	3,778,035		$	121,302		$	3,899,337
	Net income	226,163			8,555			234,718			244,823			8,040			252,863
	Other comprehensive income	15,122			—			15,122			30,843			—			30,843
	Total comprehensive income	241,285			8,555			249,840			275,666			8,040			283,706
	Issuance of capital stock	2,331			—			2,331			2,365			—			2,365
	Reissuance of treasury stock — net	37			—			37			(82		)	—			(82		)
	Other (primarily stock compensation)	(22		)	—			(22		)	258			—			258
	Dividends on common stock	8			—			8			—			—			—
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584
		Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
	Net income	381,814			25,338			407,152			358,911			23,582			382,493
	Other comprehensive income	24,673			—			24,673			32,688			—			32,688
	Total comprehensive income	406,487			25,338			431,825			391,599			23,582			415,181
	Issuance of capital stock	7,268			—			7,268			7,590			—			7,590
	Reissuance (purchase) of treasury stock - net	(5,868		)	—			(5,868		)	3,277			—			3,277
	Other (primarily stock compensation)	14,988			—			14,988			4,270			—			4,270
	Dividends on common stock	(119,877		)	—			(119,877		)	(172,344		)	—			(172,344		)
	Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,976		)	(2,976		)
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584

Commitments_and_Contingencies

Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies.

Commitments and Contingencies

9.                                      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 United States Department of Energy (“DOE”) in the United States Court of Federal Claims.  The lawsuit seeks to recover APS’s damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  Activities in this legal proceeding are currently limited to review of supporting information for APS’s claim by the Government.

APS currently estimates it will incur $122 million over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel.  At September 30, 2013, APS had a regulatory liability of $42 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

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 assessment per reactor under the program for each nuclear 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 interest in the three Palo Verde units, APS’s maximum potential retrospective assessment per incident for all three units is approximately $111.1 million, with an annual payment limitation of approximately $16.4 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 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”).  Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies.  Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations.  APS is subject to retrospective 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 $18 million for each retrospective 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 $48 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

As of September 30, 2013, our contractual obligations for fuel and purchased power commitments decreased approximately $300 million from December 31, 2012, as discussed in the 2012 Form 10-K.  As of September 30, 2013, the updated contractual obligations related to our fuel and purchased power obligations are as follows (dollars in millions):

2013

2014

2015

2016

2017

Thereafter

Total

Fuel and Purchased Power

$

108

$

576

$

549

$

516

$

441

$

6,399

$

8,589

For additional information regarding contractual obligations, see information provided in our 2012 Form 10-K.

Superfund-Related Matters

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

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Southwest Power Outage

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

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.

The FERC and the North American Electric Reliability Corporation (“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 includes 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 does not address potential reliability violations or an assessment of responsibility of the parties involved.  APS continues to analyze business practices and procedures related to the September 8 events.

APS cannot predict the timing, results or potential impacts of enforcement actions that may be brought against APS relating to the September 8 events, or any claims that may be made as a result of the outages.  If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that a violation is found to have been in existence.

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 intend to file a motion to dismiss the complaint.

Clean Air Act 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 New Source Review (“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 New Source Performance Standards (“NSPS”) program.  Among other things, the 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 without risk of default.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Environmental Matters

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

Regional Haze Rules.  APS has received the final rulemaking imposing new requirements on Four Corners and the Cholla Power Plant (“Cholla”) and is currently awaiting a final rulemaking from EPA that could impose new requirements on the Navajo Generating Station (“Navajo Plant”).  EPA and Arizona Department of Environmental Quality (“ADEQ”) will require these plants to install pollution control equipment that constitutes the “best available retrofit technology” (“BART”) to lessen the impacts of emissions on visibility surrounding the plants.  Based on EPA’s final standards, APS’s share of its total costs for Four Corners (assuming the consummation of its purchase of SCE’s interest in Units 4 and 5 and subsequent shut down of Units 1-3) could be approximately $300 million.  APS’s share of costs for upgrades at Navajo, based on EPA’s Federal Implementation Plan (“FIP”) proposal, could be up to approximately $200 million.  APS has filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, will require installation of controls with a cost to APS of approximately $200 million.

Mercury and Other Hazardous Air Pollutants.  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 $120 million for Cholla Units 1-3.  Estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3.  No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  Salt River Project Agricultural Improvement and Power District (“SRP”), the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, greenhouse gas emissions and other rules or matters involving the Clean Air Act, Endangered Species Act, 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 State Implementation Plan (“SIP”) and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.  Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  In addition, on February 4, 2013, APS filed a Petition for Reconsideration and Stay of the final BART rule with EPA.  On March 22, 2013, APS filed a motion with the court to suspend the compliance deadlines under the BART rule until the court rules on the matter.  The State of Arizona and three other Arizona utilities also filed similar petitions and motions.  On September 30, 2013, the court issued an order denying these motions to suspend the compliance deadline.

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.  Prior to year end, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, intend to file a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  APS believes the Assessment and the refund claim denial are without merit, but cannot predict the timing or outcome of this litigation.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At September 30, 2013, approximately $76 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.  One of these letters of credit expires in 2015 and two expire in 2016.  APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $32 million at September 30, 2013.  Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including certain natural gas tolling contracts entered into with third parties.  At September 30, 2013, $60 million of such letters of credit were outstanding that will expire in 2014 and 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 surety bonds for APS which were not material at September 30, 2013.

Other_Income_and_Other_Expense

Other Income and Other Expense	9 Months Ended
	Sep. 30, 2013
Other Income and Other Expense
Other Income and Other Expense	10.                               Other Income and Other Expense
	The following table provides detail of other income and other expense for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Other income:
	Interest income	$	116		$	307		$	1,291		$	1,018
	Miscellaneous	44			113			96			339
	Total other income	$	160		$	420		$	1,387		$	1,357
	Other expense:
	Non-operating costs	$	(2,028	)	$	(1,645	)	$	(5,951	)	$	(5,885	)
	Investment losses — net	(3,435		)	(2,254		)	(3,643		)	(2,366		)
	Miscellaneous	(1,972		)	(1,797		)	(3,827		)	(4,182		)
	Total other expense	$	(7,435	)	$	(5,696	)	$	(13,421	)	$	(12,433	)

Earnings_Per_Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2013
Earnings Per Share
Earnings Per Share	11.                               Earnings Per Share
	The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2013 and 2012:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Basic earnings per share:
	Income from continuing operations attributable to common shareholders	$	2.06	$	2.23	$	3.47	$	3.29
	Loss from discontinued operations	—		—		—		(0.01		)
	Earnings per share — basic	$	2.06	$	2.23	$	3.47	$	3.28
	Diluted earnings per share:
	Income from continuing operations attributable to common shareholders	$	2.04	$	2.21	$	3.44	$	3.26
	Loss from discontinued operations	—		—		—		(0.01		)
	Earnings per share — diluted	$	2.04	$	2.21	$	3.44	$	3.25
	Performance shares and restricted stock units (which are contingently issuable) increased the weighted average common shares outstanding by approximately 1,044,000 shares and 1,100,000 shares for the three months ended September 30, 2013 and 2012, respectively, and by approximately 978,000 shares and 971,000 shares for the nine months ended September 30, 2013 and 2012, respectively.
	For the three and nine months ended September 30, 2013 and 2012, there were no common stock options that were excluded from the computation of diluted earnings per share as a result of the options’ exercise prices being greater than the average market price of the common shares.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2013
Fair Value Measurements
Fair Value Measurements	12.                               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 United States 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 in common and collective trusts and commingled funds that are redeemable and valued based on the funds’ net asset value (“NAV”).
	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 8 in the 2012 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.
	Cash Equivalents
	Cash equivalents represent short-term investments with original maturities of three months or less in exchange-traded money market funds that are valued using quoted prices in active markets.
	Risk Management Activities — Derivative Instruments
	Exchange-traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange-traded commodity contracts, we calculate fair market 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 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 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 United States government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.
	Fixed income securities issued by the United States 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.
	Our trustee provides valuation of our nuclear decommissioning trust assets by using 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 13 for additional discussion about our nuclear decommissioning trust.
	Fair Value Tables
	The following table presents the fair value at September 30, 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
		in Active			Other			Unobservable						September 30,
		Markets for			Observable			Inputs (a)						2013
		Identical Assets			Inputs			(Level 3)
		(Level 1)			(Level 2)
	Assets
	Risk management activities — derivative instruments:
	Commodity Contracts	$	—		$	12		$	48		$	(11	)(b)	$	49
	Nuclear decommissioning trust:
	U.S. commingled equity funds	—			245			—			—			245
	Fixed income securities:
	U.S. Treasury	109			—			—			—			109
	Cash and cash equivalent funds	—			13			—			(3		)(c)	10
	Corporate debt	—			83			—			—			83
	Mortgage-backed securities	—			82			—			—			82
	Municipality bonds	—			71			—			—			71
	Other	—			13			—			—			13
	Subtotal nuclear decommissioning trust	109			507			—			(3		)	613
	Total	$	109		$	519		$	48		$	(14	)	$	662
	Liabilities
	Risk management activities — derivative instruments:
	Commodity contracts	$	—		$	(49	)	$	(92	)	$	20	(b)	$	(121	)
	(a)                                 Primarily consists of heat rate options and long-dated electricity contracts.
	(b)                                 Primarily represents counterparty netting, margin and collateral (see Note 7).
	(c)                                  Represents nuclear decommissioning trust net pending securities sales and purchases.
	The following table presents the fair value at December 31, 2012 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
		in Active			Other			Unobservable						December 31,
		Markets for			Observable			Inputs (a)						2012
		Identical			Inputs			(Level 3)
		Assets			(Level 2)
		(Level 1)
	Assets
	Cash equivalents	$	16		$	—		$	—		$	—		$	16
	Risk management activities — derivative instruments:
	Commodity Contracts	—			22			62			(22		)(b)	62
	Nuclear decommissioning trust:
	U.S. commingled equity funds	—			204			—			—			204
	Fixed income securities:
	U.S. Treasury	104			—			—			—			104
	Cash and cash equivalent funds	6			13			—			(4		)(c)	15
Corporate debt	—			80			—			—			80
Mortgage-backed securities	—			83			—			—			83
Municipality bonds	—			74			—			—			74
Other	—			11			—			—			11
Subtotal nuclear decommissioning trust	110			465			—			(4		)	571
Total	$	126		$	487		$	62		$	(26	)	$	649
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—		$	(96	)	$	(110	)	$	47	(b)	$	(159	)
(a)                                 Primarily consists of heat rate options and long-dated electricity contracts.
(b)                                 Represents counterparty netting, margin and collateral (see Note 7).
(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 impact on the fair value of these options to increase, and if these valuation inputs decrease, we would expect the impact on the fair value of these options to decrease.  If natural gas prices and natural gas price volatilities increase, we would expect the impact on the fair value of these options to decrease, and if these inputs decrease, we would expect the impact on 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 Level 3 instruments at September 30, 2013 and December 31, 2012:
	September 30, 2013						Valuation		Significant				Weighted-
	Fair Value (millions)
Commodity Contracts	Assets			Liabilities			Technique		Unobservable Input		Range		Average
Electricity:
Forward Contracts (a)	$	47		$	74		Discounted cash flows		Electricity forward price (per MWh)		$24.55 – $60.97		$	40.23
Option Contracts (b)	—			16			Option model		Electricity forward price (per MWh)		$38.56 – $82.07		$	55.74
									Electricity price volatilities		51% – 106%		74		%
									Natural gas forward price		$3.82 – $3.96		$	3.91
									Natural gas price volatilities		24% – 51%		31		%
Natural Gas:
Forward Contracts (a)	1			2			Discounted cash flows		Natural gas forward price (per mmbtu)		$3.31 – $4.25		$	3.97
Total	$	48		$	92
(a)                                 Includes swaps and physical and financial contracts.
(b)                                 Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
	December 31, 2012						Valuation		Significant				Weighted-
	Fair Value (millions)
Commodity Contracts	Assets			Liabilities			Technique		Unobservable Input		Range		Average
Electricity:
Forward Contracts (a)	$	57		$	82		Discounted cash flows		Electricity forward price (per MWh)		$23.06 – $64.20		$	43.16
Option Contracts	—			27			Option model		Electricity forward price (per MWh)		$36.66 – $92.19		$	60.97
									Natural gas forward price (per mmbtu)		$4.10 – $4.25		$	4.2
									Implied electricity price volatilities		15% – 66%		39		%
									Implied natural gas price volatilities		17% – 36%		23		%
Natural Gas:
Forward Contracts (a)	5			1			Discounted cash flows		Natural gas forward price (per mmbtu)		$3.25 – $4.44		$	3.93
Total	$	62		$	110
(a)                                 Includes swaps and physical and financial contracts.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2013 and 2012 (dollars in millions):
Commodity Contracts	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Net derivative balance at beginning of period	$	(53	)	$	(45	)	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—			—			2
Included in OCI	—			—			—			(2		)
Deferred as a regulatory asset or liability	4			(3		)	(2		)	4
Settlements	6			(1		)	8			(1		)
Transfers into Level 3 from Level 2	(1		)	(4		)	(1		)	(2		)
Transfers from Level 3 into Level 2	—			3			(1		)	—
Net derivative balance at end of period	$	(44	)	$	(50	)	$	(44	)	$	(50	)
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 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 heat rate options and 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 any short-term borrowings approximate fair value.  Our short-term borrowings are classified within Level 2 of the fair value hierarchy.  For our long-term debt fair values, see Note 2.

Nuclear_Decommissioning_Trusts

Nuclear Decommissioning Trusts	9 Months Ended
	Sep. 30, 2013
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts	13.                               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 their stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities.  APS classifies investments in decommissioning trust funds as available for sale.  As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets.  See Note 12 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 September 30, 2013 and December 31, 2012 (dollars in millions):
		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	September 30, 2013
	Equity securities	$	245		$	104		$	—
	Fixed income securities	371			13			(5		)
	Net payables (a)	(3		)	—			—
	Total	$	613		$	117		$	(5	)
	(a)                                 Net payables relate to pending securities sales and purchases.
		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	December 31, 2012
	Equity securities	$	204		$	67		$	—
	Fixed income securities	371			24			—
	Net payables (a)	(4		)	—			—
	Total	$	571		$	91		$	—
	(a)                                 Net payables relate to pending securities sales and purchases.
	The costs of securities sold are determined on the basis of specific identification.  The following table sets forth approximate realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Realized gains	$	1		$	1		$	4		$	5
	Realized losses	(3		)	(1		)	(5		)	(3		)
	Proceeds from the sale of securities (a)	110			84			364			295
	(a)                                 Proceeds are reinvested in the trust.
	The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2013 is as follows (dollars in millions):
		Fair Value
	Less than one year	$	12
	1 year - 5 years	106
	5 years - 10 years	104
	Greater than 10 years	149
	Total	$	371

New_Accounting_Standards

New Accounting Standards	9 Months Ended
	Sep. 30, 2013
New Accounting Standards
New Accounting Standards	14.                               New Accounting Standards
	During 2013, we adopted, on a retrospective basis, new guidance relating to balance sheet offsetting disclosures.  The new guidance requires enhanced disclosures regarding an entity’s ability to offset certain instruments on the balance sheet and how offsetting impacts the balance sheet.  The adoption of this guidance resulted in expanded disclosures relating to our derivative instruments (see Note 7), but did not impact our financial statement results.
	During 2013, we also adopted, on a prospective basis, new guidance relating to reporting amounts reclassified from AOCI.  This guidance requires new disclosures relating to AOCI and how reclassifications from AOCI impact net income.  As a result of adopting this new guidance, we have included a new footnote disclosure to provide the information required by the new standard (see Notes 15 and S-3).  The adoption of this guidance did not impact our financial statement results.
	In July 2013, new guidance was issued which will generally require 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.  The new guidance is effective for us on January 1, 2014, with early application permitted.  We are currently evaluating the impacts of this new guidance.  The adoption of this new guidance may impact our balance sheet presentation, but will not impact our results of operations or cash flows.

Changes_in_Accumulated_Other_C

Changes in Accumulated Other Comprehensive Loss	9 Months Ended
	Sep. 30, 2013
Changes in Accumulated Other Comprehensive Loss
Changes in Accumulated Other Comprehensive Loss	15.                               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 three and nine months ended September 30, 2013 (dollars in thousands):
		Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
		Derivative			Pension and			Total			Derivative			Pension and			Total
		Instruments			Other						Instruments			Other
					Postretirement									Postretirement
					Benefits									Benefits
	Beginning balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
	Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,635		)	(1,882		)
	Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	957		(b)	15,267			23,685		(a)	2,870		(b)	26,555
	Net current period other comprehensive income	14,165			957			15,122			23,438			1,235			24,673
	Ending balance	$	(26,154	)	$	(63,181	)	$	(89,335	)	$	(26,154	)	$	(63,181	)	$	(89,335	)
	(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 7.
	(b)         These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.

Consolidation_and_Nature_of_Op1

Consolidation and Nature of Operations (Tables)	9 Months Ended
	Sep. 30, 2013
Consolidation and Nature of Operations
Schedule of impact of the reclassifications to prior year (previously reported) amounts of the deferred investment tax credit and income tax receivables which have become more material	The following tables show the impact of the reclassifications to prior year (previously reported) amounts of the deferred investment tax credit and income tax receivables which have become more material in 2013 (dollars in thousands):
	Balance Sheets - December 31, 2012	As			Reclassifications			Amount
		previously						reported after
		reported						reclassifications
	Deferred investment tax credit	$	—		$	99,819		$	99,819
	Deferred credits — other	283,654			(99,819		)	183,835
	Statement of Cash Flows for the Nine	As			Reclassifications			Amount
	Months Ended September 30, 2012	previously						reported after
		reported						reclassifications
	Cash Flows from Operating Activities
	Deferred income taxes	$	206,501		$	(8,974	)	$	197,527
	Deferred investment tax credit	—			8,974			8,974
	Income tax receivable	—			6,466			6,466
	Accrued taxes	76,365			(6,466		)	69,899
	Change in long-term income tax receivable	—			(1,320		)	(1,320		)
	Change in other long-term assets	(15,205		)	1,320			(13,885		)
Summary of supplemental cash flow information	The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
		Nine Months Ended
		September 30,
		2013			2012
	Cash paid during the period for:
	Income taxes, net of (refunds)	$	3,412		$	(651	)
	Interest, net of amounts capitalized	141,047			152,582
	Significant non-cash investing and financing activities:
	Accrued capital expenditures	$	11,377		$	11,281

LongTerm_Debt_and_Liquidity_Ma1

Long-Term Debt and Liquidity Matters (Tables)	9 Months Ended
	Sep. 30, 2013
Long-Term Debt and Liquidity Matters
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
		September 30, 2013				December 31, 2012
		Carrying		Fair Value		Carrying		Fair Value
		Amount				Amount
	Pinnacle West	$	125	$	125	$	125	$	125
	APS	3,262		3,538		3,197		3,750
	Total	$	3,387	$	3,663	$	3,322	$	3,875

Regulatory_Matters_Tables

Regulatory Matters (Tables)	9 Months Ended
	Sep. 30, 2013
Regulatory Matters
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 2013 and 2012 (dollars in millions):
		Nine Months Ended
		September 30,
		2013			2012
	Beginning balance	$	73		$	28
	Deferred fuel and purchased power costs — current period	(13		)	(52		)
	Amounts (collected from) credited to customers	(23		)	92
	Ending balance	$	37		$	68
Schedule of regulatory assets	The detail of regulatory assets is as follows (dollars in millions):
		Remaining		September 30, 2013					December 31, 2012
		Amortization
		Period		Current			Non-Current		Current		Non-Current
	Pension and other postretirement benefits		(a)	$	—		$	754	$	—	$	780
	Income taxes — allowance for equity funds used during construction	2043		4			105		4		92
	Deferred fuel and purchased power — mark-to-market (Note 7)	2016		15			24		19		21
	Transmission vegetation management	2016		9			16		9		23
	Coal reclamation	2038		8			20		8		24
	Palo Verde VIEs (Note 6)	2046		—			40		—		38
	Deferred compensation	2036		—			36		—		34
	Deferred fuel and purchased power (b) (c)	2013		37			—		73		—
	Retired power plant costs	2020		3			19		—		—
	Tax expense of Medicare subsidy	2024		2			15		2		17
	Loss on reacquired debt	2034		1			17		2		18
	Income taxes — investment tax credit basis adjustment	2042		1			30		1		26
	Pension and other postretirement benefits deferral	2015		8			6		8		13
	Lost fixed cost recovery (b)	2014		19			—		7		—
	Transmission cost adjustor (b)	2014		12			2		10		—
	Other	Various		1			22		1		14
	Total regulatory assets (d)			$	120		$	1,106	$	144	$	1,100
	(a)                                 This asset represents the future recovery of under-funded pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future revenues.
	(b)                                 See “Cost Recovery Mechanisms” discussion above.
	(c)                                  Subject to a carrying charge.
	(d)                                 There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”
Schedule of regulatory liabilities	The detail of regulatory liabilities is as follows (dollars in millions):
		Remaining		September 30, 2013					December 31, 2012
		Amortization
		Period		Current			Non-Current		Current		Non-Current
	Removal costs		(a)	$	26		$	311	$	27	$	321
	Asset retirement obligations		(a)	—			272		—		256
	Renewable energy standard (b)	2014		27			22		43		—
	Income taxes — change in rates	2042		—			68		—		66
	Spent nuclear fuel	2047		5			37		10		36
	Deferred gains on utility property	2019		2			11		2		12
	Income taxes — deferred investment tax credit	2042		2			60		2		52
	Demand side management (b)	2014		26			—		4		—
	Other	Various		—			17		—		16
	Total regulatory liabilities			$	88		$	798	$	88	$	759
	(a)                                 In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
	(b)                                 See “Cost Recovery Mechanisms” discussion above.

Retirement_Plans_and_Other_Ben1

Retirement Plans and Other Benefits (Tables)	9 Months Ended
	Sep. 30, 2013
Retirement Plans and Other Benefits
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)	The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):
		Pension Benefits												Other Benefits
		Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
		September 30,						September 30,						September 30,						September 30,
		2013			2012			2013			2012			2013			2012			2013			2012
	Service cost — benefits earned during the period	$	16		$	16		$	48		$	48		$	6		$	7		$	18		$	20
	Interest cost on benefit obligation	28			30			84			90			10			12			31			35
	Expected return on plan assets	(36		)	(35		)	(110		)	(106		)	(11		)	(12		)	(34		)	(34		)
	Amortization of:
	Prior service cost	—			—			1			1			—			—			—			—
	Net actuarial loss	10			11			30			33			3			5			8			15
	Net periodic benefit cost	$	18		$	22		$	53		$	66		$	8		$	12		$	23		$	36
	Portion of cost charged to expense	$	10		$	12		$	29		$	25		$	5		$	7		$	14		$	13

Palo_Verde_Sale_Leaseback_Vari1

Palo Verde Sale Leaseback Variable Interest Entities (Tables)	9 Months Ended
	Sep. 30, 2013
Palo Verde Sale Leaseback Variable Interest Entities
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets	Our Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):
		September 30,		December 31,
		2013		2012
	Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	126	$	129
	Current maturities of long-term debt	20		27
	Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	37		39
	Equity — Noncontrolling interests	146		129

Derivative_Accounting_Tables

Derivative Accounting (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Accounting
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)	As of September 30, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
	Commodity	Quantity
	Power	6,498		gigawatt hours
	Gas	112		Bcfs (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 (dollars in thousands):
				Three Months Ended						Nine Months Ended
				September 30,						September 30,
	Commodity Contracts	Financial Statement Location		2013			2012			2013			2012
	Loss recognized in OCI on derivative instruments (effective portion)	Other comprehensive income (loss) — derivative instruments		$	(240	)	$	(119	)	$	(409	)	$	(37,513	)
	Loss reclassified from AOCI into income (effective portion realized) (a)	Fuel and purchased power (b)		(23,658		)	(49,478		)	(39,156		)	(86,993		)
	Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)	Fuel and purchased power (b)		—			—			—			117
	(a)         During the three and nine months ended September 30, 2013 and three months ended September 30, 2012, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.  During the nine months ended September 30, 2012, we had $1.8 million of losses reclassified from AOCI to earnings related to discontinued cash flow hedges.
	(b)         Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments	The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
				Three Months Ended						Nine Months Ended
				September 30,						September 30,
	Commodity Contracts	Financial Statement Location		2013			2012			2013			2012
	Net gain recognized in income	Operating revenues (a)		$	196		$	258		$	400		$	19
	Net gain (loss) recognized in income	Fuel and purchased power expense (a)		(1,341		)	12,870			(11,750		)	13,860
	Total			$	(1,145	)	$	13,128		$	(11,350	)	$	13,879
	(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
	As of September 30, 2013:	Gross			Amounts			Net			Other			Amount
	(dollars in thousands)	Recognized			Offset			Recognized			(c)			Reported on
		Derivatives			(b)			Derivatives						Balance Sheet
		(a)
	Current Assets	$	32,201		$	(9,605	)	$	22,596		$	145		$	22,741
	Investments and Other Assets	27,905			(1,859		)	26,046			—			26,046
	Total Assets	60,106			(11,464		)	48,642			145			48,787
	Current Liabilities	(66,680		)	32,675			(34,005		)	(19,463		)	(53,468		)
	Deferred Credits and Other	(74,751		)	7,089			(67,662		)	—			(67,662		)
	Total Liabilities	(141,431		)	39,764			(101,667		)	(19,463		)	(121,130		)
	Total	$	(81,325	)	$	28,300		$	(53,025	)	$	(19,318	)	$	(72,343	)
	(a)         All of our gross recognized derivative instruments were subject to master netting arrangements.
	(b)         Includes cash collateral provided to counterparties of $28,300.
	(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 $19,463, and cash margin provided to counterparties of $145.
	As of December 31, 2012:	Gross			Amounts			Net			Other			Amount
	(dollars in thousands)	Recognized			Offset			Recognized			(c)			Reported on
		Derivatives			(b)			Derivatives						Balance Sheet
		(a)
	Current Assets	$	42,495		$	(17,797	)	$	24,698		$	1,001		$	25,699
	Investments and Other Assets	41,563			(5,672		)	35,891			—			35,891
	Total Assets	84,058			(23,469		)	60,589			1,001			61,590
	Current Liabilities	(105,324		)	57,046			(48,278		)	(25,463		)	(73,741		)
	Deferred Credits and Other	(100,986		)	15,722			(85,264		)	—			(85,264		)
	Total Liabilities	(206,310		)	72,768			(133,542		)	(25,463		)	(159,005		)
	Total	$	(122,252	)	$	49,299		$	(72,953	)	$	(24,462	)	$	(97,415	)
	(a)         All of our gross recognized derivative instruments were subject to master netting arrangements.
	(b)         Includes cash collateral provided to counterparties of $49,299.
	(c)          Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions.  Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463.  This amount is not subject to offsetting.
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 September 30, 2013 (dollars in millions):
		September 30,
		2013
	Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	141
	Cash Collateral Posted	28
	Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	88
	(a)         This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

Changes_in_Equity_Tables

Changes in Equity (Tables)	9 Months Ended
	Sep. 30, 2013
Changes in Equity
Schedule of changes in shareholders' equity and changes in equity of noncontrolling interests	The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended September 30, 2013									Three Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, July 1	$	4,032,165		$	137,069		$	4,169,234		$	3,778,035		$	121,302		$	3,899,337
	Net income	226,163			8,555			234,718			244,823			8,040			252,863
	Other comprehensive income	15,122			—			15,122			30,843			—			30,843
	Total comprehensive income	241,285			8,555			249,840			275,666			8,040			283,706
	Issuance of capital stock	2,331			—			2,331			2,365			—			2,365
	Reissuance of treasury stock — net	37			—			37			(82		)	—			(82		)
	Other (primarily stock compensation)	(22		)	—			(22		)	258			—			258
	Dividends on common stock	8			—			8			—			—			—
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584
		Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
	Net income	381,814			25,338			407,152			358,911			23,582			382,493
	Other comprehensive income	24,673			—			24,673			32,688			—			32,688
	Total comprehensive income	406,487			25,338			431,825			391,599			23,582			415,181
	Issuance of capital stock	7,268			—			7,268			7,590			—			7,590
	Reissuance (purchase) of treasury stock - net	(5,868		)	—			(5,868		)	3,277			—			3,277
	Other (primarily stock compensation)	14,988			—			14,988			4,270			—			4,270
	Dividends on common stock	(119,877		)	—			(119,877		)	(172,344		)	—			(172,344		)
	Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,976		)	(2,976		)
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies.
Schedule of updated contractual obligations related to the entity's fuel and purchased power obligations	As of September 30, 2013, the updated contractual obligations related to our fuel and purchased power obligations are as follows (dollars in millions):
		2013		2014		2015		2016		2017		Thereafter		Total
	Fuel and Purchased Power	$	108	$	576	$	549	$	516	$	441	$	6,399	$	8,589

Other_Income_and_Other_Expense1

Other Income and Other Expense (Tables)	9 Months Ended
	Sep. 30, 2013
Other Income and Other Expense
Detail of other income and other expense	The following table provides detail of other income and other expense for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Other income:
	Interest income	$	116		$	307		$	1,291		$	1,018
	Miscellaneous	44			113			96			339
	Total other income	$	160		$	420		$	1,387		$	1,357
	Other expense:
	Non-operating costs	$	(2,028	)	$	(1,645	)	$	(5,951	)	$	(5,885	)
	Investment losses — net	(3,435		)	(2,254		)	(3,643		)	(2,366		)
	Miscellaneous	(1,972		)	(1,797		)	(3,827		)	(4,182		)
	Total other expense	$	(7,435	)	$	(5,696	)	$	(13,421	)	$	(12,433	)

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share
Schedule of earnings per weighted average common share outstanding
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Basic earnings per share:
	Income from continuing operations attributable to common shareholders	$	2.06	$	2.23	$	3.47	$	3.29
	Loss from discontinued operations	—		—		—		(0.01		)
	Earnings per share — basic	$	2.06	$	2.23	$	3.47	$	3.28
	Diluted earnings per share:
	Income from continuing operations attributable to common shareholders	$	2.04	$	2.21	$	3.44	$	3.26
	Loss from discontinued operations	—		—		—		(0.01		)
	Earnings per share — diluted	$	2.04	$	2.21	$	3.44	$	3.25

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Measurements
Fair value of assets and liabilities that are measured at fair value on a recurring basis	The following table presents the fair value at September 30, 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
		in Active			Other			Unobservable						September 30,
		Markets for			Observable			Inputs (a)						2013
		Identical Assets			Inputs			(Level 3)
		(Level 1)			(Level 2)
	Assets
	Risk management activities — derivative instruments:
	Commodity Contracts	$	—		$	12		$	48		$	(11	)(b)	$	49
	Nuclear decommissioning trust:
	U.S. commingled equity funds	—			245			—			—			245
	Fixed income securities:
	U.S. Treasury	109			—			—			—			109
	Cash and cash equivalent funds	—			13			—			(3		)(c)	10
	Corporate debt	—			83			—			—			83
	Mortgage-backed securities	—			82			—			—			82
	Municipality bonds	—			71			—			—			71
	Other	—			13			—			—			13
	Subtotal nuclear decommissioning trust	109			507			—			(3		)	613
	Total	$	109		$	519		$	48		$	(14	)	$	662
	Liabilities
	Risk management activities — derivative instruments:
	Commodity contracts	$	—		$	(49	)	$	(92	)	$	20	(b)	$	(121	)
	(a)                                 Primarily consists of heat rate options and long-dated electricity contracts.
	(b)                                 Primarily represents counterparty netting, margin and collateral (see Note 7).
	(c)                                  Represents nuclear decommissioning trust net pending securities sales and purchases.
	The following table presents the fair value at December 31, 2012 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
		in Active			Other			Unobservable						December 31,
		Markets for			Observable			Inputs (a)						2012
		Identical			Inputs			(Level 3)
		Assets			(Level 2)
		(Level 1)
	Assets
	Cash equivalents	$	16		$	—		$	—		$	—		$	16
	Risk management activities — derivative instruments:
	Commodity Contracts	—			22			62			(22		)(b)	62
	Nuclear decommissioning trust:
	U.S. commingled equity funds	—			204			—			—			204
	Fixed income securities:
	U.S. Treasury	104			—			—			—			104
	Cash and cash equivalent funds	6			13			—			(4		)(c)	15
	Corporate debt	—			80			—			—			80
	Mortgage-backed securities	—			83			—			—			83
	Municipality bonds	—			74			—			—			74
	Other	—			11			—			—			11
	Subtotal nuclear decommissioning trust	110			465			—			(4		)	571
	Total	$	126		$	487		$	62		$	(26	)	$	649
	Liabilities
	Risk management activities — derivative instruments:
	Commodity contracts	$	—		$	(96	)	$	(110	)	$	47	(b)	$	(159	)
	(a)                                 Primarily consists of heat rate options and long-dated electricity contracts.
	(b)                                 Represents counterparty netting, margin and collateral (see Note 7).
	(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
		September 30, 2013						Valuation		Significant				Weighted-
		Fair Value (millions)
	Commodity Contracts	Assets			Liabilities			Technique		Unobservable Input		Range		Average
	Electricity:
	Forward Contracts (a)	$	47		$	74		Discounted cash flows		Electricity forward price (per MWh)		$24.55 – $60.97		$	40.23
	Option Contracts (b)	—			16			Option model		Electricity forward price (per MWh)		$38.56 – $82.07		$	55.74
										Electricity price volatilities		51% – 106%		74		%
										Natural gas forward price		$3.82 – $3.96		$	3.91
										Natural gas price volatilities		24% – 51%		31		%
	Natural Gas:
	Forward Contracts (a)	1			2			Discounted cash flows		Natural gas forward price (per mmbtu)		$3.31 – $4.25		$	3.97
	Total	$	48		$	92
	(a)                                 Includes swaps and physical and financial contracts.
	(b)                                 Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
		December 31, 2012						Valuation		Significant				Weighted-
		Fair Value (millions)
	Commodity Contracts	Assets			Liabilities			Technique		Unobservable Input		Range		Average
	Electricity:
	Forward Contracts (a)	$	57		$	82		Discounted cash flows		Electricity forward price (per MWh)		$23.06 – $64.20		$	43.16
	Option Contracts	—			27			Option model		Electricity forward price (per MWh)		$36.66 – $92.19		$	60.97
										Natural gas forward price (per mmbtu)		$4.10 – $4.25		$	4.2
										Implied electricity price volatilities		15% – 66%		39		%
										Implied natural gas price volatilities		17% – 36%		23		%
	Natural Gas:
	Forward Contracts (a)	5			1			Discounted cash flows		Natural gas forward price (per mmbtu)		$3.25 – $4.44		$	3.93
	Total	$	62		$	110
	(a)                                 Includes swaps and physical and financial contracts.
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs	The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2013 and 2012 (dollars in millions):
	Commodity Contracts	Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Net derivative balance at beginning of period	$	(53	)	$	(45	)	$	(48	)	$	(51	)
	Total net gains (losses) realized/unrealized:
	Included in earnings	—			—			—			2
	Included in OCI	—			—			—			(2		)
	Deferred as a regulatory asset or liability	4			(3		)	(2		)	4
	Settlements	6			(1		)	8			(1		)
	Transfers into Level 3 from Level 2	(1		)	(4		)	(1		)	(2		)
	Transfers from Level 3 into Level 2	—			3			(1		)	—
	Net derivative balance at end of period	$	(44	)	$	(50	)	$	(44	)	$	(50	)
	Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

Nuclear_Decommissioning_Trusts1

Nuclear Decommissioning Trusts (Tables)	9 Months Ended
	Sep. 30, 2013
Nuclear Decommissioning Trusts
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 September 30, 2013 and December 31, 2012 (dollars in millions):
		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	September 30, 2013
	Equity securities	$	245		$	104		$	—
	Fixed income securities	371			13			(5		)
	Net payables (a)	(3		)	—			—
	Total	$	613		$	117		$	(5	)
	(a)                                 Net payables relate to pending securities sales and purchases.
		Fair Value			Total			Total
					Unrealized			Unrealized
					Gains			Losses
	December 31, 2012
	Equity securities	$	204		$	67		$	—
	Fixed income securities	371			24			—
	Net payables (a)	(4		)	—			—
	Total	$	571		$	91		$	—
	(a)                                 Net payables relate to pending securities sales and purchases.
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds	The following table sets forth approximate realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Realized gains	$	1		$	1		$	4		$	5
	Realized losses	(3		)	(1		)	(5		)	(3		)
	Proceeds from the sale of securities (a)	110			84			364			295
	(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 September 30, 2013 is as follows (dollars in millions):
		Fair Value
	Less than one year	$	12
	1 year - 5 years	106
	5 years - 10 years	104
	Greater than 10 years	149
	Total	$	371

Changes_in_Accumulated_Other_C1

Changes in Accumulated Other Comprehensive Loss (Tables)	9 Months Ended
	Sep. 30, 2013
Changes in Accumulated Other Comprehensive Loss
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 three and nine months ended September 30, 2013 (dollars in thousands):
		Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
		Derivative			Pension and			Total			Derivative			Pension and			Total
		Instruments			Other						Instruments			Other
					Postretirement									Postretirement
					Benefits									Benefits
	Beginning balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
	Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,635		)	(1,882		)
	Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	957		(b)	15,267			23,685		(a)	2,870		(b)	26,555
	Net current period other comprehensive income	14,165			957			15,122			23,438			1,235			24,673
	Ending balance	$	(26,154	)	$	(63,181	)	$	(89,335	)	$	(26,154	)	$	(63,181	)	$	(89,335	)
	(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 7.
	(b)         These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.

Consolidation_and_Nature_of_Op2

Consolidation and Nature of Operations (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Cash Flows from Operating Activities
Deferred income taxes	$256,132	$197,527
Deferred investment tax credit	115,984	8,974	99,819
Deferred credits - other	178,053		183,835
Income tax receivable	-131,128	6,466
Accrued taxes	58,919	69,899
Change in long-term income tax receivable	137,270	-1,320
Change in other long-term assets	-24,345	-13,885
Cash paid during the period for:
Income taxes, net of (refunds)	3,412	-651
Interest, net of amounts capitalized	141,047	152,582
Significant non-cash investing and financing activities:
Accrued capital expenditures	11,377	11,281
As previously reported
Cash Flows from Operating Activities
Deferred income taxes		206,501
Deferred credits - other			283,654
Accrued taxes		76,365
Change in other long-term assets		-15,205
Reclassifications
Cash Flows from Operating Activities
Deferred income taxes		-8,974
Deferred investment tax credit		8,974	99,819
Deferred credits - other			-99,819
Income tax receivable		6,466
Accrued taxes		-6,466
Change in long-term income tax receivable		-1,320
Change in other long-term assets		$1,320

LongTerm_Debt_and_Liquidity_Ma2

Long-Term Debt and Liquidity Matters (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Apr. 09, 2013	Sep. 30, 2013	Apr. 09, 2013	Mar. 22, 2013	1-May-13	Jul. 12, 2013	Oct. 11, 2013
			Pinnacle West	Pinnacle West	APS	APS	APS	APS	Long term debt	Revolving credit facility maturing in 2016	Revolving credit facility maturing in 2016	Revolving credit facility maturing in 2015	Revolving credit facility maturing in 2018	Revolving credit facility maturing in 2018	4.50% unsecured senior notes that mature on April 1, 2042	Pollution Control Revenue Refunding Bonds, 2009 Series C	Pollution Control Revenue Refunding Bonds, 1994 Series A	Pollution Control Revenue Refunding Bonds, 1994 Series C
							ACC	ACC	APS	Pinnacle West	APS	APS	APS	APS	APS	APS	APS	APS
								Minimum	item									Subsequent event
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility									$1,000,000,000	$200,000,000	$500,000,000	$500,000,000	$500,000,000	$500,000,000
Maximum commercial paper support available under credit facility									250,000,000	200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders										300,000,000	700,000,000		700,000,000
Outstanding borrowings										0	0		0
Outstanding letters of credit										0	0		0
Commercial paper borrowings outstanding									0	0
Notes issued															100,000,000
Interest rate (as a percent)															4.50%	1.75%
Long-term debt redemption																32,000,000	33,000,000	32,000,000
Number of line of credit facilities									2
Estimated fair value of long-term debt, including current maturities
Carrying Amount	3,387,000,000	3,322,000,000	125,000,000	125,000,000	3,262,000,000	3,197,000,000
Fair Value	3,663,000,000	3,875,000,000	125,000,000	125,000,000	3,538,000,000	3,750,000,000
Debt Provisions
Required common equity ratio ordered by ACC (as a percent)								40.00%
Total shareholder equity	4,275,804,000	3,972,806,000			4,392,797,000	4,093,000,000	4,400,000,000
Total capitalization							7,600,000,000
Dividend restrictions, shareholder equity required								$3,000,000,000

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)

9 Months Ended

1 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

0 Months Ended

9 Months Ended

1 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

9 Months Ended

0 Months Ended

1 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Jan. 31, 2012

Jun. 30, 2011

Jan. 06, 2012

Jan. 31, 2012

Dec. 31, 2009

Jun. 30, 2010

Dec. 30, 2009

Sep. 30, 2013

1-May-13

Dec. 31, 2012

Feb. 12, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2011

Jun. 02, 2012

Jun. 30, 2012

Apr. 30, 2012

Jun. 30, 2011

Dec. 31, 2009

Jun. 02, 2011

Jan. 31, 2013

Jun. 30, 2012

Jun. 30, 2012

Jul. 12, 2013

Feb. 28, 2013

Sep. 30, 2013

Sep. 30, 2012

Jun. 01, 2013

Jun. 30, 2012

APS

APS

Filing with the Arizona Corporation Commission

Filing with the Arizona Corporation Commission

Filing with the Arizona Corporation Commission

Filing with the Arizona Corporation Commission

2008 General Retail Rate Case On-Going Impacts

2008 General Retail Rate Case On-Going Impacts

2008 General Retail Rate Case On-Going Impacts

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

Cost Recovery Mechanisms

APS

APS

APS

APS

APS

APS

APS

Power Supply Adjustor (PSA)

ACC

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

APS

ACC

ACC

ACC

ACC

ACC

ACC

ACC

2013 DSMAC

Lost Fixed Cost Recovery Mechanism

Lost Fixed Cost Recovery Mechanism

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

ACC

FERC

FERC

Retail rate case filing

Retail rate case filing

Retail rate case filing

Retail rate case filing

2008 General retail rate case

2008 General retail rate case

RES

2012 RES

2013 DSMAC

2012 DSMAC

2012 DSMAC

2012 DSMAC

2012 DSMAC

2012 DSMAC

2013 RES

2013 RES

2013 RES

RES implementation plan covering 2014-2018 timeframe

Power Supply Adjustor (PSA)

Power Supply Adjustor (PSA)

Power Supply Adjustor (PSA)

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters

Maximum

item

Maximum

Minimum

Regulatory Matters

Net retail rate increase

$95,500,000

Approximate percentage of increase in the average retail customer bill

6.60%

Settlement Agreement

Net change in base rates

0

Non-fuel base rate increase

116,300,000

Fuel-related base rate decrease

153,100,000

Current base fuel rate (in dollars per kWh)

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%

Annual cost recovery due to modifications to the Environmental Improvement Surcharge

5,000,000

Elimination of the sharing provision of fuel and purchased power costs

9

Period to process the subsequent rate cases

12 months

ACC staff sufficiency findings, general period of time

30 days

2008 General Retail Rate Case on-going impacts

Number of other parties to the settlement agreement

21

Minimum amount of reduction of average annual operational expenses from 2010 through 2014

30,000,000

Authorization and requirements of equity infusions into APS beginning June 1, 2009 through December 31, 2014

700,000,000

Equity infusions into APS

253,000,000

Change in regulatory asset

Plan term

5 years

Funding approval as per budget authorized

110,000,000

Funding request

107,000,000

97,000,000

Amount of approved budget

103,000,000

Amount of approved budget for residential distributed energy up-front incentives

4,000,000

Amount of approved budget for commercial distributed energy up-front incentives

100,000

Amount of proposed budget

87,600,000

143,000,000

Percentage of cumulative energy savings for prior year

3.00%

Percentage of annual energy savings to meet energy efficiency goal for 2011

2.75%

Period of energy savings goal

2 years

Demand-side management adjustor charge (DSMAC)

72,000,000

Costs already being recovered in general rates

10,000,000

Amortization of recovery of demand-side management adjustor charge included in costs already been recovered

5,000,000

Percentage of cumulative energy savings for current year

5.00%

Beginning balance

73,000,000

28,000,000

Deferred fuel and purchased power costs-current period

-13,093,000

-51,533,000

-13,093,000

-51,533,000

-13,000,000

-52,000,000

Amounts (collected from) credited to customers

-23,158,000

91,894,000

-23,158,000

91,894,000

-23,000,000

92,000,000

Ending balance

37,000,000

68,000,000

PSA rate (in dollars per kWh)

0.0013

PSA rate for prior year (in dollars per kWh)

-0.0042

Increase in PSA charge (in dollars per kWh)

0.0055

Forward component of increase in PSA (in dollars per kWh)

-0.001

Historical component of increase in PSA (in dollars per kWh)

0.0023

Maximum increase or decrease in PSA charge without permission of the ACC (in dollars per kWh)

0.004

Increase in annual wholesale transmission rates

26,000,000

16,000,000

Deferred contract termination charges to be amortized over a future period related to proposed acquisition of Southern California Edison

40,000,000

Amortization period

10 years

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

$5,100,000

Regulatory_Matters_Details_2

Regulatory Matters (Details 2) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Detail of regulatory assets
Regulatory assets, current	$120,000,000	$144,000,000
Regulatory assets, non-current	1,105,882,000	1,099,900,000
Pension and other postretirement benefits
Detail of regulatory assets
Regulatory assets, non-current	754,000,000	780,000,000
Income taxes - allowance for equity funds used during construction
Detail of regulatory assets
Regulatory assets, current	4,000,000	4,000,000
Regulatory assets, non-current	105,000,000	92,000,000
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	15,000,000	19,000,000
Regulatory assets, non-current	24,000,000	21,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	16,000,000	23,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	8,000,000	8,000,000
Regulatory assets, non-current	20,000,000	24,000,000
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, non-current	40,000,000	38,000,000
Deferred compensation
Detail of regulatory assets
Regulatory assets, non-current	36,000,000	34,000,000
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	37,000,000	73,000,000
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	3,000,000
Regulatory assets, non-current	19,000,000
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	15,000,000	17,000,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000,000	2,000,000
Regulatory assets, non-current	17,000,000	18,000,000
Income taxes - investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	30,000,000	26,000,000
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	8,000,000	8,000,000
Regulatory assets, non-current	6,000,000	13,000,000
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	19,000,000	7,000,000
Transmission cost adjustor
Detail of regulatory assets
Regulatory assets, current	12,000,000	10,000,000
Regulatory assets, non-current	2,000,000
Other
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	$22,000,000	$14,000,000

Regulatory_Matters_Details_3

Regulatory Matters (Details 3) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Detail of regulatory liabilities
Regulatory liabilities, current	$88,000,000	$88,000,000
Regulatory liabilities, non-current	798,226,000	759,201,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	26,000,000	27,000,000
Regulatory liabilities, non-current	311,000,000	321,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, non-current	272,000,000	256,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	27,000,000	43,000,000
Regulatory liabilities, non-current	22,000,000
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, non-current	68,000,000	66,000,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	5,000,000	10,000,000
Regulatory liabilities, non-current	37,000,000	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	11,000,000	12,000,000
Income taxes-deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	2,000,000	2,000,000
Regulatory liabilities, non-current	60,000,000	52,000,000
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	26,000,000	4,000,000
Other
Detail of regulatory liabilities
Regulatory liabilities, non-current	$17,000,000	$16,000,000

Retirement_Plans_and_Other_Ben2

Retirement Plans and Other Benefits (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Retirement Plans and Other Benefits
Amount of pension and other postretirement benefit costs deferred					$14
Amortization of regulatory assets	2	2	6	2
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	16	16	48	48
Interest cost on benefit obligation	28	30	84	90
Expected return on plan assets	-36	-35	-110	-106
Amortization of prior service cost			1	1
Amortization of net actuarial loss	10	11	30	33
Net periodic benefit cost	18	22	53	66
Portion of cost charged to expense	10	12	29	25
Contributions
Employer's contributions under the plan			141
Minimum Contributions under MAP-21
2013			0
2014			89
2015			112
Pension Benefits | Maximum
Expected employer's contributions
2014			175
2015			175
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	6	7	18	20
Interest cost on benefit obligation	10	12	31	35
Expected return on plan assets	-11	-12	-34	-34
Amortization of net actuarial loss	3	5	8	15
Net periodic benefit cost	8	12	23	36
Portion of cost charged to expense	5	7	14	13
Contributions
Employer's contributions under the plan			11
Expected employer's contributions
2013			14
2014			20
2015			$20

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012
Income Taxes
Long-term income tax receivables			$70,389,000
Decrease in long term deferred tax liability	80,000,000
Period over which deferred income tax liability would have been repaid		20 years
Income Taxes, additional disclosures
Percentage of bonus depreciation for federal income tax purposes		50.00%
Federal general business income tax credit carryforwards whose realization will be delayed on recognition of cash benefit			78,000,000
Federal general business income tax credit carryforwards	78,000,000	78,000,000
Palo Verde VIE
Income Taxes
Income tax expense associates with the VIE's		0
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Long-term income tax receivables			70,784,000
Decrease in uncertain tax positions	67,000,000	67,000,000
Income tax receivable that will be reclassified from long term to short-term	137,000,000
Anticipated refund amount	4,000,000	4,000,000
ARIZONA PUBLIC SERVICE COMPANY | Expected contributions
Income Taxes
Decrease in uncertain tax positions	$35,000,000	$35,000,000

Palo_Verde_Sale_Leaseback_Vari2

Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
					item
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$8,555,000	$8,040,000	$25,338,000	$23,582,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	126,092,000		126,092,000		128,995,000
Current maturities of long-term debt	566,481,000		566,481,000		122,828,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	37,414,000		37,414,000		38,869,000
Equity-Noncontrolling interests	145,624,000		145,624,000		129,483,000
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	8,555,000	8,040,000	25,338,000	23,573,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	126,092,000		126,092,000		128,995,000
Current maturities of long-term debt	566,481,000		566,481,000		122,828,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	37,414,000		37,414,000		38,869,000
Equity-Noncontrolling interests	145,624,000		145,624,000		129,483,000
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payment if lease is extended					23,000,000
Number of options					2
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	9,000,000	8,000,000	25,000,000	24,000,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	126,000,000		126,000,000		129,000,000
Current maturities of long-term debt	20,000,000		20,000,000		27,000,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	37,000,000		37,000,000		39,000,000
Equity-Noncontrolling interests	146,000,000		146,000,000		129,000,000
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events			142,000,000
VIE debt to be assumed upon the occurrence of certain unlikely events			$57,000,000

Derivative_Accounting_Details

Derivative Accounting (Details)	Sep. 30, 2013
	GW
Commodity - Power
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	6,498
Commodity - Gas
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	112,000
ARIZONA PUBLIC SERVICE COMPANY
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change	90.00%
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%

Derivative_Accounting_Details_

Derivative Accounting (Details 2) (Commodity Contracts, USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Designated as Hedging Instruments
Gains and losses from derivative instruments
Loss recognized in OCI on derivative instruments (effective portion)	($240,000)	($119,000)	($409,000)	($37,513,000)
Loss reclassified from AOCI into income (effective portion realized)	-23,658,000	-49,478,000	-39,156,000	-86,993,000
Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)				117,000
Amount reclassified from AOCI to earnings related to discontinued cash flow hedges	0	0	0	1,800,000
Estimated net loss before income taxes to be reclassified from AOCI			23,000,000
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net gain recognized in income from Derivative Instruments	-1,145,000	13,128,000	-11,350,000	13,879,000
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net gain recognized in income from Derivative Instruments	196,000	258,000	400,000	19,000
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net gain recognized in income from Derivative Instruments	($1,341,000)	$12,870,000	($11,750,000)	$13,860,000

Derivative_Accounting_Details_1

Derivative Accounting (Details 3) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Commodity Contracts
Assets
Amount Reported on Balance Sheet	$49,000
Assets and Liabilities
Gross Recognized Derivatives	-81,325	-122,252
Amounts Offset	28,300	49,299
Net Recognized Derivatives	-53,025	-72,953
Other	-19,318	-24,462
Amount Reported on Balance Sheet	-72,343	-97,415
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	32,201	42,495
Amounts Offset	-9,605	-17,797
Net Recognized Derivatives	22,596	24,698
Other	145	1,001
Amount Reported on Balance Sheet	22,741	25,699
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	27,905	41,563
Amounts Offset	-1,859	-5,672
Net Recognized Derivatives	26,046	35,891
Amount Reported on Balance Sheet	26,046	35,891
Commodity Contracts | Total Assets
Assets
Gross Recognized Derivatives	60,106	84,058
Amounts Offset	-11,464	-23,469
Net Recognized Derivatives	48,642	60,589
Other	145	1,001
Amount Reported on Balance Sheet	48,787	61,590
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	-66,680	-105,324
Amounts Offset	32,675	57,046
Net Recognized Derivatives	-34,005	-48,278
Other	-19,463	-25,463
Amount Reported on Balance Sheet	-53,468	-73,741
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	-74,751	-100,986
Amounts Offset	7,089	15,722
Net Recognized Derivatives	-67,662	-85,264
Amount Reported on Balance Sheet	-67,662	-85,264
Commodity Contracts | Total Liabilities
Liabilities
Gross Recognized Derivatives	-141,431	-206,310
Amounts Offset	39,764	72,768
Net Recognized Derivatives	-101,667	-133,542
Other	-19,463	-25,463
Amount Reported on Balance Sheet	-121,130	-159,005
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	$5,000	$5,000

Derivative_Accounting_Details_2

Derivative Accounting (Details 4) (Commodity Contracts, USD $)	9 Months Ended
	Sep. 30, 2013
	item
Commodity Contracts
Credit Risk and Credit-Related Contingent Features
Concentration of credit risk, number of counterparties	2
Concentration of risk with two counterparties, as a percentage of risk management assets	90.00%
Risk management activities-derivative instruments: Commodity Contracts	$49,000,000
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	141,000,000
Cash Collateral Posted	28,000,000
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	88,000,000
Additional collateral to counterparties for energy related non-derivative instrument contracts	$175,000,000

Changes_in_Equity_Details

Changes in Equity (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Changes in equity
Balance	$4,169,234	$3,899,337	$4,102,289	$3,930,586
Net income	234,718	252,863	407,152	382,493
Other comprehensive income	15,122	30,843	24,673	32,688
COMPREHENSIVE INCOME	249,840	283,706	431,825	415,181
Issuance of capital stock	2,331	2,365	7,268	7,590
Reissuance of treasury stock - net	37	-82	-5,868	3,277
Other (primarily stock compensation)	-22	258	14,988	4,270
Dividends on common Stock	8		-119,877	-172,344
Net capital activities by noncontrolling interests			-9,197	-2,976
Balance	4,421,428	4,185,584	4,421,428	4,185,584
Common Shareholders
Changes in equity
Balance	4,032,165	3,778,035	3,972,806	3,821,850
Net income	226,163	244,823	381,814	358,911
Other comprehensive income	15,122	30,843	24,673	32,688
COMPREHENSIVE INCOME	241,285	275,666	406,487	391,599
Issuance of capital stock	2,331	2,365	7,268	7,590
Reissuance of treasury stock - net	37	-82	-5,868	3,277
Other (primarily stock compensation)	-22	258	14,988	4,270
Dividends on common Stock	8		-119,877	-172,344
Balance	4,275,804	4,056,242	4,275,804	4,056,242
Noncontrolling Interests
Changes in equity
Balance	137,069	121,302	129,483	108,736
Net income	8,555	8,040	25,338	23,582
COMPREHENSIVE INCOME	8,555	8,040	25,338	23,582
Net capital activities by noncontrolling interests			-9,197	-2,976
Balance	$145,624	$129,342	$145,624	$129,342

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	0 Months Ended	9 Months Ended
	Apr. 02, 2013	Sep. 30, 2013
		item
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station
Estimated share of the costs related to on-site interim storage of spent nuclear fuel		$122,000,000
Regulatory liability of amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage		42,000,000
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
Maximum potential retrospective assessment per incident of APS		111,100,000
Annual payment limitation with respect to maximum potential retrospective assessment		16,400,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde		2,750,000,000
Sublimit for non-nuclear property damage losses which has been imposed to the primary policy offered	1,500,000,000
Sublimit for non-nuclear losses which has been imposed to the accidental outage policy	327,600,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment		18,000,000
Collateral assurance provided based on rating triggers		$48,000,000
Period to provide collateral assurance based on rating triggers		20 days

Commitments_and_Contingencies_2

Commitments and Contingencies (Details 2) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	1 Months Ended	9 Months Ended		0 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2011	Sep. 30, 2013	Sep. 08, 2011	Aug. 06, 2013
	item	item		Contaminated groundwater wells
	kV			item
	MW
Contractual Obligations
Decrease in contractual obligations for fuel and purchased power commitments		$300
2013		108
2014		576
2015		549
2016		516
2017		441
Thereafter		6,399
Total commitments		8,589
Superfund-Related Matters
Costs related to investigation and study under Superfund site		2
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit				24
Southwest Power Outage
Capacity of transmission line that tripped out of service (in kV)	500
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost	10 minutes
Number of customers losing service in Yuma area	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
Maximum possible fine per violation per day that the violation is found to have been in existence			1
Financial Assurances
Outstanding letters of credit to support existing variable interest rate pollution control bonds		76
Number of letters of credit expiring in 2015		1
Number of letters of credit expiring in 2016		2
Letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions		32
Outstanding letters of credit to support natural gas tolling contract obligations		$60

Commitments_and_Contingencies_3

Commitments and Contingencies (Details 3) (USD $)	0 Months Ended	9 Months Ended
In Millions, unless otherwise specified	23-May-13	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
	Four Corners	Four Corners	Four Corners	Navajo Plant	Cholla	Cholla Units 1-3
	New Mexico Tax Matter	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY
			New Mexico Tax Matter
Environmental Matters
Expected environmental cost		$300		$200	$200	$120
Coal severance surtax, penalty, and interest	30
Share of the assessment			$12

Other_Income_and_Other_Expense2

Other Income and Other Expense (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other income:
Interest income	$116	$307	$1,291	$1,018
Miscellaneous	44	113	96	339
Total other income	160	420	1,387	1,357
Other expense:
Non-operating costs	-2,028	-1,645	-5,951	-5,885
Investment losses - net	-3,435	-2,254	-3,643	-2,366
Miscellaneous	-1,972	-1,797	-3,827	-4,182
Total other expense	($7,435)	($5,696)	($13,421)	($12,433)

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Basic earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$2.06	$2.23	$3.47	$3.29
Loss from discontinued operations (in dollars per share)				($0.01)
Earnings per share - basic (in dollars per share)	$2.06	$2.23	$3.47	$3.28
Diluted earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$2.04	$2.21	$3.44	$3.26
Loss from discontinued operations (in dollars per share)				($0.01)
Earnings per share - diluted (in dollars per share)	$2.04	$2.21	$3.44	$3.25
Performance shares and restricted stock units	1,044,000	1,100,000	978,000	971,000
Options to purchase shares of common stock outstanding excluded from computation of diluted earnings per share due to its antidilutive effect	0	0	0	0

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Assets
Nuclear decommissioning trust	$612,640,000	$570,625,000
Total assets	48,000,000	62,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash Equivalents		16,000,000
Nuclear decommissioning trust	109,000,000	110,000,000
Total assets	109,000,000	126,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Nuclear decommissioning trust	109,000,000	104,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust		6,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Risk management activities-derivative instruments: Commodity Contracts	12,000,000	22,000,000
Nuclear decommissioning trust	507,000,000	465,000,000
Total assets	519,000,000	487,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	-49,000,000	-96,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Nuclear decommissioning trust	245,000,000	204,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	13,000,000	13,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	83,000,000	80,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	82,000,000	83,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Nuclear decommissioning trust	71,000,000	74,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Nuclear decommissioning trust	13,000,000	11,000,000
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Risk management activities-derivative instruments: Commodity Contracts	48,000,000	62,000,000
Total assets	48,000,000	62,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	-92,000,000	-110,000,000
Fair value measurement on a recurring basis | Other
Assets
Risk management activities-derivative instruments: Commodity Contracts	-11,000,000	-22,000,000
Nuclear decommissioning trust	-3,000,000	-4,000,000
Total assets	-14,000,000	-26,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	20,000,000	47,000,000
Fair value measurement on a recurring basis | Other | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	-3,000,000	-4,000,000
Fair value measurement on a recurring basis | Fair Value
Assets
Cash Equivalents		16,000,000
Risk management activities-derivative instruments: Commodity Contracts	49,000,000	62,000,000
Nuclear decommissioning trust	613,000,000	571,000,000
Total assets	662,000,000	649,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	-121,000,000	-159,000,000
Fair value measurement on a recurring basis | Fair Value | US commingled equity funds
Assets
Nuclear decommissioning trust	245,000,000	204,000,000
Fair value measurement on a recurring basis | Fair Value | U.S. Treasury
Assets
Nuclear decommissioning trust	109,000,000	104,000,000
Fair value measurement on a recurring basis | Fair Value | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	10,000,000	15,000,000
Fair value measurement on a recurring basis | Fair Value | Corporate debt
Assets
Nuclear decommissioning trust	83,000,000	80,000,000
Fair value measurement on a recurring basis | Fair Value | Mortgage-backed securities
Assets
Nuclear decommissioning trust	82,000,000	83,000,000
Fair value measurement on a recurring basis | Fair Value | Municipality bonds
Assets
Nuclear decommissioning trust	71,000,000	74,000,000
Fair value measurement on a recurring basis | Fair Value | Other
Assets
Nuclear decommissioning trust	$13,000,000	$11,000,000

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 2) (USD $)

3 Months Ended

9 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Electricity forward contracts

Electricity forward contracts

Electricity forward contracts

Electricity forward contracts

Electricity forward contracts

Electricity forward contracts

Electricity forward contracts

Electricity forward contracts

Option Contracts

Option Contracts

Option Contracts

Option Contracts

Option Contracts

Option Contracts

Option Contracts

Option Contracts

Natural gas forward contracts

Natural gas forward contracts

Natural gas forward contracts

Natural gas forward contracts

Natural gas forward contracts

Natural gas forward contracts

Natural gas forward contracts

Natural gas forward contracts

Minimum

Minimum

Maximum

Maximum

Weighted Average

Weighted Average

Minimum

Minimum

Maximum

Maximum

Weighted Average

Weighted Average

Minimum

Minimum

Maximum

Maximum

Weighted Average

Weighted Average

Discounted cash flows

Discounted cash flows

Discounted cash flows

Discounted cash flows

Discounted cash flows

Discounted cash flows

Option model

Option model

Option model

Option model

Option model

Option model

Discounted cash flows

Discounted cash flows

Discounted cash flows

Discounted cash flows

Discounted cash flows

Discounted cash flows

Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments

Assets

$48

$48

$62

$47

$57

$1

$5

Liabilities

92

92

110

74

82

16

27

2

1

Electricity forward price (per MWh)

24.55

23.06

60.97

64.2

40.23

43.16

38.56

36.66

82.07

92.19

55.74

60.97

Electricity price volatilities (as a percent)

51.00%

15.00%

106.00%

66.00%

74.00%

39.00%

Natural gas forward price (per mmbtu)

3.82

4.1

3.96

4.25

3.91

4.2

3.31

3.25

4.25

4.44

3.97

3.93

Natural gas price volatilities (as a percent)

24.00%

17.00%

51.00%

36.00%

31.00%

23.00%

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

Net derivative balance at beginning of period

-53

-45

-48

-51

Total net gains (losses) realized/unrealized:

Included in earnings

2

Included in OCI

-2

Deferred as a regulatory asset or liability

4

-3

-2

4

Settlements

6

-1

8

-1

Transfers into Level 3 from Level 2

-1

-4

-1

-2

Transfers from Level 3 into Level 2

3

-1

Net derivative balance at end of period

-44

-50

-44

-50

Transfers in or out of Level 1 to or from any other hierarchy level

$0

Nuclear_Decommissioning_Trusts2

Nuclear Decommissioning Trusts (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Nuclear decommissioning trust fund assets
Fair Value	$612,640,000		$612,640,000		$570,625,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities			363,944,000	295,126,000
Fair value of fixed income securities, summarized by contractual maturities
Total	612,640,000		612,640,000		570,625,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	612,640,000		612,640,000		570,625,000
Unrealized Gains	117,000,000		117,000,000		91,000,000
Unrealized Losses	-5,000,000		-5,000,000
Net payables for securities purchases	-3,000,000		-3,000,000		-4,000,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	1,000,000	1,000,000	4,000,000	5,000,000
Realized losses	-3,000,000	-1,000,000	-5,000,000	-3,000,000
Proceeds from the sale of securities	110,000,000	84,000,000	363,944,000	295,126,000
Fair value of fixed income securities, summarized by contractual maturities
Total	612,640,000		612,640,000		570,625,000
ARIZONA PUBLIC SERVICE COMPANY | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	245,000,000		245,000,000		204,000,000
Unrealized Gains	104,000,000		104,000,000		67,000,000
Fair value of fixed income securities, summarized by contractual maturities
Total	245,000,000		245,000,000		204,000,000
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	371,000,000		371,000,000		371,000,000
Unrealized Gains	13,000,000		13,000,000		24,000,000
Unrealized Losses	-5,000,000		-5,000,000
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	12,000,000		12,000,000
1 year - 5 years	106,000,000		106,000,000
5 years - 10 years	104,000,000		104,000,000
Greater than 10 years	149,000,000		149,000,000
Total	$371,000,000		$371,000,000		$371,000,000

Changes_in_Accumulated_Other_C2

Changes in Accumulated Other Comprehensive Loss (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	($104,457)		($114,008)
Other comprehensive loss before reclassifications	-145		-1,882
Amounts reclassified from accumulated other comprehensive loss	15,267		26,555
Net current period other comprehensive income	15,122	30,843	24,673	32,688
Ending balance	-89,335		-89,335
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-40,319		-49,592
Other comprehensive loss before reclassifications	-145		-247
Amounts reclassified from accumulated other comprehensive loss	14,310		23,685
Net current period other comprehensive income	14,165		23,438
Ending balance	-26,154		-26,154
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-64,138		-64,416
Other comprehensive loss before reclassifications			-1,635
Amounts reclassified from accumulated other comprehensive loss	957		2,870
Net current period other comprehensive income	957		1,235
Ending balance	($63,181)		($63,181)

CONDENSED_CONSOLIDATED_STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (APSC) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
OPERATING EXPENSES
Fuel and purchased power	$350,953	$302,894	$859,216	$783,926
Operations and maintenance	233,323	220,729	685,873	647,628
Depreciation and amortization	107,388	100,353	317,410	301,068
Taxes other than income taxes	43,256	36,507	124,091	120,271
Total	736,704	661,505	1,992,443	1,858,216
OPERATING INCOME	415,688	447,970	762,423	750,466
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,569	5,708	18,698	15,639
Other income (Note S-2)	160	420	1,387	1,357
Other expense (Note S-2)	-7,435	-5,696	-13,421	-12,433
Total	-1,706	432	6,664	4,563
INTEREST EXPENSE
Allowance for borrowed funds used during construction	-3,235	-3,830	-10,861	-10,428
Total	47,352	48,412	140,511	151,781
NET INCOME	234,718	252,863	407,152	382,493
Less: Net income attributable to noncontrolling interests (Note 6)	8,555	8,040	25,338	23,582
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	226,163	244,823	381,814	358,911
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	1,151,535	1,108,623	2,752,427	2,606,458
OPERATING EXPENSES
Fuel and purchased power	350,953	302,894	859,216	783,926
Operations and maintenance	222,617	218,403	668,319	640,596
Depreciation and amortization	107,364	100,329	317,338	300,997
Income taxes	143,335	153,797	241,347	233,679
Taxes other than income taxes	43,015	36,255	123,366	119,499
Total	867,284	811,678	2,209,586	2,078,697
OPERATING INCOME	284,251	296,945	542,841	527,761
OTHER INCOME (DEDUCTIONS)
Income taxes	4,123	3,170	9,555	6,906
Allowance for equity funds used during construction	5,569	5,708	18,698	15,639
Other income (Note S-2)	721	815	3,012	2,343
Other expense (Note S-2)	-4,615	-3,352	-15,755	-11,969
Total	5,798	6,341	15,510	12,919
INTEREST EXPENSE
Interest on long-term debt	47,214	48,841	140,978	150,416
Interest on short-term borrowings	1,553	1,334	4,950	5,283
Debt discount, premium and expense	1,008	1,070	3,001	3,182
Allowance for borrowed funds used during construction	-3,235	-3,830	-10,861	-10,428
Total	46,540	47,415	138,068	148,453
NET INCOME	243,509	255,871	420,283	392,227
Less: Net income attributable to noncontrolling interests (Note 6)	8,555	8,040	25,338	23,573
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$234,954	$247,831	$394,945	$368,654

CONDENSED_CONSOLIDATED_STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
NET INCOME	$234,718	$252,863	$407,152	$382,493
Derivative instruments:
Net unrealized loss, net of tax benefit of $95 and $47 for three months ended September 30, 2013 and 2012 and of $162 and $14,820 for nine months ended September 30, 2013 and 2012	-145	-72	-247	-22,696
Reclassification of net realized loss, net of tax benefit of $9,348 and $19,547 for three months ended September 30, 2013 and 2012 and $15,471 and $34,367 for nine months ended September 30, 2013 and 2012	14,310	29,935	23,685	52,632
Pension and other postretirement benefits activity, net of tax (expense) of $(621) and $(568) for three months ended September 30, 2013 and 2012 and $(798) and $(1,409) for nine months ended September 30, 2013 and 2012	957	980	1,235	2,752
Total other comprehensive income	15,122	30,843	24,673	32,688
COMPREHENSIVE INCOME	249,840	283,706	431,825	415,181
Less: Comprehensive income attributable to noncontrolling interests	8,555	8,040	25,338	23,582
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	241,285	275,666	406,487	391,599
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	243,509	255,871	420,283	392,227
Derivative instruments:
Net unrealized loss, net of tax benefit of $95 and $47 for three months ended September 30, 2013 and 2012 and of $162 and $14,820 for nine months ended September 30, 2013 and 2012	-145	-72	-247	-22,693
Reclassification of net realized loss, net of tax benefit of $9,348 and $19,547 for three months ended September 30, 2013 and 2012 and $15,471 and $34,367 for nine months ended September 30, 2013 and 2012	14,310	29,931	23,684	52,625
Pension and other postretirement benefits activity, net of tax (expense) of $(621) and $(568) for three months ended September 30, 2013 and 2012 and $(798) and $(1,409) for nine months ended September 30, 2013 and 2012	951	869	1,222	2,158
Total other comprehensive income	15,116	30,728	24,659	32,090
COMPREHENSIVE INCOME	258,625	286,599	444,942	424,317
Less: Comprehensive income attributable to noncontrolling interests	8,555	8,040	25,338	23,573
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$250,070	$278,559	$419,604	$400,744

CONDENSED_CONSOLIDATED_STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net unrealized loss, tax benefit	$95	$47	$162	$14,817
Reclassification of net realized loss, tax benefit	9,348	19,543	15,471	34,361
Pension and other postretirement benefits activity, tax (expense)	-625	-640	-807	-1,797
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized loss, tax benefit	95	47	162	14,820
Reclassification of net realized loss, tax benefit	9,348	19,547	15,471	34,367
Pension and other postretirement benefits activity, tax (expense)	($621)	($568)	($798)	($1,409)

CONDENSED_CONSOLIDATED_BALANCE2

CONDENSED CONSOLIDATED BALANCE SHEETS (APSC) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$14,597,995	$14,346,367
Accumulated depreciation and amortization	-5,101,498	-4,929,613
Net	9,496,497	9,416,754
Construction work in progress	605,987	565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	126,092	128,995
Intangible assets, net of accumulated amortization	160,134	162,150
Nuclear fuel, net of accumulated amortization	140,356	122,778
Total property, plant and equipment	10,529,066	10,396,393
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	612,640	570,625
Assets from risk management activities (Note 7)	26,046	35,891
Other assets	60,219	62,694
Total investments and other assets	698,905	669,210
CURRENT ASSETS
Cash and cash equivalents	135,457	26,202
Customer and other receivables	427,370	277,225
Accrued unbilled revenues	132,555	94,845
Allowance for doubtful accounts	-3,768	-3,340
Materials and supplies (at average cost)	223,385	218,096
Income tax receivable	133,551	2,423
Fossil fuel (at average cost)	34,959	31,334
Deferred fuel and purchased power regulatory asset (Note 3)	37,383	72,692
Other regulatory assets (Note 3)	82,558	71,257
Deferred income taxes	87,490	152,191
Assets from risk management activities (Note 7)	22,741	25,699
Other current assets	36,805	37,102
Total current assets	1,350,486	1,005,726
DEFERRED DEBITS
Regulatory assets (Note 3)	1,105,882	1,099,900
Income tax receivable (Note 5)		70,389
Other	138,332	137,997
Total deferred debits	1,244,214	1,308,286
TOTAL ASSETS	13,822,671	13,379,615
CAPITALIZATION
Common stock	2,479,101	2,462,712
Retained earnings	1,886,038	1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits	-63,181	-64,416
Derivative instruments	-26,154	-49,592
Total shareholders' equity	4,275,804	3,972,806
Noncontrolling interests (Note 6)	145,624	129,483
Total equity	4,421,428	4,102,289
Long-term debt less current maturities (Note 2)	2,782,901	3,160,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414	38,869
CURRENT LIABILITIES
Short-term borrowings		92,175
Current maturities of long-term debt (Note 2)	566,481	122,828
Accounts payable	250,023	221,312
Accrued taxes (Note 5)	183,858	124,939
Accrued interest	45,811	49,380
Common dividends payable		59,789
Customer deposits	77,254	79,689
Liabilities from risk management activities (Note 7)	53,468	73,741
Regulatory liabilities (Note 3)	88,409	88,116
Other current liabilities	181,639	171,573
Total current liabilities	1,446,943	1,083,542
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,363,783	2,151,371
Regulatory liabilities (Note 3)	798,226	759,201
Liability for asset retirements	364,635	357,097
Liabilities for pension and other postretirement benefits (Note 4)	939,414	1,058,755
Deferred investment tax credit	115,984	99,819
Liabilities from risk management activities (Note 7)	67,662	85,264
Customer advances	109,667	109,359
Coal mine reclamation	114,764	118,860
Unrecognized tax benefits (Note 5)	81,797	71,135
Other	178,053	183,835
Total deferred credits and other	5,133,985	4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	13,822,671	13,379,615
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,594,129	14,342,501
Accumulated depreciation and amortization	-5,097,804	-4,925,990
Net	9,496,325	9,416,511
Construction work in progress	605,987	565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	126,092	128,995
Intangible assets, net of accumulated amortization	159,979	161,995
Nuclear fuel, net of accumulated amortization	140,356	122,778
Total property, plant and equipment	10,528,739	10,395,995
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	612,640	570,625
Assets from risk management activities (Note 7)	26,046	35,891
Other assets	33,203	31,650
Total investments and other assets	671,889	638,166
CURRENT ASSETS
Cash and cash equivalents	113,072	3,499
Customer and other receivables	426,425	274,815
Accrued unbilled revenues	132,555	94,845
Allowance for doubtful accounts	-3,768	-3,340
Materials and supplies (at average cost)	223,385	218,096
Income tax receivable	126,098	589
Fossil fuel (at average cost)	34,959	31,334
Deferred fuel and purchased power regulatory asset (Note 3)	37,383	72,692
Other regulatory assets (Note 3)	82,558	71,257
Deferred income taxes	538	74,420
Assets from risk management activities (Note 7)	22,741	25,699
Other current assets	35,983	37,077
Total current assets	1,231,929	900,983
DEFERRED DEBITS
Regulatory assets (Note 3)	1,105,882	1,099,900
Unamortized debt issue costs	22,367	22,492
Income tax receivable (Note 5)		70,784
Other	114,995	114,222
Total deferred debits	1,243,244	1,307,398
TOTAL ASSETS	13,675,801	13,242,542
CAPITALIZATION
Common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,899,375	1,624,237
Accumulated other comprehensive loss:
Pension and other postretirement benefits	-38,281	-39,503
Derivative instruments	-26,155	-49,592
Total shareholders' equity	4,392,797	4,093,000
Noncontrolling interests (Note 6)	145,624	129,483
Total equity	4,538,421	4,222,483
Long-term debt less current maturities (Note 2)	2,657,901	3,035,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414	38,869
Total capitalization	7,233,736	7,296,571
CURRENT LIABILITIES
Short-term borrowings		92,175
Current maturities of long-term debt (Note 2)	566,481	122,828
Accounts payable	243,470	215,577
Accrued taxes (Note 5)	178,349	116,700
Accrued interest	45,542	49,135
Common dividends payable		59,800
Customer deposits	77,254	79,689
Liabilities from risk management activities (Note 7)	53,468	73,741
Regulatory liabilities (Note 3)	88,409	88,116
Other current liabilities	152,392	145,326
Total current liabilities	1,405,365	1,043,087
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,337,320	2,133,976
Regulatory liabilities (Note 3)	798,226	759,201
Liability for asset retirements	364,635	357,097
Liabilities for pension and other postretirement benefits (Note 4)	901,146	1,017,556
Deferred investment tax credit	115,984	99,819
Liabilities from risk management activities (Note 7)	67,662	85,264
Customer advances	109,667	109,359
Coal mine reclamation	114,764	118,860
Unrecognized tax benefits (Note 5)	81,589	70,932
Other	145,707	150,820
Total deferred credits and other	5,036,700	4,902,884
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$13,675,801	$13,242,542

CONDENSED_CONSOLIDATED_STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (APSC) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$407,152	$382,493
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	377,971	360,570
Deferred fuel and purchased power	13,093	51,533
Deferred fuel and purchased power amortization	23,158	-91,894
Allowance for equity funds used during construction	-18,698	-15,639
Deferred income taxes	256,132	197,527
Deferred investment tax credit	16,164	8,974
Change in derivative instruments fair value	537	-943
Changes in current assets and liabilities:
Customer and other receivables	-178,029	-76,697
Accrued unbilled revenues	-37,710	-11,186
Materials, supplies and fossil fuel	-8,914	-23,873
Income tax receivable	-131,128	6,466
Other current assets	-12,246	-10,035
Accounts payable	44,704	-69,776
Accrued taxes	58,919	69,899
Other current liabilities	4,096	17,071
Change in margin and collateral accounts - assets	-327	1,980
Change in margin and collateral accounts - liabilities	15,000	114,579
Change in unrecognized tax benefits	-57,585	-3,554
Change in long-term income tax receivable	137,270	-1,320
Change in other long-term assets	-24,345	-13,885
Change in other long-term liabilities	-2,884	37,181
Net cash flow provided by operating activities	882,330	929,471
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	-581,515	-670,684
Contributions in aid of construction	34,910	41,451
Allowance for borrowed funds used during construction	-10,861	-10,428
Proceeds from nuclear decommissioning trust sales	363,944	295,126
Investment in nuclear decommissioning trust	-376,881	-308,063
Other	-1,553	-520
Net cash flow used for investing activities	-571,956	-653,118
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	351,081
Short-term borrowings - net	-92,175
Repayment of long-term debt	-72,777	-421,703
Dividends paid on common stock	-174,485	-167,074
Noncontrolling interests	-9,197	-2,630
Net cash flow used for financing activities	-201,119	-230,457
NET INCREASE IN CASH AND CASH EQUIVALENTS	109,255	45,896
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	26,202	33,583
CASH AND CASH EQUIVALENTS AT END OF PERIOD	135,457	79,479
Cash paid during the period for:
Income taxes paid	3,412	-651
Interest, net of amounts capitalized	141,047	152,582
Significant non-cash investing and financing activities:
Accrued capital expenditures	11,377	11,281
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	420,283	392,227
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	377,899	360,499
Deferred fuel and purchased power	13,093	51,533
Deferred fuel and purchased power amortization	23,158	-91,894
Allowance for equity funds used during construction	-18,698	-15,639
Deferred income taxes	256,253	222,251
Deferred investment tax credit	16,164	8,974
Change in derivative instruments fair value	537	-943
Changes in current assets and liabilities:
Customer and other receivables	-179,494	-79,152
Accrued unbilled revenues	-37,710	-11,186
Materials, supplies and fossil fuel	-8,914	-23,873
Income tax receivable	-125,509	-775
Other current assets	-11,449	-10,446
Accounts payable	43,886	-72,802
Accrued taxes	61,649	62,834
Other current liabilities	1,073	112
Change in margin and collateral accounts - assets	-327	1,980
Change in margin and collateral accounts - liabilities	15,000	114,579
Change in unrecognized tax benefits	-57,585	-3,554
Change in long-term income tax receivable	137,665	-1,320
Change in other long-term assets	-28,686	-17,185
Change in other long-term liabilities	691	36,451
Net cash flow provided by operating activities	898,979	922,671
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	-581,515	-670,684
Contributions in aid of construction	34,910	41,451
Allowance for borrowed funds used during construction	-10,861	-10,428
Proceeds from nuclear decommissioning trust sales	363,944	295,126
Investment in nuclear decommissioning trust	-376,881	-308,063
Other	-1,561	-520
Net cash flow used for investing activities	-571,964	-653,118
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	351,081
Short-term borrowings - net	-92,175
Repayment of long-term debt	-72,777	-421,703
Dividends paid on common stock	-179,600	-162,400
Noncontrolling interests	-9,197	-2,630
Net cash flow used for financing activities	-217,442	-235,652
NET INCREASE IN CASH AND CASH EQUIVALENTS	109,573	33,901
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,499	19,873
CASH AND CASH EQUIVALENTS AT END OF PERIOD	113,072	53,774
Cash paid during the period for:
Income taxes paid	3,412
Interest, net of amounts capitalized	138,626	149,338
Significant non-cash investing and financing activities:
Accrued capital expenditures	$11,377	$11,281

Changes_in_Equity_APSC

Changes in Equity (APSC)	9 Months Ended
	Sep. 30, 2013
Changes in equity
Changes in Equity	8.                                      Changes in Equity
	The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended September 30, 2013									Three Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, July 1	$	4,032,165		$	137,069		$	4,169,234		$	3,778,035		$	121,302		$	3,899,337
	Net income	226,163			8,555			234,718			244,823			8,040			252,863
	Other comprehensive income	15,122			—			15,122			30,843			—			30,843
	Total comprehensive income	241,285			8,555			249,840			275,666			8,040			283,706
	Issuance of capital stock	2,331			—			2,331			2,365			—			2,365
	Reissuance of treasury stock — net	37			—			37			(82		)	—			(82		)
	Other (primarily stock compensation)	(22		)	—			(22		)	258			—			258
	Dividends on common stock	8			—			8			—			—			—
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584
		Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
	Net income	381,814			25,338			407,152			358,911			23,582			382,493
	Other comprehensive income	24,673			—			24,673			32,688			—			32,688
	Total comprehensive income	406,487			25,338			431,825			391,599			23,582			415,181
	Issuance of capital stock	7,268			—			7,268			7,590			—			7,590
	Reissuance (purchase) of treasury stock - net	(5,868		)	—			(5,868		)	3,277			—			3,277
	Other (primarily stock compensation)	14,988			—			14,988			4,270			—			4,270
	Dividends on common stock	(119,877		)	—			(119,877		)	(172,344		)	—			(172,344		)
	Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,976		)	(2,976		)
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Changes in Equity	ARIZONA PUBLIC SERVICE COMPANY
	NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	S-1.                           Changes in Equity
	The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended September 30, 2013									Three Months Ended September 30, 2012
		Shareholder			Noncontrolling			Total			Shareholder			Noncontrolling			Total
		Equity			Interests						Equity			Interests
	Beginning balance, July 1	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093
	Net income	234,954			8,555			243,509			247,831			8,040			255,871
	OCI	15,116			—			15,116			30,728			—			30,728
	Total comprehensive income	250,070			8,555			258,625			278,559			8,040			286,599
	Other	1			(1		)	—			1			—			1
	Ending balance, September 30	$	4,392,797		$	145,624		$	4,538,421		$	4,181,351		$	129,342		$	4,310,693
		Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
		Shareholder			Noncontrolling			Total			Shareholder			Noncontrolling			Total
		Equity			Interests						Equity			Interests
	Beginning balance, January 1	$	4,093,000		$	129,483		$	4,222,483		$	3,943,007		$	108,399		$	4,051,406
	Net income	394,945			25,338			420,283			368,654			23,573			392,227
	OCI	24,659			—			24,659			32,090			—			32,090
	Total comprehensive income	419,604			25,338			444,942			400,744			23,573			424,317
	Dividends on common stock	(119,800		)	—			(119,800		)	(162,400		)	—			(162,400		)
	Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,630		)	(2,630		)
	Other	(7		)	—			(7		)	—			—			—
	Ending balance, September 30	$	4,392,797		$	145,624		$	4,538,421		$	4,181,351		$	129,342		$	4,310,693

Other_Income_and_Other_Expense3

Other Income and Other Expense (APSC)	9 Months Ended
	Sep. 30, 2013
Other Income and Other Expense	10.                               Other Income and Other Expense
	The following table provides detail of other income and other expense for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Other income:
	Interest income	$	116		$	307		$	1,291		$	1,018
	Miscellaneous	44			113			96			339
	Total other income	$	160		$	420		$	1,387		$	1,357
	Other expense:
	Non-operating costs	$	(2,028	)	$	(1,645	)	$	(5,951	)	$	(5,885	)
	Investment losses — net	(3,435		)	(2,254		)	(3,643		)	(2,366		)
	Miscellaneous	(1,972		)	(1,797		)	(3,827		)	(4,182		)
	Total other expense	$	(7,435	)	$	(5,696	)	$	(13,421	)	$	(12,433	)
ARIZONA PUBLIC SERVICE COMPANY
Other Income and Other Expense	ARIZONA PUBLIC SERVICE COMPANY
	NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	S-2.                           Other Income and Other Expense
	The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Other income:
	Interest income	$	2		$	61		$	1,061		$	244
	Miscellaneous	719			754			1,951			2,099
	Total other income	$	721		$	815		$	3,012		$	2,343
	Other expense:
	Non-operating costs (a)	$	(2,263	)	$	(2,007	)	$	(6,868	)	$	(6,690	)
	Asset dispositions	(1,203		)	(248		)	(3,864		)	(666		)
	Miscellaneous	(1,149		)	(1,097		)	(5,023		)	(4,613		)
	Total other expense	$	(4,615	)	$	(3,352	)	$	(15,755	)	$	(11,969	)
	(a)                                 As defined by the FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).

Changes_in_Accumulated_Other_C3

Changes in Accumulated Other Comprehensive Loss (APSC)	9 Months Ended
	Sep. 30, 2013
Changes in Accumulated Other Comprehensive Loss	15.                               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 three and nine months ended September 30, 2013 (dollars in thousands):
		Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
		Derivative			Pension and			Total			Derivative			Pension and			Total
		Instruments			Other						Instruments			Other
					Postretirement									Postretirement
					Benefits									Benefits
	Beginning balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
	Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,635		)	(1,882		)
	Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	957		(b)	15,267			23,685		(a)	2,870		(b)	26,555
	Net current period other comprehensive income	14,165			957			15,122			23,438			1,235			24,673
	Ending balance	$	(26,154	)	$	(63,181	)	$	(89,335	)	$	(26,154	)	$	(63,181	)	$	(89,335	)
	(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 7.
	(b)         These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
ARIZONA PUBLIC SERVICE COMPANY
Changes in Accumulated Other Comprehensive Loss	ARIZONA PUBLIC SERVICE COMPANY
	NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	S-3.                           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 three and nine months ended September 30, 2013 (dollars in thousands):
		Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
		Derivative			Pension and			Total			Derivative			Pension and			Total
		Instruments			Other						Instruments			Other
					Postretirement									Postretirement
					Benefits									Benefits
	Beginning balance	$	(40,320	)	$	(39,232	)	$	(79,552	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
	Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,630		)	(1,877		)
	Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	951		(b)	15,261			23,684		(a)	2,852		(b)	26,536
	Net current period other comprehensive income	14,165			951			15,116			23,437			1,222			24,659
	Ending balance	$	(26,155	)	$	(38,281	)	$	(64,436	)	$	(26,155	)	$	(38,281	)	$	(64,436	)
	(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 7.
	(b)         These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.

Changes_in_Equity_APSC_Tables

Changes in Equity (APSC) (Tables)	9 Months Ended
	Sep. 30, 2013
Changes in equity
Schedule of changes in shareholders' equity and changes in equity of noncontrolling interests	The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended September 30, 2013									Three Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, July 1	$	4,032,165		$	137,069		$	4,169,234		$	3,778,035		$	121,302		$	3,899,337
	Net income	226,163			8,555			234,718			244,823			8,040			252,863
	Other comprehensive income	15,122			—			15,122			30,843			—			30,843
	Total comprehensive income	241,285			8,555			249,840			275,666			8,040			283,706
	Issuance of capital stock	2,331			—			2,331			2,365			—			2,365
	Reissuance of treasury stock — net	37			—			37			(82		)	—			(82		)
	Other (primarily stock compensation)	(22		)	—			(22		)	258			—			258
	Dividends on common stock	8			—			8			—			—			—
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584
		Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
		Common			Noncontrolling			Total			Common			Noncontrolling			Total
		Shareholders			Interests						Shareholders			Interests
	Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
	Net income	381,814			25,338			407,152			358,911			23,582			382,493
	Other comprehensive income	24,673			—			24,673			32,688			—			32,688
	Total comprehensive income	406,487			25,338			431,825			391,599			23,582			415,181
	Issuance of capital stock	7,268			—			7,268			7,590			—			7,590
	Reissuance (purchase) of treasury stock - net	(5,868		)	—			(5,868		)	3,277			—			3,277
	Other (primarily stock compensation)	14,988			—			14,988			4,270			—			4,270
	Dividends on common stock	(119,877		)	—			(119,877		)	(172,344		)	—			(172,344		)
	Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,976		)	(2,976		)
	Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Schedule of changes in shareholders' equity and changes in equity of noncontrolling interests	The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended September 30, 2013									Three Months Ended September 30, 2012
		Shareholder			Noncontrolling			Total			Shareholder			Noncontrolling			Total
		Equity			Interests						Equity			Interests
	Beginning balance, July 1	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093
	Net income	234,954			8,555			243,509			247,831			8,040			255,871
	OCI	15,116			—			15,116			30,728			—			30,728
	Total comprehensive income	250,070			8,555			258,625			278,559			8,040			286,599
	Other	1			(1		)	—			1			—			1
	Ending balance, September 30	$	4,392,797		$	145,624		$	4,538,421		$	4,181,351		$	129,342		$	4,310,693
		Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
		Shareholder			Noncontrolling			Total			Shareholder			Noncontrolling			Total
		Equity			Interests						Equity			Interests
	Beginning balance, January 1	$	4,093,000		$	129,483		$	4,222,483		$	3,943,007		$	108,399		$	4,051,406
	Net income	394,945			25,338			420,283			368,654			23,573			392,227
	OCI	24,659			—			24,659			32,090			—			32,090
	Total comprehensive income	419,604			25,338			444,942			400,744			23,573			424,317
	Dividends on common stock	(119,800		)	—			(119,800		)	(162,400		)	—			(162,400		)
	Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,630		)	(2,630		)
	Other	(7		)	—			(7		)	—			—			—
	Ending balance, September 30	$	4,392,797		$	145,624		$	4,538,421		$	4,181,351		$	129,342		$	4,310,693

Other_Income_and_Other_Expense4

Other Income and Other Expense (APSC) (Tables)	9 Months Ended
	Sep. 30, 2013
Detail of other income and other expense	The following table provides detail of other income and other expense for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Other income:
	Interest income	$	116		$	307		$	1,291		$	1,018
	Miscellaneous	44			113			96			339
	Total other income	$	160		$	420		$	1,387		$	1,357
	Other expense:
	Non-operating costs	$	(2,028	)	$	(1,645	)	$	(5,951	)	$	(5,885	)
	Investment losses — net	(3,435		)	(2,254		)	(3,643		)	(2,366		)
	Miscellaneous	(1,972		)	(1,797		)	(3,827		)	(4,182		)
	Total other expense	$	(7,435	)	$	(5,696	)	$	(13,421	)	$	(12,433	)
ARIZONA PUBLIC SERVICE COMPANY
Detail of other income and other expense	The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Other income:
	Interest income	$	2		$	61		$	1,061		$	244
	Miscellaneous	719			754			1,951			2,099
	Total other income	$	721		$	815		$	3,012		$	2,343
	Other expense:
	Non-operating costs (a)	$	(2,263	)	$	(2,007	)	$	(6,868	)	$	(6,690	)
	Asset dispositions	(1,203		)	(248		)	(3,864		)	(666		)
	Miscellaneous	(1,149		)	(1,097		)	(5,023		)	(4,613		)
	Total other expense	$	(4,615	)	$	(3,352	)	$	(15,755	)	$	(11,969	)
	(a)                                 As defined by the FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).

Changes_in_Accumulated_Other_C4

Changes in Accumulated Other Comprehensive Loss (APSC) (Tables)	9 Months Ended
	Sep. 30, 2013
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 three and nine months ended September 30, 2013 (dollars in thousands):
		Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
		Derivative			Pension and			Total			Derivative			Pension and			Total
		Instruments			Other						Instruments			Other
					Postretirement									Postretirement
					Benefits									Benefits
	Beginning balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
	Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,635		)	(1,882		)
	Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	957		(b)	15,267			23,685		(a)	2,870		(b)	26,555
	Net current period other comprehensive income	14,165			957			15,122			23,438			1,235			24,673
	Ending balance	$	(26,154	)	$	(63,181	)	$	(89,335	)	$	(26,154	)	$	(63,181	)	$	(89,335	)
	(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 7.
	(b)         These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.
ARIZONA PUBLIC SERVICE COMPANY
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 three and nine months ended September 30, 2013 (dollars in thousands):
		Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
		Derivative			Pension and			Total			Derivative			Pension and			Total
		Instruments			Other						Instruments			Other
					Postretirement									Postretirement
					Benefits									Benefits
	Beginning balance	$	(40,320	)	$	(39,232	)	$	(79,552	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
	Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,630		)	(1,877		)
	Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	951		(b)	15,261			23,684		(a)	2,852		(b)	26,536
	Net current period other comprehensive income	14,165			951			15,116			23,437			1,222			24,659
	Ending balance	$	(26,155	)	$	(38,281	)	$	(64,436	)	$	(26,155	)	$	(38,281	)	$	(64,436	)
	(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 7.
	(b)         These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 4.

Changes_in_Equity_APSC_Details

Changes in Equity (APSC) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Changes in equity
Balance	$4,169,234	$3,899,337	$4,102,289	$3,930,586
Net income	234,718	252,863	407,152	382,493
Other comprehensive income	15,122	30,843	24,673	32,688
COMPREHENSIVE INCOME	249,840	283,706	431,825	415,181
Dividends on common stock	8		-119,877	-172,344
Net capital activities by noncontrolling interests			-9,197	-2,976
Other	22	-258	-14,988	-4,270
Balance	4,421,428	4,185,584	4,421,428	4,185,584
Shareholder equity
Changes in equity
Balance	4,032,165	3,778,035	3,972,806	3,821,850
Net income	226,163	244,823	381,814	358,911
Other comprehensive income	15,122	30,843	24,673	32,688
COMPREHENSIVE INCOME	241,285	275,666	406,487	391,599
Dividends on common stock	8		-119,877	-172,344
Other	22	-258	-14,988	-4,270
Balance	4,275,804	4,056,242	4,275,804	4,056,242
Noncontrolling Interests
Changes in equity
Balance	137,069	121,302	129,483	108,736
Net income	8,555	8,040	25,338	23,582
COMPREHENSIVE INCOME	8,555	8,040	25,338	23,582
Net capital activities by noncontrolling interests			-9,197	-2,976
Balance	145,624	129,342	145,624	129,342
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Balance	4,279,796	4,024,093	4,222,483	4,051,406
Net income	243,509	255,871	420,283	392,227
Other comprehensive income	15,116	30,728	24,659	32,090
COMPREHENSIVE INCOME	258,625	286,599	444,942	424,317
Dividends on common stock			-119,800	-162,400
Net capital activities by noncontrolling interests			-9,197	-2,630
Other		1	-7
Balance	4,538,421	4,310,693	4,538,421	4,310,693
ARIZONA PUBLIC SERVICE COMPANY | Shareholder equity
Changes in equity
Balance	4,142,726	3,902,791	4,093,000	3,943,007
Net income	234,954	247,831	394,945	368,654
Other comprehensive income	15,116	30,728	24,659	32,090
COMPREHENSIVE INCOME	250,070	278,559	419,604	400,744
Dividends on common stock			-119,800	-162,400
Other	1	1	-7
Balance	4,392,797	4,181,351	4,392,797	4,181,351
ARIZONA PUBLIC SERVICE COMPANY | Noncontrolling Interests
Changes in equity
Balance	137,070	121,302	129,483	108,399
Net income	8,555	8,040	25,338	23,573
COMPREHENSIVE INCOME	8,555	8,040	25,338	23,573
Net capital activities by noncontrolling interests			-9,197	-2,630
Other	-1
Balance	$145,624	$129,342	$145,624	$129,342

Other_Income_and_Other_Expense5

Other Income and Other Expense (APSC) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other income:
Interest income	$116	$307	$1,291	$1,018
Miscellaneous	44	113	96	339
Total other income	160	420	1,387	1,357
Other expense:
Non-operating costs	-2,028	-1,645	-5,951	-5,885
Miscellaneous	-1,972	-1,797	-3,827	-4,182
Total other expense	-7,435	-5,696	-13,421	-12,433
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	2	61	1,061	244
Miscellaneous	719	754	1,951	2,099
Total other income	721	815	3,012	2,343
Other expense:
Non-operating costs	-2,263	-2,007	-6,868	-6,690
Asset dispositions	-1,203	-248	-3,864	-666
Miscellaneous	-1,149	-1,097	-5,023	-4,613
Total other expense	($4,615)	($3,352)	($15,755)	($11,969)

Changes_in_Accumulated_Other_C5

Changes in Accumulated Other Comprehensive Loss (APSC) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	($104,457)		($114,008)
Other comprehensive loss before reclassifications	-145		-1,882
Amounts reclassified from accumulated other comprehensive loss	15,267		26,555
Net current period other comprehensive income	15,122	30,843	24,673	32,688
Ending balance	-89,335		-89,335
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-40,319		-49,592
Other comprehensive loss before reclassifications	-145		-247
Amounts reclassified from accumulated other comprehensive loss	14,310		23,685
Net current period other comprehensive income	14,165		23,438
Ending balance	-26,154		-26,154
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-64,138		-64,416
Other comprehensive loss before reclassifications			-1,635
Amounts reclassified from accumulated other comprehensive loss	957		2,870
Net current period other comprehensive income	957		1,235
Ending balance	-63,181		-63,181
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-79,552		-89,095
Other comprehensive loss before reclassifications	-145		-1,877
Amounts reclassified from accumulated other comprehensive loss	15,261		26,536
Net current period other comprehensive income	15,116	30,728	24,659	32,090
Ending balance	-64,436		-64,436
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-40,320		-49,592
Other comprehensive loss before reclassifications	-145		-247
Amounts reclassified from accumulated other comprehensive loss	14,310		23,684
Net current period other comprehensive income	14,165		23,437
Ending balance	-26,155		-26,155
ARIZONA PUBLIC SERVICE COMPANY | Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	-39,232		-39,503
Other comprehensive loss before reclassifications			-1,630
Amounts reclassified from accumulated other comprehensive loss	951		2,852
Net current period other comprehensive income	951		1,222
Ending balance	($38,281)		($38,281)