10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2013

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File  Number	Exact Name of Each Registrant as specified in its charter; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
1-8962	PINNACLE WEST CAPITAL CORPORATION (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000	86-0512431
1-4473	ARIZONA PUBLIC SERVICE COMPANY (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000	86-0011170

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION	Yes x  No o
ARIZONA PUBLIC SERVICE COMPANY	Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PINNACLE WEST CAPITAL CORPORATION	Yes x  No o
ARIZONA PUBLIC SERVICE COMPANY	Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o Accelerated filer o Non-accelerated filer x Smaller reporting company o

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

PINNACLE WEST CAPITAL CORPORATION	Yes o  No x
ARIZONA PUBLIC SERVICE COMPANY	Yes o  No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of July 29, 2013: 109,996,850
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of July 29, 2013: 71,264,947

Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

TABLE OF CONTENTS

		Page
Forward-Looking Statements		2
Part I		3
Item 1.	Financial Statements	3
	Pinnacle West Capital Corporation	3
	Arizona Public Service Company	45
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	56
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	77
Item 4.	Controls and Procedures	77
Part II		79
Item 1.	Legal Proceedings	79
Item 1A.	Risk Factors	79
Item 5.	Other Information	79
Item 6.	Exhibits	81
Signatures		84

This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation (“Pinnacle West”) and Arizona Public Service Company (“APS”).  Any use of the words “Company,” “we,” and “our” refer to Pinnacle West.  Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries.  Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information.  The information required with respect to each company is set forth within the applicable items.  Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS.  Item 1 also includes Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS, and Supplemental Notes, which only relate to APS’s Condensed Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (“2012 Form 10-K”), Part II, Item 1A of this report and in Part I, Item 2 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, these factors include, but are not limited to:

·our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;

·variations in demand for electricity, including those due to weather, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation;

·power plant and transmission system performance and outages;

·volatile fuel and purchased power costs;

·fuel and water supply availability;

·our ability to achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital;

·regulatory and judicial decisions, developments and proceedings;

·new legislation or regulation, including those relating to environmental requirements, nuclear plant operations and potential deregulation of retail electric markets;

·our ability to meet renewable energy and energy efficiency mandates and recover related costs;

·risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

·competition in retail and wholesale power markets;

·the duration and severity of the economic decline in Arizona and current real estate market conditions;

·the cost of debt and equity capital and the ability to access capital markets when required;

·changes to our credit ratings;

·the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

·the liquidity of wholesale power markets and the use of derivative contracts in our business;

·potential shortfalls in insurance coverage;

·new accounting requirements or new interpretations of existing requirements;

·generation, transmission and distribution facility and system conditions and operating costs;

·the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our region;

·the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations;

·technological developments affecting the electric industry; and

·restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission (“ACC”) orders.

These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our 2012 Form 10-K and in Part II, Item 1A of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures.  Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

2

PART I — FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars and shares in thousands, except per share amounts)

	Three Months Ended June 30,
	2013			2012
OPERATING REVENUES	$	915,822		$	878,576
OPERATING EXPENSES
Fuel and purchased power	277,584			264,723
Operations and maintenance	229,300			216,236
Depreciation and amortization	106,292			100,606
Taxes other than income taxes	40,814			41,289
Other expenses	2,020			1,233
Total	656,010			624,087
OPERATING INCOME	259,812			254,489
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	6,265			5,175
Other income (Note 10)	469			177
Other expense (Note 10)	(2,234		)	(2,669		)
Total	4,500			2,683
INTEREST EXPENSE
Interest charges	51,307			53,000
Allowance for borrowed funds used during construction	(3,636		)	(3,447		)
Total	47,671			49,553
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	216,641			207,619
INCOME TAXES	77,043			76,689
INCOME FROM CONTINUING OPERATIONS	139,598			130,930
LOSS FROM DISCONTINUED OPERATIONS
Net of income tax benefit of $535	—			(819		)
NET INCOME	139,598			130,111
Less: Net income attributable to noncontrolling interests (Note 6)	8,391			7,766
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	131,207		$	122,345
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,962			109,491
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,932			110,359
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	1.19		$	1.12
Net income attributable to common shareholders — basic	1.19			1.12
Income from continuing operations attributable to common shareholders — diluted	1.18			1.12
Net income attributable to common shareholders — diluted	1.18			1.11
DIVIDENDS DECLARED PER SHARE	$	1.09		$	1.05
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	131,207		$	123,164
Discontinued operations, net of tax	—			(819		)
Net income attributable to common shareholders	$	131,207		$	122,345

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

3

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,
	2013			2012
NET INCOME	$	139,598		$	130,111
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $105 and $(1,781)	(160		)	2,728
Reclassification of net realized loss, net of tax benefit of $2,824 and $9,090	4,322			13,925
Pension and other postretirement benefits activity, net of tax benefit (expense) of $449 and $(526)	(688		)	806
Total other comprehensive income	3,474			17,459
COMPREHENSIVE INCOME	143,072			147,570
Less: Comprehensive income attributable to noncontrolling interests	8,391			7,766
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	134,681		$	139,804

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars and shares in thousands, except per share amounts)

	Six Months Ended June 30,
	2013			2012
OPERATING REVENUES	$	1,602,474		$	1,499,207
OPERATING EXPENSES
Fuel and purchased power	508,263			481,032
Operations and maintenance	452,550			426,899
Depreciation and amortization	210,022			200,715
Taxes other than income taxes	80,835			83,764
Other expenses	4,069			4,301
Total	1,255,739			1,196,711
OPERATING INCOME	346,735			302,496
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	13,129			9,931
Other income (Note 10)	1,227			937
Other expense (Note 10)	(5,986		)	(6,737		)
Total	8,370			4,131
INTEREST EXPENSE
Interest charges	100,785			109,967
Allowance for borrowed funds used during construction	(7,626		)	(6,598		)
Total	93,159			103,369
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	261,946			203,258
INCOME TAXES	89,512			72,044
INCOME FROM CONTINUING OPERATIONS	172,434			131,214
LOSS FROM DISCONTINUED OPERATIONS
Net of income tax benefit of $1,040	—			(1,584		)
NET INCOME	172,434			129,630
Less: Net income attributable to noncontrolling interests (Note 6)	16,783			15,542
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	155,651		$	114,088
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,898			109,395
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,843			110,183
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	1.42		$	1.06
Net income attributable to common shareholders — basic	1.42			1.04
Income from continuing operations attributable to common shareholders — diluted	1.40			1.05
Net income attributable to common shareholders — diluted	1.40			1.04
DIVIDENDS DECLARED PER SHARE	$	1.09		$	1.575
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	155,651		$	115,681
Discontinued operations, net of tax	—			(1,593		)
Net income attributable to common shareholders	$	155,651		$	114,088

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

5

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2013			2012
NET INCOME	$	172,434		$	129,630
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $67 and $14,770	(102		)	(22,624		)
Reclassification of net realized loss, net of tax benefit of $6,124 and $14,818	9,375			22,697
Pension and other postretirement benefits activity, net of tax (expense) of $(182) and $(1,157)	278			1,772
Total other comprehensive income	9,551			1,845
COMPREHENSIVE INCOME	181,985			131,475
Less: Comprehensive income attributable to noncontrolling interests	16,783			15,542
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	165,202		$	115,933

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

6

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	27,803		$	26,202
Customer and other receivables	345,581			277,225
Accrued unbilled revenues	163,608			94,845
Allowance for doubtful accounts	(2,821		)	(3,340		)
Materials and supplies (at average cost)	220,025			218,096
Fossil fuel (at average cost)	33,407			31,334
Deferred income taxes	105,146			152,191
Income tax receivable (Note 5)	2,317			2,423
Assets from risk management activities (Note 7)	22,575			25,699
Deferred fuel and purchased power regulatory asset (Note 3)	26,526			72,692
Other regulatory assets (Note 3)	79,405			71,257
Other current assets	42,717			37,102
Total current assets	1,066,289			1,005,726
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	31,918			35,891
Nuclear decommissioning trust (Note 13)	595,231			570,625
Other assets	64,304			62,694
Total investments and other assets	691,453			669,210
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,503,810			14,346,367
Accumulated depreciation and amortization	(5,022,729		)	(4,929,613		)
Net	9,481,081			9,416,754
Construction work in progress	545,231			565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	127,060			128,995
Intangible assets, net of accumulated amortization	162,715			162,150
Nuclear fuel, net of accumulated amortization	156,252			122,778
Total property, plant and equipment	10,472,339			10,396,393
DEFERRED DEBITS
Regulatory assets (Note 3)	1,120,366			1,099,900
Income tax receivable (Note 5)	71,274			70,389
Other	140,973			137,997
Total deferred debits	1,332,613			1,308,286
TOTAL ASSETS	$	13,562,694		$	13,379,615

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

7

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	287,368		$	221,312
Accrued taxes (Note 5)	129,865			124,939
Accrued interest	49,199			49,380
Common dividends payable	59,946			59,789
Short-term borrowings	30,100			92,175
Current maturities of long-term debt (Note 2)	599,131			122,828
Customer deposits	78,795			79,689
Liabilities from risk management activities (Note 7)	67,855			73,741
Regulatory liabilities (Note 3)	80,763			88,116
Other current liabilities	154,196			171,573
Total current liabilities	1,537,218			1,083,542
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
Long-term debt less current maturities	2,782,758			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	2,820,172			3,199,088
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,175,865			2,151,371
Regulatory liabilities (Note 3)	790,788			759,201
Liability for asset retirements	362,619			357,097
Liabilities for pension and other postretirement benefits (Note 4)	1,013,976			1,058,755
Deferred investment tax credit	119,979			99,819
Liabilities from risk management activities (Note 7)	85,474			85,264
Customer advances	108,335			109,359
Coal mine reclamation	115,145			118,860
Unrecognized tax benefits (Note 5)	72,629			71,135
Other	191,259			183,835
Total deferred credits and other	5,036,069			4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 8)
Common stock, no par value	2,486,871			2,466,923
Treasury stock	(10,117		)	(4,211		)
Total common stock	2,476,754			2,462,712
Retained earnings	1,659,868			1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(64,138		)	(64,416		)
Derivative instruments	(40,319		)	(49,592		)
Total accumulated other comprehensive loss	(104,457		)	(114,008		)
Total shareholders’ equity	4,032,165			3,972,806
Noncontrolling interests (Note 6)	137,070			129,483
Total equity	4,169,235			4,102,289
TOTAL LIABILITIES AND EQUITY	$	13,562,694		$	13,379,615

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

8

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	172,434		$	129,630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	249,482			239,743
Deferred fuel and purchased power	36,183			82,261
Deferred fuel and purchased power amortization	10,921			(54,388		)
Allowance for equity funds used during construction	(13,129		)	(9,931		)
Deferred income taxes	68,526			61,109
Deferred investment tax credit	20,159			5,033
Change in derivative instruments fair value	349			(2,618		)
Changes in current assets and liabilities:
Customer and other receivables	(79,408		)	(21,424		)
Accrued unbilled revenues	(68,763		)	(43,211		)
Materials, supplies and fossil fuel	(4,002		)	(21,012		)
Other current assets	(14,439		)	(9,407		)
Accounts payable	85,563			9,199
Accrued taxes and income tax receivable — net	5,032			19,775
Other current liabilities	(26,098		)	807
Change in margin and collateral accounts — assets	(1,111		)	124
Change in margin and collateral accounts — liabilities	14,600			69,602
Change in other long-term assets	(23,796		)	(1,692		)
Change in other long-term liabilities	21,753			5,035
Net cash flow provided by operating activities	454,256			458,635
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(376,601		)	(424,775		)
Contributions in aid of construction	21,236			25,800
Allowance for borrowed funds used during construction	(7,626		)	(6,598		)
Proceeds from nuclear decommissioning trust sales	253,996			211,138
Investment in nuclear decommissioning trust	(262,621		)	(219,762		)
Other	(262		)	(525		)
Net cash flow used for investing activities	(371,878		)	(414,722		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307			351,081
Repayment of long-term debt	(40,127		)	(421,451		)
Short-term borrowings and payments — net	(62,075		)	109,000
Dividends paid on common stock	(116,231		)	(111,297		)
Common stock equity issuance	9,751			8,869
Distributions to noncontrolling interests	(9,197		)	(2,630		)
Other	795			160
Net cash flow used for financing activities	(80,777		)	(66,268		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,601			(22,355		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	26,202			33,583
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	27,803		$	11,228

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

9

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 which has become more material this quarter (dollars in thousands):

Balance Sheets - December 31, 2012	As previously reported		Reclassifications			Amount reported after reclassifications
Deferred investment tax credit	$	—	$	99,819		$	99,819
Deferred credits — other	283,654		(99,819		)	183,835

Statement of Cash Flows for the Six Months Ended June 30, 2012	As previously reported		Reclassifications			Amount reported after reclassifications
Cash Flows from Operating Activities
Deferred income taxes	$	66,142	$	(5,033	)	$	61,109
Deferred investment tax credit	—		5,033			5,033

10

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):

	Six Months Ended June 30,
	2013			2012
Cash paid during the period for:
Income taxes, net of (refunds)	$	(9	)	$	(649	)
Interest, net of amounts capitalized	91,346			94,680
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	8,904		$	14,745
Dividends accrued but not paid	59,946			57,479

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 June 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 June 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 June 30, 2013 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.

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At June 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 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 June 30, 2013, APS had commercial paper borrowings of $30 million and no outstanding borrowings or outstanding letters of credit under these credit facilities.

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.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at June 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 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):

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	As of June 30, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,294		3,591		3,197		3,750
Total	$	3,419	$	3,716	$	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 June 30, 2013, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.1 billion, and total capitalization was approximately $7.4 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.

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.

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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.

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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.  A hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed

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energy, rather than acquiring and retiring renewable energy credits, began in June 2013 and is expected to conclude in September 2013.  The track and record approach would require monitoring the distributed energy systems that are connected to APS’s system, recording the amount of energy they produce, and reporting the energy production amounts to the ACC for informational purposes only.  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 to APS 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.

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 the Company’s obligations under its 2008 rate case settlement agreement approved by the ACC, including the remaining 50 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.

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 2013.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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):

	Six Months Ended June 30,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs — current period	(36		)	(82		)
Amounts (collected from) credited to customers	(10		)	54
Ending balance	$	27		$	—

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 and Transmission Cost Adjustor.  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.

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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 agreement 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 existing 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.  APS believes the costs associated with the termination of the existing agreement are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance.

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 commissioners voted to discuss this matter using a two-step process.  First, the ACC will solicit comments from interested parties on the pros and cons of retail electric deregulation in Arizona, including the potential effects on residential and small business customers.  The ACC opened a docket for this matter and set a procedural schedule whereby comments from interested parties were filed on July 15 and additional responses are due August 16, 2013.  The ACC plans to schedule an open meeting for discussion of these comments and a possible vote on whether to proceed to a second phase of consideration.  If the ACC votes to proceed to a second phase, they will then request the interested parties to propose structures and rules that would govern a future deregulated retail electric market for the ACC’s further consideration.  We cannot predict the outcome of these proceedings.

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Regulatory Assets and Liabilities

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

	Remaining
	Amortization	June 30, 2013				December 31, 2012
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)	$	—	$	766	$	—	$	780
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2043	4		97		4		92
Deferred fuel and purchased power — mark-to-market (Note 7)	2016	15		28		19		21
Transmission vegetation management	2016	9		18		9		23
Coal reclamation	2038	8		22		8		24
Palo Verde VIEs (Note 6)	2046	—		40		—		38
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2013	27		—		73		—
Retired power plant costs	2020	3		19		—		—
Tax expense of Medicare subsidy	2024	2		16		2		17
Loss on reacquired debt	2034	1		18		2		18
Income taxes — investment tax credit basis adjustment	2042	1		31		1		26
Pension and other postretirement benefits deferral	2015	8		8		8		13
Lost fixed cost recovery	2014	14		1		7		—
Transmission cost adjustor	2014	13		3		10		—
Other	Various	1		17		1		14
Total regulatory assets (d)		$	106	$	1,120	$	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.”

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

	Remaining
	Amortization	June 30, 2013				December 31, 2012
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	27	$	316	$	27	$	321
Asset retirement obligations	(a)	—		263		—		256
Renewable energy standard (b)	2014	28		16		43		—
Income taxes — change in rates	2042	—		68		—		66
Spent nuclear fuel	2047	6		38		10		36
Deferred gains on utility property	2019	2		11		2		12
Income taxes — deferred investment tax credit	2042	2		62		2		52
Demand side management	2014	16		—		4		—
Other	Various	—		17		—		16
Total regulatory liabilities		$	81	$	791	$	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.

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 as a regulatory asset for future recovery, pursuant to an ACC regulatory order.  We deferred pension and other postretirement benefit costs of approximately $5 million for the three months ended June 30, 2012, and approximately $14 million for the six months ended June 30, 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 June 30, 2013, and approximately $4 million for the six months ended June 30, 2013.  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):

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	Pension Benefits												Other Benefits
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost - benefits earned during the period	$	15		$	15		$	32		$	32		$	6		$	6		$	12		$	14
Interest cost on benefit obligation	28			30			56			60			10			11			20			23
Expected return on plan assets	(36		)	(35		)	(73		)	(71		)	(12		)	(11		)	(23		)	(23		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	10			12			20			22			3			4			6			10
Net periodic benefit cost	$	17		$	22		$	36		$	44		$	7		$	10		$	15		$	24
Portion of cost charged to expense	$	9		$	8		$	19		$	13		$	4		$	3		$	9		$	6

Contributions

We have contributed $87 million to our pension plan year to date 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 voluntary contributions totaling $140 million to the pension plan in 2013, and contributions up to approximately $175 million in each of 2014 and 2015.  The contributions to our other postretirement benefit plans for 2013, 2014 and 2015 are expected to be approximately $20 million each year.

5.Income Taxes

The $71 million long-term income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  Subsequent to June 30, 2013, IRS guidance was released which provided clarification regarding the timing of this cash receipt.  As a result of the release of this guidance, the $71 million income tax receivable will be reclassified to short-term for the quarter ended September 30, 2013.  Additionally, as a result of this IRS guidance, it is possible that uncertain tax positions could decrease by approximately $65-$75 million within the next 12 months.  This decrease would be substantially offset by an increase in deferred tax liabilities.

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009.  We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

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 is expected to delay 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.  As of

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June 30, 2013, approximately $39 million of the $78 million in federal general business tax credit carryforwards have been reclassified to long-term deferred income taxes as they are no longer expected to be realized within the next twelve months.

As of June 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.

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 six months ended June 30, 2013 of $8 million and $17 million, respectively, and for the three and six months ended June 30, 2012 of $8 million and $16 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 June 30, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

	June 30, 2013		December 31, 2012
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	127	$	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	137		129

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 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.

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 relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.

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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 June 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	7,668	gigawatt hours
Gas	129	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):

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		Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	Financial Statement Location	2013			2012			2013			2012
Gain (loss) recognized in OCI on derivative instruments (effective portion)	Other comprehensive income (loss) - derivative instruments	$	(265	)	$	4,509		$	(169	)	$	(37,394	)
Loss reclassified from accumulated other comprehensive income into income (effective portion realized) (a)	Fuel and purchased power (b)	(7,146		)	(23,015		)	(15,499		)	(37,515		)
Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)	Fuel and purchased power (b)	—			32			—			117

(a)During the three and six months ended June 30, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income (“AOCI”) to earnings related to discontinued cash flow hedges.  During the three and six months ended June 30, 2013,  we had no amounts 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 $37 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

		Three Months Ended June 30,					Six Months Ended June 30,
Commodity Contracts	Financial Statement Location	2013			2012		2013			2012
Net gain (loss) recognized in income	Operating revenues (a)	$	322		$	87	$	205		$	(239	)
Net gain (loss) recognized in income	Fuel and purchased power expense (a)	(27,758		)	26,042		(10,408		)	990
Total		$	(27,436	)	$	26,129	$	(10,203	)	$	751

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

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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 June 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.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2013:(dollars in thousands)	Gross Recognized Derivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			Amount Reported on Balance Sheet
Current Assets	$	32,642		$	(10,669	)	$	21,973		$	602		$	22,575
Investments and Other Assets	34,486			(2,568		)	31,918			—			31,918
Total Assets	67,128			(13,237		)	53,891			602			54,493
Current Liabilities	(82,710		)	34,318			(48,392		)	(19,463		)	(67,855		)
Deferred Credits and Other	(93,093		)	7,619			(85,474		)	—			(85,474		)
Total Liabilities	(175,803		)	41,937			(133,866		)	(19,463		)	(153,329		)
Total	$	(108,675	)	$	28,700		$	(79,975	)	$	(18,861	)	$	(98,836	)

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

(b)Includes cash collateral provided to counterparties of $28,700.

(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

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received from counterparties of $19,463, and cash margin provided to counterparties of $602.

As of December 31, 2012:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
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 86% of Pinnacle West’s $54 million of risk management assets as of June 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

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were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2013 (dollars in millions):

	June 30, 2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	176
Cash Collateral Posted	29
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	116

(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 $174 million if our debt credit ratings were to fall below investment grade.

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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,014,455		$	137,875		$	4,152,330		$	3,744,917		$	116,512		$	3,861,429
Net income	131,207			8,391			139,598			122,345			7,766			130,111
Other comprehensive income	3,474			—			3,474			17,459			—			17,459
Total comprehensive income	134,681			8,391			143,072			139,804			7,766			147,570
Issuance of capital stock	2,363			—			2,363			2,525			—			2,525
Reissuance of treasury stock — net	366			—			366			5,113			—			5,113
Other (primarily stock compensation)	185			—			185			631			—			631
Dividends on common stock	(119,885		)	—			(119,885		)	(114,955		)	—			(114,955		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

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	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
Net income	155,651			16,783			172,434			114,088			15,542			129,630
Other comprehensive income	9,551			—			9,551			1,845			—			1,845
Total comprehensive income	165,202			16,783			181,985			115,933			15,542			131,475
Issuance of capital stock	4,937			—			4,937			5,225			—			5,225
Reissuance (purchase) of treasury stock - net	(5,905		)	—			(5,905		)	3,359			—			3,359
Other (primarily stock compensation)	15,010			—			15,010			3,981			—			3,981
Dividends on common stock	(119,885		)	—			(119,885		)	(172,313		)	—			(172,313		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

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 June 30, 2013, APS had a regulatory liability of $44 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 $12.6 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 $12.2 billion of

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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 $118 million, subject to an annual limit of $18 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 $103 million, with an annual payment limitation of approximately $15 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

There have been no material changes outside the normal course of business in contractual obligations from the 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.

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The Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against over 40 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.  On February 21, 2013, certain of the defendants filed third-party complaints against additional parties, including APS.  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.

Climate Change Lawsuit

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law.  The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages.  In June 2008, the defendants filed motions to dismiss the action, which were granted.  The plaintiffs filed an appeal with the United States Court of Appeals for the Ninth Circuit in November 2009.

On September 21, 2012, a three-judge panel of the Ninth Circuit affirmed the district court’s dismissal of the Kivalina plaintiffs’ federal common law public nuisance action.  The court declined to address any other issue raised by the parties, including the plaintiffs’ state nuisance law claim.  On October 4, 2012, the plaintiffs filed a petition for rehearing by the entire Ninth Circuit, but on November 27, 2012, the court denied the plaintiffs’ petition.  On February 25, 2013, plaintiffs requested the United States Supreme Court to hear the case, but on May 20, 2013, the Court denied plaintiff’s petition for judicial review.  There is no right to appeal from this decision.

Southwest Power Outage

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

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 megawatts (“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

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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.

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 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

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up to approximately $158 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 $187 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 $124 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 “best available retrofit technology” (“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.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At June 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 December 31, 2015, and totaled approximately $34 million at June 30, 2013.  Additionally, APS has issued letters of credit to support

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collateral obligations under certain risk management arrangements including certain natural gas tolling contracts entered into with third parties.  At June 30, 2013, $60 million of such letters of credit were outstanding that will expire in 2013 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 June 30, 2013.

10.Other Income and Other Expense

The following table provides detail of other income and other expense for the three and six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	467		$	107		$	1,176		$	712
Miscellaneous	2			70			51			225
Total other income	$	469		$	177		$	1,227		$	937
Other expense:
Non-operating costs	$	(1,990	)	$	(2,389	)	$	(3,923	)	$	(4,239	)
Investment losses — net	(96		)	(58		)	(208		)	(112		)
Miscellaneous	(148		)	(222		)	(1,855		)	(2,386		)
Total other expense	$	(2,234	)	$	(2,669	)	$	(5,986	)	$	(6,737	)

11.Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and six months ended June 30, 2013 and 2012:

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	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	1.19	$	1.12		$	1.42	$	1.06
Loss from discontinued operations	—		—			—		(0.02		)
Earnings per share — basic	$	1.19	$	1.12		$	1.42	$	1.04
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	1.18	$	1.12		$	1.40	$	1.05
Loss from discontinued operations	—		(0.01		)	—		(0.01		)
Earnings per share — diluted	$	1.18	$	1.11		$	1.40	$	1.04

Performance shares and restricted stock units (which are contingently issuable) increased the weighted average common shares outstanding by approximately 970,000 shares and 868,000 shares for the three months ended June 30, 2013 and 2012, respectively, and by approximately 945,000 shares and 788,000 shares for the six months ended June 30, 2013 and 2012, respectively.

For the three and six months ended June 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.

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

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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

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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

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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 June 30, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at June 30, 2013
Assets
Cash equivalents	$	3	$	—		$	—		$	—		$	3
Risk management activities — derivative instruments:
Commodity Contracts	—		13			53			(11		)(b)	55
Nuclear decommissioning trust:
U.S. commingled equity funds	—		233			—			—			233
Fixed income securities:
U.S. Treasury	110		—			—			—			110
Cash and cash equivalent funds	1		10			—			(6		)(c)	5
Corporate debt	—		79			—			—			79
Mortgage-backed securities	—		83			—			—			83
Municipality bonds	—		71			—			—			71
Other	—		14			—			—			14
Subtotal nuclear decommissioning trust	111		490			—			(6		)	595
Total	$	114	$	503		$	53		$	(17	)	$	653
Liabilities
Risk management activities — derivative instruments:	$	—	$	(70	)	$	(106	)	$	23	(b)	$	(153	)

(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.

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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 in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at December 31, 2012
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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 implied volatilities.  If electricity prices and electricity price implied 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 implied 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 implied 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 June 30, 2013 and December 31, 2012:

	June 30, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	53	$	76	Discounted cash flows	Electricity forward price (per MWh)	$24.77-$70.12	$	42.10
Option Contracts			27		Option model	Electricity forward price (per MWh)	$39.64-$84.73	$	58.26
						Implied electricity price volatilities	17%-98%	46		%
						Implied natural gas price volatilities	16%-32%	21		%
Natural Gas:
Forward Contracts (a)	—		3		Discounted cash flows	Natural gas forward price (per mmbtu)	$3.36-$3.36	$	3.36
Total	$	53	$	106

(a)Includes swaps and physical and financial contracts.

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	December 31, 2012 Fair Value (millions)				Valuation	Significant		Weighted-
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	$	4.20
						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 six months ended June 30, 2013 and 2012 (dollars in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2013			2012			2013			2012
Net derivative balance at beginning of period	$	(53	)	$	(58	)	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			1			—			2
Included in OCI	—			3			—			(2		)
Deferred as a regulatory asset or liability	(4		)	12			(5		)	7
Settlements	4			(1		)	2			—
Transfers into Level 3 from Level 2	—			—			(1		)	2
Transfers from Level 3 into Level 2	—			(2		)	(1		)	(3		)
Net derivative balance at end of period	$	(53	)	$	(45	)	$	(53	)	$	(45	)
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

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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.

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 June 30, 2013 and December 31, 2012 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2013
Equity securities	$	233		$	93	$	—
Fixed income securities	368			14		(6		)
Net payables (a)	(6		)	—		—
Total	$	595		$	107	$	(6	)

(a)Net payables relate to pending securities sales and purchases.

	Fair Value			Total Unrealized Gains		Total Unrealized 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.

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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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized gains	$	1		$	2		$	3		$	4
Realized losses	(1		)	(1		)	(2		)	(2		)
Proceeds from the sale of securities (a)	119			119			254			211

(a)Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2013 is as follows (dollars in millions):

	Fair Value
Less than one year	$		11
1 year - 5 years	106
5 years - 10 years	100
Greater than 10 years	151
Total	$	368

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.

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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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,481	)	$	(63,450	)	$	(107,931	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
Other comprehensive loss before reclassifications	(160		)	(1,635		)	(1,795		)	(102		)	(1,635		)	(1,737		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	947		(b)	5,269			9,375		(a)	1,913		(b)	11,288
Net current period other comprehensive income (loss)	4,162			(688		)	3,474			9,273			278			9,551
Ending balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(40,319	)	$	(64,138	)	$	(104,457	)

(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.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,
	2013			2012
ELECTRIC OPERATING REVENUES	$	915,065		$	877,587
OPERATING EXPENSES
Fuel and purchased power	277,584			264,723
Operations and maintenance	224,950			213,746
Depreciation and amortization	106,268			100,583
Income taxes	81,952			80,696
Taxes other than income taxes	40,583			41,018
Total	731,337			700,766
OPERATING INCOME	183,728			176,821
OTHER INCOME (DEDUCTIONS)
Income taxes	3,100			2,030
Allowance for equity funds used during construction	6,265			5,175
Other income (Note S-2)	948			1,018
Other expense (Note S-2)	(4,844		)	(3,993		)
Total	5,469			4,230
INTEREST EXPENSE
Interest on long-term debt	47,543			48,838
Interest on short-term borrowings	1,968			1,914
Debt discount, premium and expense	982			1,052
Allowance for borrowed funds used during construction	(3,636		)	(3,447		)
Total	46,857			48,357
NET INCOME	142,340			132,694
Less: Net income attributable to noncontrolling interests (Note 6)	8,391			7,766
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	133,949		$	124,928

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

45

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,
	2013			2012
NET INCOME	$	142,340		$	132,694
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $105 and $(1,781)	(160		)	2,727
Reclassification of net realized loss, net of tax benefit of $2,824 and $9,092	4,322			13,922
Pension and other postretirement benefits activity, net of tax benefit (expense) of $399 and $(305)	(611		)	468
Total other comprehensive income	3,551			17,117
COMPREHENSIVE INCOME	145,891			149,811
Less: Comprehensive income attributable to noncontrolling interests	8,391			7,766
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	137,500		$	142,045

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

46

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2013			2012
ELECTRIC OPERATING REVENUES	$	1,600,892		$	1,497,835
OPERATING EXPENSES
Fuel and purchased power	508,263			481,032
Operations and maintenance	445,702			422,193
Depreciation and amortization	209,974			200,668
Income taxes	98,012			79,882
Taxes other than income taxes	80,351			83,244
Total	1,342,302			1,267,019
OPERATING INCOME	258,590			230,816
OTHER INCOME (DEDUCTIONS)
Income taxes	5,432			3,736
Allowance for equity funds used during construction	13,129			9,931
Other income (Note S-2)	2,291			1,528
Other expense (Note S-2)	(11,140		)	(8,617		)
Total	9,712			6,578
INTEREST EXPENSE
Interest on long-term debt	93,764			101,575
Interest on short-term borrowings	3,397			3,949
Debt discount, premium and expense	1,993			2,112
Allowance for borrowed funds used during construction	(7,626		)	(6,598		)
Total	91,528			101,038
NET INCOME	176,774			136,356
Less: Net income attributable to noncontrolling interests (Note 6)	16,783			15,533
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	159,991		$	120,823

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

47

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2013			2012
NET INCOME	$	176,774		$	136,356
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $67 and $14,773	(102		)	(22,621		)
Reclassification of net realized loss, net of tax benefit of $6,124 and $14,820	9,374			22,694
Pension and other postretirement benefits activity, net of tax (expense) of $(177) and $(841)	271			1,289
Total other comprehensive income	9,543			1,362
COMPREHENSIVE INCOME	186,317			137,718
Less: Comprehensive income attributable to noncontrolling interests	16,783			15,533
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	169,534		$	122,185

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

48

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30,			December 31,
	2013			2012
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	14,499,944		$	14,342,501
Accumulated depreciation and amortization	(5,019,059		)	(4,925,990		)
Net	9,480,885			9,416,511
Construction work in progress	545,231			565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	127,060			128,995
Intangible assets, net of accumulated amortization	162,560			161,995
Nuclear fuel, net of accumulated amortization	156,252			122,778
Total property, plant and equipment	10,471,988			10,395,995
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	595,231			570,625
Assets from risk management activities (Note 7)	31,918			35,891
Other assets	31,912			31,650
Total investments and other assets	659,061			638,166
CURRENT ASSETS
Cash and cash equivalents	5,956			3,499
Customer and other receivables	344,617			274,815
Accrued unbilled revenues	163,608			94,845
Allowance for doubtful accounts	(2,821		)	(3,340		)
Materials and supplies (at average cost)	220,025			218,096
Fossil fuel (at average cost)	33,407			31,334
Deferred fuel and purchased power regulatory asset (Note 3)	26,526			72,692
Other regulatory assets (Note 3)	79,405			71,257
Deferred income taxes	86,219			74,420
Assets from risk management activities (Note 7)	22,575			25,699
Other current assets	42,320			37,666
Total current assets	1,021,837			900,983
DEFERRED DEBITS
Regulatory assets (Note 3)	1,120,366			1,099,900
Unamortized debt issue costs	22,718			22,492
Income tax receivable (Note 5)	71,669			70,784
Other	117,123			114,222
Total deferred debits	1,331,876			1,307,398
TOTAL ASSETS	$	13,484,762		$	13,242,542

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

49

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30,			December 31,
	2013			2012
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,664,420			1,624,237
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(39,232		)	(39,503		)
Derivative instruments	(40,320		)	(49,592		)
Total shareholder equity	4,142,726			4,093,000
Noncontrolling interests (Note 6)	137,070			129,483
Total equity (Note S-1)	4,279,796			4,222,483
Long-term debt less current maturities (Note 2)	2,657,758			3,035,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414			38,869
Total capitalization	6,974,968			7,296,571
CURRENT LIABILITIES
Short-term borrowings	30,100			92,175
Current maturities of long-term debt (Note 2)	599,131			122,828
Accounts payable	282,408			215,577
Accrued taxes (Note 5)	129,003			116,700
Accrued interest	48,993			49,135
Common dividends payable	59,900			59,800
Customer deposits	78,795			79,689
Liabilities from risk management activities (Note 7)	67,855			73,741
Regulatory liabilities (Note 3)	80,763			88,116
Other current liabilities	125,501			145,326
Total current liabilities	1,502,449			1,043,087
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,215,730			2,133,976
Regulatory liabilities (Note 3)	790,788			759,201
Liability for asset retirements	362,619			357,097
Liabilities for pension and other postretirement benefits (Note 4)	974,877			1,017,556
Deferred investment tax credit	119,979			99,819
Liabilities from risk management activities (Note 7)	85,474			85,264
Customer advances	108,335			109,359
Coal mine reclamation	115,145			118,860
Unrecognized tax benefits (Note 5)	72,423			70,932
Other	161,975			150,820
Total deferred credits and other	5,007,345			4,902,884
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	13,484,762		$	13,242,542

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

50

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	176,774		$	136,356
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	249,434			239,696
Deferred fuel and purchased power	36,183			82,261
Deferred fuel and purchased power amortization	10,921			(54,388		)
Allowance for equity funds used during construction	(13,129		)	(9,931		)
Deferred income taxes	66,947			64,639
Deferred investment tax credit	20,159			5,033
Change in derivative instruments fair value	349			(2,618		)
Changes in current assets and liabilities:
Customer and other receivables	(80,854		)	(23,015		)
Accrued unbilled revenues	(68,763		)	(43,211		)
Materials, supplies and fossil fuel	(4,002		)	(21,012		)
Other current assets	(14,067		)	(9,797		)
Accounts payable	86,338			9,406
Accrued taxes and income taxes receivable — net	12,892			23,759
Other current liabilities	(28,506		)	(3,095		)
Change in margin and collateral accounts — assets	(1,111		)	124
Change in margin and collateral accounts — liabilities	14,600			69,602
Change in other long-term assets	(21,658		)	(2,456		)
Change in other long-term liabilities	26,628			5,180
Net cash flow provided by operating activities	469,135			466,533
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(376,601		)	(424,775		)
Contributions in aid of construction	21,236			25,800
Allowance for borrowed funds used during construction	(7,626		)	(6,598		)
Proceeds from nuclear decommissioning trust sales	253,996			211,138
Investment in nuclear decommissioning trust	(262,621		)	(219,762		)
Other	(270		)	(525		)
Net cash flow used for investing activities	(371,886		)	(414,722		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307			351,081
Short-term borrowings — net	(62,075		)	109,000
Repayment of long-term debt	(40,127		)	(421,451		)
Dividends paid on common stock	(119,700		)	(104,900		)
Noncontrolling interests	(9,197		)	(2,630		)
Net cash flow used for financing activities	(94,792		)	(68,900		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2,457			(17,089		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,499			19,873
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5,956		$	2,784
Supplemental disclosure of cash flow information
Cash paid during the period for:
Interest, net of amounts capitalized	$	89,676		$	92,473
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	8,904		$	14,745

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

51

Certain notes to APS’s Condensed Consolidated Financial Statements are combined with the Notes to Pinnacle West’s Condensed Consolidated Financial Statements.  Listed below are the Condensed Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS’s Condensed Consolidated Financial Statements.  In addition, listed below are the Supplemental Notes that are required disclosures for APS and should be read in conjunction with Pinnacle West’s Condensed Consolidated Notes.

	Condensed Consolidated Note Reference	APS’s Supplemental Note Reference
Consolidation and Nature of Operations	Note 1	—
Long-Term Debt and Liquidity Matters	Note 2	—
Regulatory Matters	Note 3	—
Retirement Plans and Other Benefits	Note 4	—
Income Taxes	Note 5	—
Palo Verde Sale Leaseback Variable Interest Entities	Note 6	—
Derivative Accounting	Note 7	—
Changes in Equity	Note 8	Note S-1
Commitments and Contingencies	Note 9	—
Other Income and Other Expense	Note 10	Note S-2
Earnings Per Share	Note 11	—
Fair Value Measurements	Note 12	—
Nuclear Decommissioning Trusts	Note 13	—
New Accounting Standards	Note 14	—
Changes in Accumulated Other Comprehensive Income	Note 15	Note S-3

52

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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,125,032		$	137,875		$	4,262,907		$	3,865,748		$	116,166		$	3,981,914
Net income	133,949			8,391			142,340			124,928			7,766			132,694
OCI	3,551			—			3,551			17,117			—			17,117
Total comprehensive income	137,500			8,391			145,891			142,045			7,766			149,811
Dividends on common stock	(119,800		)	—			(119,800		)	(105,000		)	—			(105,000		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,630		)	(2,630		)
Other	(6		)	—			(6		)	(2		)	—			(2		)
Ending balance, June 30	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, January 1	$	4,093,000		$	129,483		$	4,222,483		$	3,943,007		$	108,399		$	4,051,406
Net income	159,991			16,783			176,774			120,823			15,533			136,356
OCI	9,543			—			9,543			1,362			—			1,362
Total comprehensive income	169,534			16,783			186,317			122,185			15,533			137,718
Dividends on common stock	(119,800		)	—			(119,800		)	(162,400		)	—			(162,400		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,630		)	(2,630		)
Other	(8		)	—			(8		)	(1		)	—			(1		)
Ending balance, June 30	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093

53

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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	403		$	77		$	1,059		$	184
Miscellaneous	545			941			1,232			1,344
Total other income	$	948		$	1,018		$	2,291		$	1,528
Other expense:
Non-operating costs (a)	$	(2,285	)	$	(2,941	)	$	(4,605	)	$	(4,682	)
Asset dispositions	(1,397		)	(195		)	(2,661		)	(418		)
Miscellaneous	(1,162		)	(857		)	(3,874		)	(3,517		)
Total other expense	$	(4,844	)	$	(3,993	)	$	(11,140	)	$	(8,617	)

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

54

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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,482	)	$	(38,621	)	$	(83,103	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
Other comprehensive loss before reclassifications	(160		)	(1,630		)	(1,790		)	(102		)	(1,630		)	(1,732		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	1,019		(b)	5,341			9,374		(a)	1,901		(b)	11,275
Net current period other comprehensive income (loss)	4,162			(611		)	3,551			9,272			271			9,543
Ending balance	$	(40,320	)	$	(39,232	)	$	(79,552	)	$	(40,320	)	$	(39,232	)	$	(79,552	)

(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.

55

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report.  For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Part 1, Item 1A of the 2012 Form 10-K.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS.  APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

Nuclear.  APS operates and is a joint owner of Palo Verde.  The March 2011 earthquake and tsunamis in Japan and the resulting accident at Japan’s Fukushima Daiichi nuclear power station had a significant impact on nuclear power operators worldwide.  In the aftermath of the accident, the NRC conducted an independent assessment to consider actions to ensure that its regulations reflect lessons learned from the Fukushima events.

Although the NRC has repeatedly affirmed its position that continued operation of U.S. commercial nuclear power plants does not impose an immediate risk to the public health and safety, the NRC has proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans.  APS management continues to work closely with the NRC and others in the nuclear industry to ensure that the enhancements are implemented in an organized, sequential and structured way consistent with their safety benefit and significance of the issue being addressed.

Coal and Related Environmental Matters and Transactions.  APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants.  APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning greenhouse gas emissions.  Concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants.  APS is closely monitoring its long-range capital management plans, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to fund any such equipment upgrades.

56

Four Corners

Asset Purchase Agreement Terms and Approvals.   SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant.  On November 8, 2010, APS and SCE entered into an asset purchase agreement (“Asset Purchase Agreement”), providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners.  The purchase price is $294 million, subject to certain adjustments.  The Asset Purchase Agreement provides that the purchase price will be reduced by $7.5 million for each month between October 1, 2012 and the closing date.  Completion of the purchase by APS is subject to the receipt of approvals by the ACC, the California Public Utilities Commission (“CPUC”) and the FERC.  On March 29, 2012, the CPUC issued an order approving the sale.  On April 18, 2012, the ACC voted to allow APS to move forward with the purchase.  The ACC reserved the right to review the prudence of the transaction for cost recovery purposes in a future proceeding if the purchase closes.  The ACC also authorized an accounting deferral of certain costs associated with the purchase until any such cost recovery proceeding concludes.  The FERC application seeking authorization for the transaction was approved on November 27, 2012.  The principal remaining condition to closing stated in the Asset Purchase Agreement is the negotiation and execution of a new coal supply contract on terms reasonably acceptable to APS.

Pursuant to the Asset Purchase Agreement, either APS or SCE has a right to terminate the Agreement because the closing conditions were not satisfied by December 31, 2012, unless the party seeking to terminate is then in breach of the Agreement.

Coal Supplier Ownership Transfer.  On December 19, 2012, BHP Billiton New Mexico Coal, Inc. (“BHP Billiton”), the parent company of BHP Navajo Coal Company (“BNCC”), the coal supplier and operator of the mine that serves Four Corners, announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which full ownership of BNCC would be sold to the Navajo Nation.  BHP Billiton would be retained by BNCC under contract as the mine manager and operator until July 2016.  Key terms of the new coal supply contract are being finalized by the Navajo Nation and APS and the other Four Corners co-owners.  These negotiations, and the related transaction whereby ownership of BNCC would be transferred to the Navajo Nation, are proceeding.  On April 29, 2013, the Navajo Nation Tribal Council approved the creation of a new commercial enterprise with sufficient power and authority to execute the transaction with BHP Billiton.

Examination of Deregulated Retail Electric Market.  As discussed in Note 3, on May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC opened a docket for this matter and set a procedural schedule whereby comments from interested parties on the pros and cons of retail electric deregulation were filed on July 15 and additional responses are due August 16, 2013. The ACC stated that after it has had an opportunity to review the written comments, it plans to convene an open meeting to discuss the issues and information filed in the docket.

In light of this development, APS currently expects that it will not be in a position to close the Four Corners purchase transaction with SCE until the ACC’s intentions with regard to pursuing deregulation in Arizona become clearer.  While the process set by the ACC to consider this issue proceeds, APS intends to take action to maintain all necessary regulatory and other approvals required on its behalf to complete the transaction.

57

Pollution Control Investments.  As disclosed in our 2012 Form 10-K, EPA, in its final regional haze rule for Four Corners, set a date of July 1, 2013 for the Four Corners’ owners to elect one of two emissions alternatives to apply to Four Corners.  Either alternative would involve substantial investment by the owners in additional post-combustion pollution controls, and accordingly contemplates the continued operation of Four Corners for a substantial period of time.  In light of the docket opened by the ACC concerning deregulation, APS and EPA discussed a potential extension of the July 1 deadline.  On June 25, 2013, EPA issued a proposed rule that would extend the date by which the Four Corners participants must notify EPA of their chosen BART compliance strategy from July 1 to December 31, 2013.

Lease Extension.  APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation which extends the Four Corners leasehold interest from 2016 to 2041.  The Navajo Nation approved these amendments in March 2011.  The effectiveness of the amendments also requires the approval of the United States Department of the Interior (“DOI”), as does a related federal rights-of-way grant which the Four Corners participants will pursue.  A federal environmental review is underway as part of the DOI review process.

Shut-down of Units 1, 2 and 3.  APS has announced that, if APS’s purchase of SCE’s interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2 and 3 at the plant.  APS owns 100% of Units 1-3.  These events will change the plant’s overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791 MW to 970 MW.  When the ACC approved APS moving forward with the purchase of Units 4 and 5, it also approved the recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3.  The Settlement Agreement in APS’s most recent retail rate case allows APS to seek a rate adjustment to reflect the Four Corners transaction should the transaction close (see Note 3).

APS cannot predict whether the closing of its planned purchase of SCE’s interest in Four Corners will occur, or the effect that the ACC’s re-examination of a possible deregulated retail electric market in Arizona may have on the future operation of the plant.

Transmission and Delivery.  APS is working closely with regulators to identify and plan for transmission needs that continue to support system reliability, access to markets and renewable energy development.  The capital expenditures table presented in the “Liquidity and Capital Resources” section below includes new transmission projects through 2015, along with other transmission costs for upgrades and replacements.  APS is also working to establish and expand smart grid technologies throughout its service territory designed to provide long-term benefits both to APS and its customers.  APS is strategically deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations, as well as the number of customers that experience outages, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

Renewable Energy.  The ACC approved the RES in 2006.  The renewable energy requirement is 4% of retail electric sales in 2013 and increases annually until it reaches 15% in 2025.  In the settlement agreement related to the 2008 retail rate case, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 1,700 gigawatt hours (“GWh”) of new renewable resources to be in service by year-end 2015, in addition to its 2008 renewable resource commitments.  Taken together, APS’s commitment is currently estimated to be approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of

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5% for that year.  We expect renewable energy, including rooftop solar, to meet approximately 8% of our retail energy sales for 2013.  A component of the RES targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 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.  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, began in June 2013 and is expected to conclude in September 2013.  The track and record approach would require monitoring the distributed energy systems that are connected to APS’s system, recording the amount of energy they produce, and reporting the energy production amounts to the ACC for informational purposes only.  Finally, the ACC authorized an APS-led multi-session technical conference to consider APS’s net metering policy and the costs 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 to APS 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.

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 the Company’s obligations under its 2008 rate case settlement agreement approved by the ACC, including the remaining 50 MW of AZ Sun.

APS has a diverse portfolio of existing and planned renewable resources totaling 1,135 MW, including solar, wind, geothermal, biomass and biogas.  Of this portfolio, 714 MW are currently in operation and 421 MW are under contract for development or are under construction.  The following table summarizes APS’s renewable energy sources in operation and under development as of August 2, 2013.

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	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar (a)	99	70
Purchased Power Agreements:
Solar	30	280
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	349	280
Total Distributed Energy: Solar (b)	266	71
Total Renewable Portfolio	714	421

(a)Through the ACC-approved AZ Sun Program, APS has executed contracts for the development of 150 MW of new solar generation, representing an investment commitment of approximately $611 million.

(b)Distributed generation is produced in DC and is converted to AC for reporting purposes.

Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.

Demand Side Management.  In recent years, Arizona regulators have placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy.  In December 2009, the ACC initiated an Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020.  The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives.  This ambitious standard became effective on January 1, 2011.  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 2013.

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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.

Rate Matters.  APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health.  APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC.  On June 1, 2011, APS filed a rate case with the ACC.  APS and other parties to the retail rate case subsequently entered into a Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case.  See Note 3 for details regarding the Settlement Agreement terms and for information on APS’s FERC rates.

APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its demand side management and renewable energy efforts and customer programs.  These mechanisms are described more fully in Note 3.

As part of APS’s proposed acquisition of SCE’s 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 agreement 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 existing 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.  APS believes the costs associated with the termination of the existing agreement are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance.

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona (see Note 3).

Financial Strength and Flexibility.  Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company.  Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Other Subsidiaries.  The operations of El Dorado are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.  In February 2012, our other first-tier subsidiary, SunCor, filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  On March 25, 2013, the bankruptcy plan submitted to the court and agreed to by SunCor and its creditors (the “Joint  Plan”) became effective.  The Joint Plan provides for the full release of Pinnacle West and its affiliates from any and all claims related to SunCor, SunCor’s subsidiaries, and their respective estates.

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Key Financial Drivers

In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below.  We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Electric Operating Revenues.  For the years 2010 through 2012, retail electric revenues comprised approximately 93% of our total electric operating revenues.  Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.  These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth.  Retail customer growth in APS’s service territory for the six-month period ended June 30, 2013 was 1.4% compared with the comparable prior-year period.  For the three years 2010 through 2012, APS’s customer growth averaged 0.7% per year.  We currently expect annual customer growth to average about 2% for 2013 through 2015 based on our assessment of modestly improving economic conditions, both nationally and in Arizona.  Retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, increased 0.8% for the six-month period ended June 30, 2013 compared with the prior-year period, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, offset by mildly improving economic conditions.  For the three years 2010 through 2012, APS experienced annual declines in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kilowatt-hours will increase on average by less than one percent during 2013 through 2015, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  A failure of the Arizona economy to continue to improve could further impact these estimates.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes.  Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.

Weather.  In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data.  Historically, extreme weather variations have resulted in annual variations in net income in excess of $20 million.  However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

Fuel and Purchased Power Costs.  Fuel and purchased power costs included on our Condensed Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in

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our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses.  Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.  In the settlement agreement related to the 2008 retail rate case, APS committed to operational expense reductions from 2010 through 2014, and received approval to defer certain pension and other postretirement benefit cost increases incurred in 2011 and 2012, which totaled $25 million, as a regulatory asset, until the most recent general retail rate case decision became effective on July 1, 2012.  In July 2012, we began amortizing the regulatory asset over a 36-month period.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates.  See “Capital Expenditures” below for information regarding the planned additions to our facilities.

Property Taxes.  Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates.  The average property tax rate in Arizona for APS, which owns essentially all of our property, was 9.6% of the assessed value for 2012 and 9.0% for 2011.  We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities.  (See Note 3 for property tax deferrals contained in the Settlement Agreement).

Income Taxes.  Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC.  In addition, income taxes may also be affected by the settlement of issues with taxing authorities.

Interest Expense.  Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 2).  The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow.  An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction.  We stop accruing AFUDC on a project when it is placed in commercial operation.

RESULTS OF OPERATIONS

Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution.

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Operating Results

Three-month period ended June 30, 2013 compared with three-month period ended June 30, 2012  Our consolidated net income attributable to common shareholders for the three months ended June 30, 2013 was $131 million, compared with net income of $122 million for the prior-year period.  The results reflect an increase of approximately $8 million for the regulated electricity segment primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3) and higher retail transmission revenues.  These positive factors were partially offset by higher fuel and purchased power costs, net of related deferrals; the effects of weather; higher operations and maintenance expenses; and higher depreciation and amortization expenses.

The following table presents net income attributable to common shareholders by business segment compared with the prior-year period:

	Three Months Ended  June 30,
	2013			2012			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	637		$	613		$	24
Operations and maintenance	(229		)	(216		)	(13		)
Depreciation and amortization	(106		)	(101		)	(5		)
Taxes other than income taxes	(41		)	(41		)	—
Other income (expenses), net	3			3			—
Interest charges, net of allowance for borrowed funds used during construction	(48		)	(50		)	2
Income taxes	(77		)	(77		)	—
Less income related to noncontrolling interests (Note 6)	(8		)	(8		)	—
Regulated electricity segment net income	131			123			8
Loss from Discontinued Operations Attributable to Common Shareholders (a)	—			(1		)	1
Net Income Attributable to Common Shareholders	$	131		$	122		$	9

(a)Includes activities related to SunCor.

Operating revenues less fuel and purchased power expenses  Regulated electricity segment operating revenues less fuel and purchased power expenses were $24 million higher for the three months ended June 30, 2013 compared with the prior-year period.  The following table summarizes the major components of this change:

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	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Impacts of retail regulatory settlement effective July 1, 2012	$	34		$	2		$	32
Higher retail transmission revenues	10			—			10
Higher demand-side management, renewable energy and similar regulatory surcharges	9			3			6
Effects of weather	(12		)	(3		)	(9		)
Higher fuel and purchased power costs, net of related deferrals and off-system sales	1			14			(13		)
Miscellaneous items, net	(5		)	(3		)	(2		)
Total	$	37		$	13		$	24

Operations and maintenance  Operations and maintenance expenses increased $13 million for the three months ended June 30, 2013 compared with the prior-year period primarily because of:

·An increase of $7 million related to amortization of certain pension and other postretirement benefit costs in 2013 compared with regulatory deferral of such costs in 2012;

·An increase of $5 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues; and

·An increase of $1 million related to other miscellaneous factors.

Depreciation and amortization  Depreciation and amortization expenses were $5 million higher for the three months ended June 30, 2013 compared with the prior-year period primarily because of increased plant in service.

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Six-month period ended June 30, 2013 compared with six-month period ended June 30, 2012  Our consolidated net income attributable to common shareholders for the six months ended June 30, 2013 was $156 million, compared with net income of $114 million for the prior-year period.  The results reflect an increase of approximately $39 million for the regulated electricity segment primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3); higher retail transmission revenues; higher retail sales due to customer growth and changes in customer usage patterns and related pricing; and lower net interest charges due to lower debt balances and lower interest rates in the current-year period.  These positive factors were partially offset by higher operations and maintenance expenses; higher fuel and purchased power costs, net of related deferrals; and higher depreciation and amortization expenses.

The following table presents net income attributable to common shareholders by business segment compared with the prior-year period:

	Six Months Ended June 30,
	2013			2012			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,093		$	1,017		$	76
Operations and maintenance	(453		)	(427		)	(26		)
Depreciation and amortization	(210		)	(201		)	(9		)
Taxes other than income taxes	(81		)	(84		)	3
Other income (expenses), net	7			4			3
Interest charges, net of allowance for borrowed funds used during construction	(93		)	(103		)	10
Income taxes	(90		)	(73		)	(17		)
Less income related to noncontrolling interests (Note 6)	(17		)	(16		)	(1		)
Regulated electricity segment net income	156			117			39
All other	—			(1		)	1
Income from Continuing Operations Attributable to Common Shareholders	156			116			40
Loss from Discontinued Operations Attributable to Common Shareholders (a)	—			(2		)	2
Net Income Attributable to Common Shareholders	$	156		$	114		$	42

(a)Includes activities related to SunCor.

Operating revenues less fuel and purchased power expenses  Regulated electricity segment operating revenues less fuel and purchased power expenses were $76 million higher for the six months

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ended June 30, 2013 compared with the prior-year period.  The following table summarizes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Impacts of retail regulatory settlement effective July 1, 2012	$	59		$	3		$	56
Higher retail transmission revenues	21			—			21
Higher demand-side management, renewable energy and similar regulatory surcharges	14			4			10
Higher retail sales due to customer growth and changes in customer usage patterns and related pricing	13			3			10
Effects of weather	7			4			3
Higher fuel and purchased power costs, net of related deferrals and off-system sales	(4		)	17			(21		)
Miscellaneous items, net	(7		)	(4		)	(3		)
Total	$	103		$	27		$	76

Operations and maintenance  Operations and maintenance expenses increased $26 million for the six months ended June 30, 2013 compared with the prior-year period primarily because of:

·An increase of $18 million related to amortization of certain pension and other postretirement benefit costs in 2013 compared with regulatory deferral of such costs in 2012;

·An increase of $7 million in information technology costs;

·An increase of $4 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues; and

·A decrease of $3 million related to other miscellaneous factors.

Depreciation and amortization  Depreciation and amortization expenses were $9 million higher for the six months ended June 30, 2013 compared with the prior-year period primarily because of increased plant in service.

Interest charges, net of allowance for borrowed funds used during construction  Interest charges, net of allowance for borrowed funds used during construction, decreased $10 million for the

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six months ended June 30, 2013 compared with the prior-year period primarily because of lower debt balances and lower interest rates in the current period.

Income taxes  Income taxes were $17 million higher for the six months ended June 30, 2013 compared with the prior-year period primarily due to higher pretax income in the current period.

LIQUIDITY AND CAPITAL RESOURCES

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness.  The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.

Our primary sources of cash are dividends from APS and external debt and equity issuances.  An ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At June 30, 2013, APS’s common equity ratio, as defined, was 56%.  Its total shareholder equity was approximately $4.1 billion, and total capitalization was approximately $7.4 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same.  This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt.  APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.

Many of APS’s current capital expenditure projects qualify for bonus depreciation.  The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions extending the eligibility for 50% bonus depreciation to qualified property placed in service in 2013.  As a result of this provision, and the previously enacted bonus depreciation provisions provided for in the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, total cash tax benefits of up to $400-$500 million are expected to be generated for APS through accelerated depreciation.  The cash generated is an acceleration of the tax benefits that APS would have otherwise received over 20 years.  It is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a majority of the benefit realized as of December 31, 2012.

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the six months ended June 30, 2013 and 2012 (dollars in millions):

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Pinnacle West Consolidated

	Six Months Ended June 30,						Net
	2013			2012			Change
Net cash flow provided by operating activities	$	454		$	459		$	(5	)
Net cash flow used for investing activities	(372		)	(415		)	43
Net cash flow used for financing activities	(80		)	(66		)	(14		)
Net increase (decrease) in cash and cash equivalents	$	2		$	(22	)	$	24

Arizona Public Service Company

	Six Months Ended June 30,						Net
	2013			2012			Change
Net cash flow provided by operating activities	$	469		$	467		$	2
Net cash flow used for investing activities	(372		)	(415		)	43
Net cash flow used for financing activities	(95		)	(69		)	(26		)
Net increase (decrease) in cash and cash equivalents	$	2		$	(17	)	$	19

Operating Cash Flows

Six-month period ended June 30, 2013 compared with six-month period ended June 30, 2012  Pinnacle West’s consolidated net cash provided by operating activities was $454 million in 2013, compared to $459 million in 2012, a decrease of $5 million in net cash provided.  The decrease is primarily related to $56 million of pension contributions in 2013 made in the six-month period ended June 30, 2013 (approximately $12 million of which is reflected in capital expenditures) and a $56 million change in cash collateral posted.  The decrease is partially offset by approximately $95 million of higher cash inflows due to the increase in pre-tax income primarily driven by higher authorized revenue requirements resulting from the retail regulatory settlement effective July 1, 2012 and other changes in working capital.

Other  Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries.  The requirements of the Employee Retirement Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan.  We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount.  The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations.  Under ERISA, the qualified pension plan was 105% funded as of January 1, 2012 and 107% funded as of January 1, 2013, reflecting scheduled contributions.  The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.  Contributions made or expected to be made in 2013 will be mostly allocated to the 2012 plan year.  Therefore, the funded status of the plan as of January 1, 2013 increased from 101%, previously reported, to 107% (including those 2012 plan year contributions).  Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We have contributed $87 million to our pension plan year to date 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 voluntary contributions totaling $140 million to the

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pension plan in 2013, and contributions up to approximately $175 million in each of 2014 and 2015.  The contributions to our other postretirement benefit plans for 2013, 2014 and 2015 are expected to be approximately $20 million per year.

The $71 million long-term income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  Subsequent to June 30, 2013, IRS guidance was released which provided clarification regarding the timing of this cash receipt.  As a result of the release of this guidance, the $71 million income tax receivable will be reclassified to short-term for the quarter ended September 30, 2013.  Additionally, as a result of this IRS guidance, it is possible that uncertain tax positions could decrease by approximately $65-$75 million within the next 12 months.  This decrease would be substantially offset by an increase in deferred tax liabilities.

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009.  We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

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.

Investing Cash Flows

Six-month period ended June 30, 2013 compared with six-month period ended June 30, 2012  Pinnacle West’s consolidated net cash used for investing activities was $372 million in 2013, compared to $415 million in 2012, a decrease of $43 million in net cash used.  The decrease in net cash used for investing activities is primarily due to a decrease of approximately $44 million in capital expenditures.

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Capital Expenditures  The following table summarizes the estimated capital expenditures for the years presented:

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2013		2014		2015
APS
Generation:
Nuclear Fuel	$	54	$	82	$	83
Renewables	192		39		—
Environmental	19		71		178
Four Corners Units 4 and 5	235		—		—
Other Generation	150		252		353
Distribution	249		307		310
Transmission	148		211		200
Other (a)	47		68		66
Total APS	$	1,094	$	1,030	$	1,190

(a)Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’s existing fossil and nuclear plants.  Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment.  For purposes of this table, we have assumed the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shutdown of Units 1-3, as discussed in the “Overview” section above.  As a result, we included the estimated $235 million purchase price under Generation and have not included environmental expenditures for Units 1-3.  We have not included estimated costs for Cholla’s compliance with EPA’s regional haze rule since we have challenged the rule judicially and are considering our future options with respect to that plant if the rule is upheld.  We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction.  Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

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Financing Cash Flows and Liquidity

Six-month period ended June 30, 2013 compared with six-month period ended June 30, 2012  Pinnacle West’s consolidated net cash used for financing activities was $81 million in 2013, compared to $66 million of net cash used in 2012, an increase of $15 million in net cash used.  The increase in net cash used for financing activities is primarily due to a $171 million net change in APS’s short-term borrowings and $215 million in lower issuances of long-term debt, largely offset by $381 million in lower repayments of long-term debt (see below).

Significant Financing Activities  On June 19, 2013, the Pinnacle West Board of Directors declared a quarterly dividend of $0.545 per share of common stock, payable on September 3, 2013, to shareholders of record on August 1, 2013.

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 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 June 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.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2013 and December 31, 2012.

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

At June 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 June 30, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding, and no commercial paper borrowings.

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.

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At June 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 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 June 30, 2013, APS had commercial paper borrowings of $30 million and no outstanding borrowings or outstanding letters of credit under these credit facilities.

See “Financial Assurances” in Note 9 for a discussion of APS’s separate outstanding letters of credit.

Other Financing Matters  See Note 3 for information regarding the PSA approved by the ACC.

See Note 3 for information regarding the settlement related to the 2008 retail rate case, which includes ACC authorization and requirements of equity infusions into APS of at least $700 million by December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in 2010).

See Note 7 for information related to the change in our margin accounts.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.  Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At June 30, 2013, the ratio was approximately 46% for Pinnacle West and 45% for APS.  Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt.  See further discussion of “cross-default” provisions below.

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

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

See Note 2 for further discussions of liquidity matters.

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Credit Ratings

The ratings of securities of Pinnacle West and APS as of July 29, 2013 are shown below.  We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt.  The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained.  There is no assurance that these ratings will continue for any given period of time.  The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant.  Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital.  Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts.  At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	Baa2	BBB+	BBB+
Commercial paper	P-3	A-2	F2
Outlook	Stable	Stable	Stable
APS
Corporate credit rating	Baa1	BBB+	BBB+
Senior unsecured	Baa1	BBB+	A-
Secured lease obligation bonds	Baa1	BBB+	A-
Commercial paper	P-2	A-2	F2
Outlook	Stable	Stable	Stable

Off-Balance Sheet Arrangements

See Note 6 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

Financial Assurances

See “Financial Assurances” in Note 9 for a discussion of APS’s outstanding letters of credit.  Pinnacle West has also issued parental guarantees and surety bonds for APS, which were not material at June 30, 2013.

Contractual Obligations

There have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2012 Form 10-K.

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CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period.  Some of those judgments can be subjective and complex, and actual results could differ from those estimates.  There have been no changes to our critical accounting policies since our 2012 Form 10-K.  See “Critical Accounting Policies” in Item 7 of the 2012 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

During 2013, we adopted new accounting guidance relating to balance sheet offsetting disclosures, and disclosures of amounts reclassified from accumulated other comprehensive income.  Additionally, we are currently evaluating the pending adoption of new accounting guidance relating to the balance sheet presentation of certain unrecognized tax benefits.  See Note 14.

MARKET AND CREDIT RISKS

Market Risks

Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund and benefit plan assets.

Interest Rate and Equity Risk

We have exposure to changing interest rates.  Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trusts (see Notes 12 and 13) and benefit plan assets.  The nuclear decommissioning trusts and benefit plan assets also have risks associated with the changing value of their investments.  Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas.  Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies.  We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options and swaps.  As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and fuels.  The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

The following table shows the net pretax changes in mark-to-market of our derivative positions for the six months ended June 30, 2013 and 2012 (dollars in millions):

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	Six Months Ended June 30,
	2013			2012
Mark-to-market of net positions at beginning of period	$	(122	)	$	(222	)
Recognized in earnings (a):
Change in mark-to-market losses for future period deliveries	—			3
Decrease (increase) in regulatory asset	(3		)	24
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (b)	—			(37		)
Mark-to-market losses realized during the period	16			37
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(109	)	$	(195	)

(a)Represents the amounts reflected in income after the effect of PSA deferrals.

(b)The changes in mark-to-market recorded in OCI are due primarily to changes in forward natural gas prices.

The table below shows the fair value of maturities of our derivative contracts (dollars in millions and excluding margin and collateral) at June 30, 2013 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  See Note 1, “Derivative Accounting” and “Fair Value Measurements,” in Item 8 of our 2012 Form 10-K and Note 12 for more discussion of our valuation methods.

Source of Fair Value	2013			2014			2015			2016			2017			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(30	)	$	(23	)	$	(3	)	$	(1	)	$	—		$	—		$	(57	)
Prices based on unobservable inputs	(8		)	(12		)	(13		)	(9		)	(4		)	(6		)	(52		)
Total by maturity	$	(38	)	$	(35	)	$	(16	)	$	(10	)	$	(4	)	$	(6	)	$	(109	)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at June 30, 2013 and December 31, 2012 (dollars in millions):

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	June 30, 2013 Gain (Loss)					December 31, 2012 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) or OCI (a)
Electricity	$	7	$	(7	)	$	7	$	(7	)
Natural gas	28		(28		)	25		(25		)
Total	$	35	$	(35	)	$	32	$	(32	)

(a)These contracts are hedges of our forecasted purchases of natural gas and electricity.  The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.  To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties.  See Note 12 for a discussion of our credit valuation adjustment policy.  See Note 7 for a further discussion of credit risk.

Item 3.                   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Key Financial Drivers” and “Market and Credit Risks” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4.                   CONTROLS AND PROCEDURES

(a)Disclosure Controls and Procedures

The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (15 U.S.C. 78a et seq.), is recorded, processed, summarized and reported, within the time periods specified in the United States Securities and Exchange Commission’s (“SEC’s”) rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of June 30, 2013.  Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

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APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of June 30, 2013.  Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b)Changes in Internal Control Over Financial Reporting

The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended June 30, 2013 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

See “Environmental Matters” in Item 5 below and in Item 5 of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, and “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2012 Form 10-K in regard to pending or threatened litigation and other disputes.

See Note 3 for ACC and FERC-related matters.

See Note 9 for information regarding environmental and climate change matters, Superfund-related matters and matters related to a September 2011 power outage.

Item 1A.RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A — Risk Factors in the 2012 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS.  The risks described in the 2012 Form 10-K are not the only risks facing Pinnacle West and APS.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.

Item 5.OTHER INFORMATION

Environmental Matters

EPA Environmental Regulation

Regional Haze Rules — Four Corners.  On August 6, 2012, EPA issued its final BART determination for Four Corners.  The rule includes two compliance alternatives.  The first emission control alternative finalized by EPA would require the installation of post-combustion controls on each of Units 1-5 at Four Corners to reduce NOx emissions.  Current estimates indicate that APS’s share of total costs for Four Corners for these controls would be approximately $400 million.  Under the second emission control alternative finalized by EPA, the owners of Four Corners would have the option to permanently close Units 1-3 by January 1, 2014 and install post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018.  APS’s share of total costs for these controls would be approximately $300 million.  The majority of these costs are not included in the capital expenditure estimates in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 2, since they would be incurred in years following 2015.  Under the final BART rule, the Four Corners participants had until July 1, 2013 to notify EPA of which emission control approach Four Corners would follow.  However, on June 25, 2013, EPA issued a proposed rule that would extend the date by which the Four Corners participants must notify EPA of their chosen BART compliance strategy, from July 1, 2013 to December 31, 2013.

Endangered Species Act.  On January 30, 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the Office of Surface Mining Reclamation and Enforcement (“OSM”) and DOI, alleging that OSM failed to engage in mandatory Endangered Species Act consultation with the Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners.  The lawsuit alleged that activities at the mine, including mining and the disposal of coal

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combustion residuals, would adversely affect several endangered species and their critical habitats.  APS is not a party to the lawsuit but is monitoring it to determine its potential impact on APS’s operations.  On March 14, 2012, the district court entered an order dismissing the plaintiffs’ lawsuit without prejudice and the plaintiffs appealed the court’s order to the United States Court of Appeals for the Tenth Circuit.  Subsequently, the parties settled and the case was dismissed on July  8, 2013.

President Obama’s Climate Action Plan.  On June 25, 2013, President Obama unveiled his Climate Action Plan addressing his plans to reduce greenhouse gas (“GHG”) emissions in the United States.  While the plan identifies a wide range of strategies for cutting GHG emissions, most important to APS and the electric utility industry is the implementation of carbon pollution standards for modified and existing fossil-fired generating plants.  Concurrent with the President’s speech, the White House issued a Presidential Memorandum directing EPA to use its existing authorities under the Clean Air Act to develop GHG emission standards for new, modified, and existing power plants.  The Presidential Memorandum directs EPA to propose GHG emission standards for modified and existing units by June 1, 2014 and to finalize them by June 1, 2015.  The memorandum further directs EPA to reissue proposed standards for new power plants by September 20, 2013 and to finalize them in a timely fashion.  APS will continue to monitor these standards as they are developed.  We cannot currently predict the shape of any final rules or standards or whether they will have a material adverse impact on our financial position, results of operations, or cash flows.

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Item 6.EXHIBITS

(a)Exhibits

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1*	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	Pinnacle West APS	XBRL Instance Document
101.SCH*	Pinnacle West APS	XBRL Taxonomy Extension Schema Document
101.CAL*	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document

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Exhibit No.	Registrant(s)	Description
101.LAB*	Pinnacle West APS	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Pinnacle West APS	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF*	Pinnacle West APS	XBRL Taxonomy Definition Linkbase Document

*Furnished herewith as an Exhibit.

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In addition, Pinnacle West and APS hereby incorporate the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit(1)	Date Filed
3.1	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of May 19, 2010	3.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-3-10
3.2	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-7-08
3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93
3.4	APS	Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012	3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473	5-22-12
3.5	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008	3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473	2-20-09

(1)  Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		PINNACLE WEST CAPITAL CORPORATION
		(Registrant)
Dated:	August 2, 2013	By:	/s/ James R. Hatfield
				James R. Hatfield
				Executive Vice President and
				Chief Financial Officer
				(Principal Financial Officer and
				Officer Duly Authorized to sign this Report)
		ARIZONA PUBLIC SERVICE COMPANY
		(Registrant)
Dated:	August 2, 2013	By:	/s/ James R. Hatfield
				James R. Hatfield
				Executive Vice President and
				Chief Financial Officer
				(Principal Financial Officer and
				Officer Duly Authorized to sign this Report)

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EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Six Months Ended June 30,		Twelve Months Ended December 31,
	2013		2012		2011		2010		2009		2008
Earnings:
Income from continuing operations attributable to common shareholders	$	155,651	$	387,380	$	328,110	$	324,688	$	236,839	$	259,871
Income taxes	89,512		237,317		183,604		160,869		138,551		95,231
Fixed charges	102,864		219,437		246,462		248,664		241,807		224,760
Total earnings	$	348,027	$	844,134	$	758,176	$	734,221	$	617,197	$	579,862
Fixed Charges:
Interest expense	$	100,785	$	214,616	$	241,995	$	244,174	$	237,766	$	220,223
Estimated interest portion of annual rents	2,079		4,821		4,467		4,490		4,041		4,537
Total fixed charges	$	102,864	$	219,437	$	246,462	$	248,664	$	241,807	$	224,760
Ratio of Earnings to Fixed Charges (rounded down)	3.38		3.84		3.07		2.95		2.55		2.57

EX-12.2

Exhibit 12.2

ARIZONA PUBLIC SERVICE COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Six Months Ended June 30,		Twelve Months Ended December 31,
	2013		2012		2011		2010		2009		2008
Earnings:
Income from continuing operations attributable to common shareholders	$	159,991	$	395,497	$	336,249	$	335,663	$	251,225	$	262,344
Income taxes	92,580		244,396		192,542		170,465		152,574		107,261
Fixed charges	101,036		214,227		238,286		234,184		227,274		206,896
Total earnings	$	353,607	$	854,120	$	767,077	$	740,312	$	631,073	$	576,501
Fixed Charges:
Interest charges	$	97,161	$	205,533	$	229,326	$	225,269	$	218,969	$	197,964
Amortization of debt discount	1,993		4,215		4,616		4,559		4,675		4,702
Estimated interest portion of annual rents	1,882		4,479		4,344		4,356		3,630		4,230
Total fixed charges	$	101,036	$	214,227	$	238,286	$	234,184	$	227,274	$	206,896
Ratio of Earnings to Fixed Charges (rounded down)	3.49		3.98		3.21		3.16		2.77		2.78

EX-12.3

Exhibit 12.3

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED

STOCK DIVIDEND REQUIREMENTS

(dollars in thousands)

	Six Months Ended June 30,		Twelve Months Ended December 31,
	2013		2012		2011		2010		2009		2008
Earnings:
Income from continuing operations attributable to common shareholders	$	155,651	$	387,380	$	328,110	$	324,688	$	236,839	$	259,871
Income taxes	89,512		237,317		183,604		160,869		138,551		95,231
Fixed charges	102,864		219,437		246,462		248,664		241,807		224,760
Total earnings	$	348,027	$	844,134	$	758,176	$	734,221	$	617,197	$	579,862
Fixed Charges:
Interest expense	$	100,785	$	214,616	$	241,995	$	244,174	$	237,766	220,223
Estimated interest portion of annual rents	2,079		4,821		4,467		4,490		4,041		4,537
Total fixed charges	$	102,864	$	219,437	$	246,462	$	248,664	$	241,807	$	224,760
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	245,163	$	624,697	$	511,714	$	485,557	$	375,390	$	355,102
Net income from continuing operations attributable to common shareholders	155,651		387,380		328,110		324,688		236,839		259,871
Ratio of income before income taxes to net income	1.58		1.61		1.56		1.50		1.59		1.37
Preferred stock dividends	—		—		—		—		—		—
Preferred stock dividend requirements – ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	102,864	$	219,437	$	246,462	$	248,664	$	241,807	$	224,760
Preferred stock dividend requirements	—		—		—		—		—		—
Total	$	102,864	$	219,437	$	246,462	$	248,664	$	241,807	$	224,760
Ratio of Earnings to Fixed Charges (rounded down)	3.38		3.84		3.07		2.95		2.55		2.57

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Donald E. Brandt, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:August 2, 2013

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James R. Hatfield, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 2, 2013
		/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Donald E. Brandt, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 2, 2013.
		/s/ Donald E. Brandt
		Donald E. Brandt
		Chairman, President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION

I, James R. Hatfield, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 2, 2013
		/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended June 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:	August 2, 2013
		/s/ Donald E. Brandt
		Donald E. Brandt
		Chairman, President and
		Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended June 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:	August 2, 2013
		/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer

EX-32.2

Exhibit 32.2

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended June 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:	August 2, 2013
		/s/ Donald E. Brandt
		Donald E. Brandt
		Chairman, President and Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended June 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:	August 2, 2013
		/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer

XML

Commitments and Contingencies

6 Months Ended

Jun. 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 June 30, 2013, APS had a regulatory liability of $44 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 $12.6 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 $12.2 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 $118 million, subject to an annual limit of $18 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 $103 million, with an annual payment limitation of approximately $15 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

There have been no material changes outside the normal course of business in contractual obligations from the 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.

The Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against over 40 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.  On February 21, 2013, certain of the defendants filed third-party complaints against additional parties, including APS.  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.

Climate Change Lawsuit

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law.  The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages.  In June 2008, the defendants filed motions to dismiss the action, which were granted.  The plaintiffs filed an appeal with the United States Court of Appeals for the Ninth Circuit in November 2009.

On September 21, 2012, a three-judge panel of the Ninth Circuit affirmed the district court’s dismissal of the Kivalina plaintiffs’ federal common law public nuisance action.  The court declined to address any other issue raised by the parties, including the plaintiffs’ state nuisance law claim.  On October 4, 2012, the plaintiffs filed a petition for rehearing by the entire Ninth Circuit, but on November 27, 2012, the court denied the plaintiffs’ petition.  On February 25, 2013, plaintiffs requested the United States Supreme Court to hear the case, but on May 20, 2013, the Court denied plaintiff’s petition for judicial review.  There is no right to appeal from this decision.

Southwest Power Outage

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

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 megawatts (“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.

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 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 $158 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 $187 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 $124 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 “best available retrofit technology” (“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.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At June 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 December 31, 2015, and totaled approximately $34 million at June 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 June 30, 2013, $60 million of such letters of credit were outstanding that will expire in 2013 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 June 30, 2013.

XML

Earnings Per Share (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Basic earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$ 1.19	$ 1.12	$ 1.42	$ 1.06
Loss from discontinued operations (in dollars per share)				$ (0.02)
Earnings per share - basic (in dollars per share)	$ 1.19	$ 1.12	$ 1.42	$ 1.04
Diluted earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$ 1.18	$ 1.12	$ 1.40	$ 1.05
Loss from discontinued operations (in dollars per share)		$ (0.01)		$ (0.01)
Earnings per share - diluted (in dollars per share)	$ 1.18	$ 1.11	$ 1.40	$ 1.04
Performance shares and restricted stock units	970,000	868,000	945,000	788,000
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

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$ 139,598	$ 130,111	$ 172,434	$ 129,630
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $105 and $(1,781) for three months ended June 30, 2013 and 2012 and of $67 and $14,770 for six months ended June 30, 2013 and 2012	(160)	2,728	(102)	(22,624)
Reclassification of net realized loss, net of tax benefit of $2,824 and $9,090 for three months ended June 30, 2013 and 2012 and $6,124 and $14,818 for six months ended June 30, 2013 and 2012	4,322	13,925	9,375	22,697
Pension and other postretirement benefits activity, net of tax benefit (expense) of $449 and $(526) for three months ended June 30, 2013 and 2012 and $(182) and $(1,157) for six months ended June 30, 2013 and 2012	(688)	806	278	1,772
Total other comprehensive income	3,474	17,459	9,551	1,845
COMPREHENSIVE INCOME	143,072	147,570	181,985	131,475
Less: Comprehensive income attributable to noncontrolling interests	8,391	7,766	16,783	15,542
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 134,681	$ 139,804	$ 165,202	$ 115,933

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Long-Term Debt and Liquidity Matters

6 Months Ended

Jun. 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 June 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 June 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 June 30, 2013 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.

At June 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 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 June 30, 2013, APS had commercial paper borrowings of $30 million and no outstanding borrowings or outstanding letters of credit under these credit facilities.

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.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at June 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 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 June 30, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,294		3,591		3,197		3,750
Total	$	3,419	$	3,716	$	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 June 30, 2013, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.1 billion, and total capitalization was approximately $7.4 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.

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Consolidation and Nature of Operations (Tables)

6 Months Ended

Jun. 30, 2013

Consolidation and Nature of Operations

Impact of the reclassifications to prior year (previously reported) amounts of the deferred investment tax credit which has become more material

The following tables show the impact of the reclassifications to prior year (previously reported) amounts of the deferred investment tax credit which has become more material this quarter (dollars in thousands):

Balance Sheets - December 31, 2012	As previously reported		Reclassifications			Amount reported after reclassifications
Deferred investment tax credit	$	—	$	99,819		$	99,819
Deferred credits — other	283,654		(99,819		)	183,835

Statement of Cash Flows for the Six Months Ended June 30, 2012	As previously reported		Reclassifications			Amount reported after reclassifications
Cash Flows from Operating Activities
Deferred income taxes	$	66,142	$	(5,033	)	$	61,109
Deferred investment tax credit	—		5,033			5,033

Summary of supplemental cash flow information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):

	Six Months Ended June 30,
	2013			2012
Cash paid during the period for:
Income taxes, net of (refunds)	$	(9	)	$	(649	)
Interest, net of amounts capitalized	91,346			94,680
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	8,904		$	14,745
Dividends accrued but not paid	59,946			57,479

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Other Income and Other Expense (APSC) (Tables)

6 Months Ended

Jun. 30, 2013

Detail of other income and other expense

The following table provides detail of other income and other expense for the three and six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	467		$	107		$	1,176		$	712
Miscellaneous	2			70			51			225
Total other income	$	469		$	177		$	1,227		$	937
Other expense:
Non-operating costs	$	(1,990	)	$	(2,389	)	$	(3,923	)	$	(4,239	)
Investment losses — net	(96		)	(58		)	(208		)	(112		)
Miscellaneous	(148		)	(222		)	(1,855		)	(2,386		)
Total other expense	$	(2,234	)	$	(2,669	)	$	(5,986	)	$	(6,737	)

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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	403		$	77		$	1,059		$	184
Miscellaneous	545			941			1,232			1,344
Total other income	$	948		$	1,018		$	2,291		$	1,528
Other expense:
Non-operating costs (a)	$	(2,285	)	$	(2,941	)	$	(4,605	)	$	(4,682	)
Asset dispositions	(1,397		)	(195		)	(2,661		)	(418		)
Miscellaneous	(1,162		)	(857		)	(3,874		)	(3,517		)
Total other expense	$	(4,844	)	$	(3,993	)	$	(11,140	)	$	(8,617	)

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

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Nuclear Decommissioning Trusts (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Nuclear decommissioning trust fund assets
Fair Value	$ 595,231,000		$ 595,231,000		$ 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			253,996,000	211,138,000
Fair value of fixed income securities, summarized by contractual maturities
Total	595,231,000		595,231,000		570,625,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	595,231,000		595,231,000		570,625,000
Unrealized Gains	107,000,000		107,000,000		91,000,000
Unrealized Losses	(6,000,000)		(6,000,000)
Net payables for securities purchases	(6,000,000)		(6,000,000)		(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	2,000,000	3,000,000	4,000,000
Realized losses	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Proceeds from the sale of securities	119,000,000	119,000,000	253,996,000	211,138,000
Fair value of fixed income securities, summarized by contractual maturities
Total	595,231,000		595,231,000		570,625,000
ARIZONA PUBLIC SERVICE COMPANY | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	233,000,000		233,000,000		204,000,000
Unrealized Gains	93,000,000		93,000,000		67,000,000
Fair value of fixed income securities, summarized by contractual maturities
Total	233,000,000		233,000,000		204,000,000
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	368,000,000		368,000,000		371,000,000
Unrealized Gains	14,000,000		14,000,000		24,000,000
Unrealized Losses	(6,000,000)		(6,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	11,000,000		11,000,000
1 year - 5 years	106,000,000		106,000,000
5 years - 10 years	100,000,000		100,000,000
Greater than 10 years	151,000,000		151,000,000
Total	$ 368,000,000		$ 368,000,000		$ 371,000,000

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Other Income and Other Expense

6 Months Ended

Jun. 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	467		$	107		$	1,176		$	712
Miscellaneous	2			70			51			225
Total other income	$	469		$	177		$	1,227		$	937
Other expense:
Non-operating costs	$	(1,990	)	$	(2,389	)	$	(3,923	)	$	(4,239	)
Investment losses — net	(96		)	(58		)	(208		)	(112		)
Miscellaneous	(148		)	(222		)	(1,855		)	(2,386		)
Total other expense	$	(2,234	)	$	(2,669	)	$	(5,986	)	$	(6,737	)

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Changes in Equity (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Changes in equity
Balance	$ 4,152,330	$ 3,861,429	$ 4,102,289	$ 3,930,586
Net income	139,598	130,111	172,434	129,630
Other comprehensive income (loss)	3,474	17,459	9,551	1,845
COMPREHENSIVE INCOME	143,072	147,570	181,985	131,475
Issuance of common stock	2,363	2,525	4,937	5,225
Reissuance of treasury stock - net	366	5,113	(5,905)	3,359
Other (primarily stock compensation)	185	631	15,010	3,981
Dividends on common Stock	(119,885)	(114,955)	(119,885)	(172,313)
Net capital activities by noncontrolling interests	(9,196)	(2,976)	(9,196)	(2,976)
Balance	4,169,235	3,899,337	4,169,235	3,899,337
Common Shareholders
Changes in equity
Balance	4,014,455	3,744,917	3,972,806	3,821,850
Net income	131,207	122,345	155,651	114,088
Other comprehensive income (loss)	3,474	17,459	9,551	1,845
COMPREHENSIVE INCOME	134,681	139,804	165,202	115,933
Issuance of common stock	2,363	2,525	4,937	5,225
Reissuance of treasury stock - net	366	5,113	(5,905)	3,359
Other (primarily stock compensation)	185	631	15,010	3,981
Dividends on common Stock	(119,885)	(114,955)	(119,885)	(172,313)
Balance	4,032,165	3,778,035	4,032,165	3,778,035
Noncontrolling Interests
Changes in equity
Balance	137,875	116,512	129,483	108,736
Net income	8,391	7,766	16,783	15,542
COMPREHENSIVE INCOME	8,391	7,766	16,783	15,542
Net capital activities by noncontrolling interests	(9,196)	(2,976)	(9,196)	(2,976)
Balance	$ 137,070	$ 121,302	$ 137,070	$ 121,302

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Changes in Accumulated Other Comprehensive Loss (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (107,931)		$ (114,008)
Other comprehensive loss before reclassifications	(1,795)		(1,737)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	5,269		11,288
Net current period other comprehensive income (loss)	3,474	17,459	9,551	1,845
Ending balance	(104,457)		(104,457)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(44,481)		(49,592)
Other comprehensive loss before reclassifications	(160)		(102)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	4,322		9,375
Net current period other comprehensive income (loss)	4,162		9,273
Ending balance	(40,319)		(40,319)
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(63,450)		(64,416)
Other comprehensive loss before reclassifications	(1,635)		(1,635)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	947		1,913
Net current period other comprehensive income (loss)	(688)		278
Ending balance	$ (64,138)		$ (64,138)

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Regulatory Matters (Details) (USD $)	6 Months Ended						0 Months Ended	6 Months Ended		0 Months Ended	6 Months Ended	1 Months Ended		1 Months Ended			12 Months Ended		1 Months Ended				1 Months Ended	6 Months Ended		1 Months Ended			1 Months Ended		3 Months Ended		0 Months Ended	1 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Power Supply Adjustor (PSA)	Jun. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY 2013 DSMAC	Feb. 12, 2013 ARIZONA PUBLIC SERVICE COMPANY Lost Fixed Cost Recovery Mechanism	Jun. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY Lost Fixed Cost Recovery Mechanism	Jul. 12, 2013 ARIZONA PUBLIC SERVICE COMPANY ACC MW	Jul. 12, 2013 ARIZONA PUBLIC SERVICE COMPANY ACC Net Metering Application	Jun. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY ACC RES	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 RES Cost Recovery Mechanisms	Jun. 02, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 DSMAC Cost Recovery Mechanisms	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Apr. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Jun. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Dec. 31, 2009 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Jun. 02, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 RES Minimum	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 RES Maximum	Jan. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 RES Maximum	Jul. 12, 2013 ARIZONA PUBLIC SERVICE COMPANY ACC RES implementation plan covering 2014-2018 timeframe Net Metering Application	Feb. 28, 2013 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms	Jun. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms	Jan. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission	Jun. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission	Jan. 06, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission	Jan. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Current	Dec. 31, 2009 ARIZONA PUBLIC SERVICE COMPANY ACC 2008 General retail rate case	Jun. 30, 2010 ARIZONA PUBLIC SERVICE COMPANY ACC 2008 General retail rate case	Dec. 30, 2009 ARIZONA PUBLIC SERVICE COMPANY ACC 2008 General retail rate case item	Jun. 01, 2013 ARIZONA PUBLIC SERVICE COMPANY FERC Transmission Rates and Transmission Cost Adjustor Cost Recovery Mechanisms	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY FERC Transmission Rates and Transmission Cost Adjustor Cost Recovery Mechanisms
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
Approved Order
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
Plan term											5 years
Funding request																			97,000,000	107,000,000
Funding approval as per budget authorized												110,000,000
Amount of approved budget																					103,000,000
Remaining capacity from APS-owned AZ Sun projects (in MW)									50
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
Percentage of sale of distributed energy system's output at a market-based price for installing new rooftop solar system to all new residential customers										100.00%
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%
Amount of proposed budget						87,600,000																143,000,000
Change in regulatory asset
Beginning balance																								73,000,000	28,000,000
Deferred fuel and purchased power costs-current period	(36,183,000)	(82,261,000)		(36,183,000)	(82,261,000)																			(36,000,000)	(82,000,000)
Amounts (collected from) credited to customers	(10,921,000)	54,388,000		(10,921,000)	54,388,000																			(10,000,000)	54,000,000
Ending balance																								27,000,000
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)			(0.0010)
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								0.031
Fixed costs recoverable per non-residential power lost								0.023
Amount of adjustment approved representing prorated sales losses							$ 5,100,000

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Retirement Plans and Other Benefits (Tables)

6 Months Ended

Jun. 30, 2013

Retirement Plans and Other Benefits

Net periodic benefit costs and the portion of these costs charged to expense

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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost - benefits earned during the period	$	15		$	15		$	32		$	32		$	6		$	6		$	12		$	14
Interest cost on benefit obligation	28			30			56			60			10			11			20			23
Expected return on plan assets	(36		)	(35		)	(73		)	(71		)	(12		)	(11		)	(23		)	(23		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	10			12			20			22			3			4			6			10
Net periodic benefit cost	$	17		$	22		$	36		$	44		$	7		$	10		$	15		$	24
Portion of cost charged to expense	$	9		$	8		$	19		$	13		$	4		$	3		$	9		$	6

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Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2013

Regulatory Matters

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):

	Six Months Ended June 30,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs — current period	(36		)	(82		)
Amounts (collected from) credited to customers	(10		)	54
Ending balance	$	27		$	—

Detail of regulatory assets

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

	Remaining
	Amortization	June 30, 2013				December 31, 2012
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)	$	—	$	766	$	—	$	780
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2043	4		97		4		92
Deferred fuel and purchased power — mark-to-market (Note 7)	2016	15		28		19		21
Transmission vegetation management	2016	9		18		9		23
Coal reclamation	2038	8		22		8		24
Palo Verde VIEs (Note 6)	2046	—		40		—		38
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2013	27		—		73		—
Retired power plant costs	2020	3		19		—		—
Tax expense of Medicare subsidy	2024	2		16		2		17
Loss on reacquired debt	2034	1		18		2		18
Income taxes — investment tax credit basis adjustment	2042	1		31		1		26
Pension and other postretirement benefits deferral	2015	8		8		8		13
Lost fixed cost recovery	2014	14		1		7		—
Transmission cost adjustor	2014	13		3		10		—
Other	Various	1		17		1		14
Total regulatory assets (d)		$	106	$	1,120	$	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.”

Detail of regulatory liabilities

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

	Remaining
	Amortization	June 30, 2013				December 31, 2012
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	27	$	316	$	27	$	321
Asset retirement obligations	(a)	—		263		—		256
Renewable energy standard (b)	2014	28		16		43		—
Income taxes — change in rates	2042	—		68		—		66
Spent nuclear fuel	2047	6		38		10		36
Deferred gains on utility property	2019	2		11		2		12
Income taxes — deferred investment tax credit	2042	2		62		2		52
Demand side management	2014	16		—		4		—
Other	Various	—		17		—		16
Total regulatory liabilities		$	81	$	791	$	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.

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Derivative Accounting (Details 3) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Commodity Contracts
Assets
Amount Reported on Balance Sheet	$ 54,000
Assets and Liabilities
Gross Recognized Derivatives	(108,675)	(122,252)
Amounts Offset	28,700	49,299
Net Recognized Derivatives	(79,975)	(72,953)
Other	(18,861)	(24,462)
Amount Reported on Balance Sheet	(98,836)	(97,415)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	32,642	42,495
Amounts Offset	(10,669)	(17,797)
Net Recognized Derivatives	21,973	24,698
Other	602	1,001
Amount Reported on Balance Sheet	22,575	25,699
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	34,486	41,563
Amounts Offset	(2,568)	(5,672)
Net Recognized Derivatives	31,918	35,891
Amount Reported on Balance Sheet	31,918	35,891
Commodity Contracts | Total Assets
Assets
Gross Recognized Derivatives	67,128	84,058
Amounts Offset	(13,237)	(23,469)
Net Recognized Derivatives	53,891	60,589
Other	602	1,001
Amount Reported on Balance Sheet	54,493	61,590
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(82,710)	(105,324)
Amounts Offset	34,318	57,046
Net Recognized Derivatives	(48,392)	(48,278)
Other	(19,463)	(25,463)
Amount Reported on Balance Sheet	(67,855)	(73,741)
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(93,093)	(100,986)
Amounts Offset	7,619	15,722
Net Recognized Derivatives	(85,474)	(85,264)
Amount Reported on Balance Sheet	(85,474)	(85,264)
Commodity Contracts | Total Liabilities
Liabilities
Gross Recognized Derivatives	(175,803)	(206,310)
Amounts Offset	41,937	72,768
Net Recognized Derivatives	(133,866)	(133,542)
Other	(19,463)	(25,463)
Amount Reported on Balance Sheet	(153,329)	(159,005)
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	$ 5,000	$ 5,000

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Nuclear Decommissioning Trusts (Tables)

6 Months Ended

Jun. 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 June 30, 2013 and December 31, 2012 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2013
Equity securities	$	233		$	93	$	—
Fixed income securities	368			14		(6		)
Net payables (a)	(6		)	—		—
Total	$	595		$	107	$	(6	)

(a) Net payables relate to pending securities sales and purchases.

	Fair Value			Total Unrealized Gains		Total Unrealized 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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized gains	$	1		$	2		$	3		$	4
Realized losses	(1		)	(1		)	(2		)	(2		)
Proceeds from the sale of securities (a)	119			119			254			211

(a) Proceeds are reinvested in the trust.

Fair value of fixed income securities, summarized by contractual maturities

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2013 is as follows (dollars in millions):

	Fair Value
Less than one year	$		11
1 year - 5 years	106
5 years - 10 years	100
Greater than 10 years	151
Total	$	368

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Regulatory Matters (Details 3) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Detail of regulatory liabilities
Regulatory liabilities, current	$ 81,000,000	$ 88,000,000
Regulatory liabilities, non-current	790,788,000	759,201,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	27,000,000	27,000,000
Regulatory liabilities, non-current	316,000,000	321,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, non-current	263,000,000	256,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	28,000,000	43,000,000
Regulatory liabilities, non-current	16,000,000
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	6,000,000	10,000,000
Regulatory liabilities, non-current	38,000,000	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	62,000,000	52,000,000
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	16,000,000	4,000,000
Other
Detail of regulatory liabilities
Regulatory liabilities, non-current	$ 17,000,000	$ 16,000,000

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Commitments and Contingencies (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	0 Months Ended	6 Months Ended
	Apr. 02, 2013	Jun. 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		44,000,000
Maximum insurance against public liability per occurrence for a nuclear incident		12,600,000,000
Maximum available nuclear liability insurance		375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program		12,200,000,000
Maximum assessment per reactor for each nuclear incident		118,000,000
Annual limit per incident with respect to maximum assessment		18,000,000
Number of VIE lessor trusts		3
Maximum potential retrospective assessment per incident of APS		103,000,000
Annual payment limitation with respect to maximum potential retrospective assessment		15,000,000
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

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Other Income and Other Expense (Tables)

6 Months Ended

Jun. 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	467		$	107		$	1,176		$	712
Miscellaneous	2			70			51			225
Total other income	$	469		$	177		$	1,227		$	937
Other expense:
Non-operating costs	$	(1,990	)	$	(2,389	)	$	(3,923	)	$	(4,239	)
Investment losses — net	(96		)	(58		)	(208		)	(112		)
Miscellaneous	(148		)	(222		)	(1,855		)	(2,386		)
Total other expense	$	(2,234	)	$	(2,669	)	$	(5,986	)	$	(6,737	)

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Other Income and Other Expense (APSC)

6 Months Ended

Jun. 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	467		$	107		$	1,176		$	712
Miscellaneous	2			70			51			225
Total other income	$	469		$	177		$	1,227		$	937
Other expense:
Non-operating costs	$	(1,990	)	$	(2,389	)	$	(3,923	)	$	(4,239	)
Investment losses — net	(96		)	(58		)	(208		)	(112		)
Miscellaneous	(148		)	(222		)	(1,855		)	(2,386		)
Total other expense	$	(2,234	)	$	(2,669	)	$	(5,986	)	$	(6,737	)

ARIZONA PUBLIC SERVICE COMPANY

Other Income and Other Expense

S-2.         Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income:
Interest income	$	403		$	77		$	1,059		$	184
Miscellaneous	545			941			1,232			1,344
Total other income	$	948		$	1,018		$	2,291		$	1,528
Other expense:
Non-operating costs (a)	$	(2,285	)	$	(2,941	)	$	(4,605	)	$	(4,682	)
Asset dispositions	(1,397		)	(195		)	(2,661		)	(418		)
Miscellaneous	(1,162		)	(857		)	(3,874		)	(3,517		)
Total other expense	$	(4,844	)	$	(3,993	)	$	(11,140	)	$	(8,617	)

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

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Changes in Equity (APSC)

6 Months Ended

Jun. 30, 2013

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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,014,455		$	137,875		$	4,152,330		$	3,744,917		$	116,512		$	3,861,429
Net income	131,207			8,391			139,598			122,345			7,766			130,111
Other comprehensive income	3,474			—			3,474			17,459			—			17,459
Total comprehensive income	134,681			8,391			143,072			139,804			7,766			147,570
Issuance of capital stock	2,363			—			2,363			2,525			—			2,525
Reissuance of treasury stock — net	366			—			366			5,113			—			5,113
Other (primarily stock compensation)	185			—			185			631			—			631
Dividends on common stock	(119,885		)	—			(119,885		)	(114,955		)	—			(114,955		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
Net income	155,651			16,783			172,434			114,088			15,542			129,630
Other comprehensive income	9,551			—			9,551			1,845			—			1,845
Total comprehensive income	165,202			16,783			181,985			115,933			15,542			131,475
Issuance of capital stock	4,937			—			4,937			5,225			—			5,225
Reissuance (purchase) of treasury stock - net	(5,905		)	—			(5,905		)	3,359			—			3,359
Other (primarily stock compensation)	15,010			—			15,010			3,981			—			3,981
Dividends on common stock	(119,885		)	—			(119,885		)	(172,313		)	—			(172,313		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

ARIZONA PUBLIC SERVICE COMPANY

Changes in Equity

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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,125,032		$	137,875		$	4,262,907		$	3,865,748		$	116,166		$	3,981,914
Net income	133,949			8,391			142,340			124,928			7,766			132,694
OCI	3,551			—			3,551			17,117			—			17,117
Total comprehensive income	137,500			8,391			145,891			142,045			7,766			149,811
Dividends on common stock	(119,800		)	—			(119,800		)	(105,000		)	—			(105,000		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,630		)	(2,630		)
Other	(6		)	—			(6		)	(2		)	—			(2		)
Ending balance, June 30	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, January 1	$	4,093,000		$	129,483		$	4,222,483		$	3,943,007		$	108,399		$	4,051,406
Net income	159,991			16,783			176,774			120,823			15,533			136,356
OCI	9,543			—			9,543			1,362			—			1,362
Total comprehensive income	169,534			16,783			186,317			122,185			15,533			137,718
Dividends on common stock	(119,800		)	—			(119,800		)	(162,400		)	—			(162,400		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,630		)	(2,630		)
Other	(8		)	—			(8		)	(1		)	—			(1		)
Ending balance, June 30	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093

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Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 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	$ 8,391,000	$ 7,766,000	$ 16,783,000	$ 15,542,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	127,060,000		127,060,000		128,995,000
Current maturities of long-term debt	599,131,000		599,131,000		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	137,070,000		137,070,000		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	8,391,000	7,766,000	16,783,000	15,533,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	127,060,000		127,060,000		128,995,000
Current maturities of long-term debt	599,131,000		599,131,000		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	137,070,000		137,070,000		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	8,000,000	8,000,000	17,000,000	16,000,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	127,000,000		127,000,000		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	137,000,000		137,000,000		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

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Changes in Equity (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Changes in equity
Balance	$ 4,152,330	$ 3,861,429	$ 4,102,289	$ 3,930,586
Net income	139,598	130,111	172,434	129,630
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	3,474	17,459	9,551	1,845
COMPREHENSIVE INCOME	143,072	147,570	181,985	131,475
Dividends on common stock	(119,885)	(114,955)	(119,885)	(172,313)
Net capital activities by noncontrolling interests	(9,196)	(2,976)	(9,196)	(2,976)
Other	(185)	(631)	(15,010)	(3,981)
Balance	4,169,235	3,899,337	4,169,235	3,899,337
Shareholder equity
Changes in equity
Balance	4,014,455	3,744,917	3,972,806	3,821,850
Net income	131,207	122,345	155,651	114,088
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	3,474	17,459	9,551	1,845
COMPREHENSIVE INCOME	134,681	139,804	165,202	115,933
Dividends on common stock	(119,885)	(114,955)	(119,885)	(172,313)
Other	(185)	(631)	(15,010)	(3,981)
Balance	4,032,165	3,778,035	4,032,165	3,778,035
Noncontrolling Interests
Changes in equity
Balance	137,875	116,512	129,483	108,736
Net income	8,391	7,766	16,783	15,542
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME	8,391	7,766	16,783	15,542
Net capital activities by noncontrolling interests	(9,196)	(2,976)	(9,196)	(2,976)
Balance	137,070	121,302	137,070	121,302
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Balance	4,262,907	3,981,914	4,222,483	4,051,406
Net income	142,340	132,694	176,774	136,356
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	3,551	17,117	9,543	1,362
COMPREHENSIVE INCOME	145,891	149,811	186,317	137,718
Dividends on common stock	(119,800)	(105,000)	(119,800)	(162,400)
Net capital activities by noncontrolling interests	(9,196)	(2,630)	(9,196)	(2,630)
Other	(6)	(2)	(8)	(1)
Balance	4,279,796	4,024,093	4,279,796	4,024,093
ARIZONA PUBLIC SERVICE COMPANY | Shareholder equity
Changes in equity
Balance	4,125,032	3,865,748	4,093,000	3,943,007
Net income	133,949	124,928	159,991	120,823
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	3,551	17,117	9,543	1,362
COMPREHENSIVE INCOME	137,500	142,045	169,534	122,185
Dividends on common stock	(119,800)	(105,000)	(119,800)	(162,400)
Other	(6)	(2)	(8)	(1)
Balance	4,142,726	3,902,791	4,142,726	3,902,791
ARIZONA PUBLIC SERVICE COMPANY | Noncontrolling Interests
Changes in equity
Balance	137,875	116,166	129,483	108,399
Net income	8,391	7,766	16,783	15,533
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME	8,391	7,766	16,783	15,533
Net capital activities by noncontrolling interests	(9,196)	(2,630)	(9,196)	(2,630)
Balance	$ 137,070	$ 121,302	$ 137,070	$ 121,302

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Long-Term Debt and Liquidity Matters (Tables)

6 Months Ended

Jun. 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 June 30, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,294		3,591		3,197		3,750
Total	$	3,419	$	3,716	$	3,322	$	3,875

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 27,803	$ 26,202
Customer and other receivables	345,581	277,225
Accrued unbilled revenues	163,608	94,845
Allowance for doubtful accounts	(2,821)	(3,340)
Materials and supplies (at average cost)	220,025	218,096
Fossil fuel (at average cost)	33,407	31,334
Deferred income taxes	105,146	152,191
Income tax receivable (Note 5)	2,317	2,423
Assets from risk management activities (Note 7)	22,575	25,699
Deferred fuel and purchased power regulatory asset (Note 3)	26,526	72,692
Other regulatory assets (Note 3)	79,405	71,257
Other current assets	42,717	37,102
Total current assets	1,066,289	1,005,726
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	31,918	35,891
Nuclear decommissioning trust (Note 13)	595,231	570,625
Other assets	64,304	62,694
Total investments and other assets	691,453	669,210
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,503,810	14,346,367
Accumulated depreciation and amortization	(5,022,729)	(4,929,613)
Net	9,481,081	9,416,754
Construction work in progress	545,231	565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	127,060	128,995
Intangible assets, net of accumulated amortization	162,715	162,150
Nuclear fuel, net of accumulated amortization	156,252	122,778
Total property, plant and equipment	10,472,339	10,396,393
DEFERRED DEBITS
Regulatory assets (Note 3)	1,120,366	1,099,900
Income tax receivable (Note 5)	71,274	70,389
Other	140,973	137,997
Total deferred debits	1,332,613	1,308,286
TOTAL ASSETS	13,562,694	13,379,615
CURRENT LIABILITIES
Accounts payable	287,368	221,312
Accrued taxes (Note 5)	129,865	124,939
Accrued interest	49,199	49,380
Common dividends payable	59,946	59,789
Short-term borrowings	30,100	92,175
Current maturities of long-term debt (Note 2)	599,131	122,828
Customer deposits	78,795	79,689
Liabilities from risk management activities (Note 7)	67,855	73,741
Regulatory liabilities (Note 3)	80,763	88,116
Other current liabilities	154,196	171,573
Total current liabilities	1,537,218	1,083,542
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
Long-term debt less current maturities	2,782,758	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	2,820,172	3,199,088
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,175,865	2,151,371
Regulatory liabilities (Note 3)	790,788	759,201
Liability for asset retirements	362,619	357,097
Liabilities for pension and other postretirement benefits (Note 4)	1,013,976	1,058,755
Deferred investment tax credit	119,979	99,819
Liabilities from risk management activities (Note 7)	85,474	85,264
Customer advances	108,335	109,359
Coal mine reclamation	115,145	118,860
Unrecognized tax benefits (Note 5)	72,629	71,135
Other	191,259	183,835
Total deferred credits and other	5,036,069	4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 8)
Common stock, no par value	2,486,871	2,466,923
Treasury stock	(10,117)	(4,211)
Total common stock	2,476,754	2,462,712
Retained earnings	1,659,868	1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(64,138)	(64,416)
Derivative instruments	(40,319)	(49,592)
Total accumulated other comprehensive loss	(104,457)	(114,008)
Total shareholders' equity	4,032,165	3,972,806
Noncontrolling interests (Note 6)	137,070	129,483
Total equity	4,169,235	4,102,289
TOTAL LIABILITIES AND EQUITY	$ 13,562,694	$ 13,379,615

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 172,434	$ 129,630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	249,482	239,743
Deferred fuel and purchased power	36,183	82,261
Deferred fuel and purchased power amortization	10,921	(54,388)
Allowance for equity funds used during construction	(13,129)	(9,931)
Deferred income taxes	68,526	61,109
Deferred investment tax credit	20,159	5,033
Change in derivative instruments fair value	349	(2,618)
Changes in current assets and liabilities:
Customer and other receivables	(79,408)	(21,424)
Accrued unbilled revenues	(68,763)	(43,211)
Materials, supplies and fossil fuel	(4,002)	(21,012)
Other current assets	(14,439)	(9,407)
Accounts payable	85,563	9,199
Accrued taxes and income tax receivable - net	5,032	19,775
Other current liabilities	(26,098)	807
Change in margin and collateral accounts - assets	(1,111)	124
Change in margin and collateral accounts - liabilities	14,600	69,602
Change in other long-term assets	(23,796)	(1,692)
Change in other long-term liabilities	21,753	5,035
Net cash flow provided by operating activities	454,256	458,635
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(376,601)	(424,775)
Contributions in aid of construction	21,236	25,800
Allowance for borrowed funds used during construction	(7,626)	(6,598)
Proceeds from nuclear decommissioning trust sales	253,996	211,138
Investment in nuclear decommissioning trust	(262,621)	(219,762)
Other	(262)	(525)
Net cash flow used for investing activities	(371,878)	(414,722)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	351,081
Repayment of long-term debt	(40,127)	(421,451)
Short-term borrowings and payments - net	(62,075)	109,000
Dividends paid on common stock	(116,231)	(111,297)
Common stock equity issuance	9,751	8,869
Distributions to noncontrolling interests	(9,197)	(2,630)
Other	795	160
Net cash flow used for financing activities	(80,777)	(66,268)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,601	(22,355)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	26,202	33,583
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 27,803	$ 11,228

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Regulatory Matters

6 Months Ended

Jun. 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.  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, began in June 2013 and is expected to conclude in September 2013.  The track and record approach would require monitoring the distributed energy systems that are connected to APS’s system, recording the amount of energy they produce, and reporting the energy production amounts to the ACC for informational purposes only.  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 to APS 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.

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 the Company’s obligations under its 2008 rate case settlement agreement approved by the ACC, including the remaining 50 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.

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 2013.

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):

	Six Months Ended June 30,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs — current period	(36		)	(82		)
Amounts (collected from) credited to customers	(10		)	54
Ending balance	$	27		$	—

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 and Transmission Cost Adjustor.  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 agreement 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 existing 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.  APS believes the costs associated with the termination of the existing agreement are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance.

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 commissioners voted to discuss this matter using a two-step process.  First, the ACC will solicit comments from interested parties on the pros and cons of retail electric deregulation in Arizona, including the potential effects on residential and small business customers.  The ACC opened a docket for this matter and set a procedural schedule whereby comments from interested parties were filed on July 15 and additional responses are due August 16, 2013.  The ACC plans to schedule an open meeting for discussion of these comments and a possible vote on whether to proceed to a second phase of consideration.  If the ACC votes to proceed to a second phase, they will then request the interested parties to propose structures and rules that would govern a future deregulated retail electric market for the ACC’s further consideration.  We cannot predict the outcome of these proceedings.

Regulatory Assets and Liabilities

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

	Remaining
	Amortization	June 30, 2013				December 31, 2012
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)	$	—	$	766	$	—	$	780
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2043	4		97		4		92
Deferred fuel and purchased power — mark-to-market (Note 7)	2016	15		28		19		21
Transmission vegetation management	2016	9		18		9		23
Coal reclamation	2038	8		22		8		24
Palo Verde VIEs (Note 6)	2046	—		40		—		38
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2013	27		—		73		—
Retired power plant costs	2020	3		19		—		—
Tax expense of Medicare subsidy	2024	2		16		2		17
Loss on reacquired debt	2034	1		18		2		18
Income taxes — investment tax credit basis adjustment	2042	1		31		1		26
Pension and other postretirement benefits deferral	2015	8		8		8		13
Lost fixed cost recovery	2014	14		1		7		—
Transmission cost adjustor	2014	13		3		10		—
Other	Various	1		17		1		14
Total regulatory assets (d)		$	106	$	1,120	$	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
	Amortization	June 30, 2013				December 31, 2012
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	27	$	316	$	27	$	321
Asset retirement obligations	(a)	—		263		—		256
Renewable energy standard (b)	2014	28		16		43		—
Income taxes — change in rates	2042	—		68		—		66
Spent nuclear fuel	2047	6		38		10		36
Deferred gains on utility property	2019	2		11		2		12
Income taxes — deferred investment tax credit	2042	2		62		2		52
Demand side management	2014	16		—		4		—
Other	Various	—		17		—		16
Total regulatory liabilities		$	81	$	791	$	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.

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Consolidation and Nature of Operations

6 Months Ended

Jun. 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 which has become more material this quarter (dollars in thousands):

Balance Sheets - December 31, 2012	As previously reported		Reclassifications			Amount reported after reclassifications
Deferred investment tax credit	$	—	$	99,819		$	99,819
Deferred credits — other	283,654		(99,819		)	183,835

Statement of Cash Flows for the Six Months Ended June 30, 2012	As previously reported		Reclassifications			Amount reported after reclassifications
Cash Flows from Operating Activities
Deferred income taxes	$	66,142	$	(5,033	)	$	61,109
Deferred investment tax credit	—		5,033			5,033

Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):

	Six Months Ended June 30,
	2013			2012
Cash paid during the period for:
Income taxes, net of (refunds)	$	(9	)	$	(649	)
Interest, net of amounts capitalized	91,346			94,680
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	8,904		$	14,745
Dividends accrued but not paid	59,946			57,479

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Retirement Plans and Other Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Retirement Plans and Other Benefits
Amount of pension and other postretirement benefit costs deferred		$ 5		$ 14
Amortization of regulatory assets	2		4
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	15	15	32	32
Interest cost on benefit obligation	28	30	56	60
Expected return on plan assets	(36)	(35)	(73)	(71)
Amortization of prior service cost			1	1
Amortization of net actuarial loss	10	12	20	22
Net periodic benefit cost	17	22	36	44
Portion of cost charged to expense	9	8	19	13
Contribution to pension plans			87
Pension Benefits | Expected contributions
Contributions
Expected contributions in 2013	140		140
Expected contributions in 2014	175		175
Expected contributions in 2015	175		175
Pension Benefits | Estimated contributions
Contributions
Expected contributions in 2013	0		0
Expected contributions in 2014	89		89
Expected contributions in 2015	112		112
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	6	6	12	14
Interest cost on benefit obligation	10	11	20	23
Expected return on plan assets	(12)	(11)	(23)	(23)
Amortization of net actuarial loss	3	4	6	10
Net periodic benefit cost	7	10	15	24
Portion of cost charged to expense	4	3	9	6
Contributions
Expected contributions in 2013	20		20
Expected contributions in 2014	20		20
Expected contributions in 2015	$ 20		$ 20

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

6 Months Ended

Jun. 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 June 30, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

	June 30, 2013		December 31, 2012
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	127	$	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	137		129

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2013

Earnings Per Share

Schedule of earnings per weighted average common share outstanding

	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	1.19	$	1.12		$	1.42	$	1.06
Loss from discontinued operations	—		—			—		(0.02		)
Earnings per share — basic	$	1.19	$	1.12		$	1.42	$	1.04
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	1.18	$	1.12		$	1.40	$	1.05
Loss from discontinued operations	—		(0.01		)	—		(0.01		)
Earnings per share — diluted	$	1.18	$	1.11		$	1.40	$	1.04

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Changes in Accumulated Other Comprehensive Loss (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (107,931)		$ (114,008)
Other comprehensive loss before reclassifications	(1,795)		(1,737)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	5,269		11,288
Net current period other comprehensive income (loss)	3,474	17,459	9,551	1,845
Ending balance	(104,457)		(104,457)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(44,481)		(49,592)
Other comprehensive loss before reclassifications	(160)		(102)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	4,322		9,375
Net current period other comprehensive income (loss)	4,162		9,273
Ending balance	(40,319)		(40,319)
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(63,450)		(64,416)
Other comprehensive loss before reclassifications	(1,635)		(1,635)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	947		1,913
Net current period other comprehensive income (loss)	(688)		278
Ending balance	(64,138)		(64,138)
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(83,103)		(89,095)
Other comprehensive loss before reclassifications	(1,790)		(1,732)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	5,341		11,275
Net current period other comprehensive income (loss)	3,551	17,117	9,543	1,362
Ending balance	(79,552)		(79,552)
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(44,482)		(49,592)
Other comprehensive loss before reclassifications	(160)		(102)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	4,322		9,374
Net current period other comprehensive income (loss)	4,162		9,272
Ending balance	(40,320)		(40,320)
ARIZONA PUBLIC SERVICE COMPANY | Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(38,621)		(39,503)
Other comprehensive loss before reclassifications	(1,630)		(1,630)
Amounts reclassified from accumulated other comprehensive loss
Amounts reclassified from accumulated other comprehensive loss:	1,019		1,901
Net current period other comprehensive income (loss)	(611)		271
Ending balance	$ (39,232)		$ (39,232)

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Long-Term Debt and Liquidity Matters (Details) (USD $)															0 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 Pinnacle West	Dec. 31, 2012 Pinnacle West	Jun. 30, 2013 APS	Dec. 31, 2012 APS	Jun. 30, 2013 APS ACC	Jun. 30, 2013 APS ACC Minimum	Jun. 30, 2013 Long term debt APS item	Jun. 30, 2013 Revolving credit facility maturing in 2016 Pinnacle West	Jun. 30, 2013 Revolving credit facility maturing in 2016 APS	Apr. 09, 2013 Revolving credit facility maturing in 2015 APS	Jun. 30, 2013 Revolving credit facility maturing in 2018 APS	Apr. 09, 2013 Revolving credit facility maturing in 2018 APS	Mar. 22, 2013 4.50% unsecured senior notes that mature on April 1, 2042 APS	Jun. 30, 2013 Pollution Control Revenue Refunding Bonds, 2009 Series C APS	May 01, 2013 Pollution Control Revenue Refunding Bonds, 2009 Series C APS	Jul. 12, 2013 Pollution Control Revenue Refunding Bonds, 1994 Series A APS
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									30,000,000	0
Notes issued															100,000,000
Interest rate (as a percent)															4.50%	1.75%
Number of line of credit facilities									2
Long-term debt redemption																	32,000,000	33,000,000
Estimated fair value of long-term debt, including current maturities
Carrying Amount	3,419,000,000	3,322,000,000	125,000,000	125,000,000	3,294,000,000	3,197,000,000
Fair Value	3,716,000,000	3,875,000,000	125,000,000	125,000,000	3,591,000,000	3,750,000,000
Debt Provisions
Required common equity ratio ordered by ACC (as a percent)								40.00%
Total shareholder equity	4,032,165,000	3,972,806,000			4,142,726,000	4,093,000,000	4,100,000,000
Total capitalization							7,400,000,000
Dividend restrictions, shareholder equity required								$ 3,000,000,000

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Other Income and Other Expense (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Other income:
Interest income	$ 467	$ 107	$ 1,176	$ 712
Miscellaneous	2	70	51	225
Total other income	469	177	1,227	937
Other expense:
Non-operating costs	(1,990)	(2,389)	(3,923)	(4,239)
Miscellaneous	(148)	(222)	(1,855)	(2,386)
Total other expense	(2,234)	(2,669)	(5,986)	(6,737)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	403	77	1,059	184
Miscellaneous	545	941	1,232	1,344
Total other income	948	1,018	2,291	1,528
Other expense:
Non-operating costs	(2,285)	(2,941)	(4,605)	(4,682)
Asset dispositions	(1,397)	(195)	(2,661)	(418)
Miscellaneous	(1,162)	(857)	(3,874)	(3,517)
Total other expense	$ (4,844)	$ (3,993)	$ (11,140)	$ (8,617)

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 53	$ 62
Liabilities	106	110
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	53	57
Liabilities	76	82
Electricity forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	24.77	23.06
Electricity forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	70.12	64.20
Electricity forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	42.10	43.16
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	27	27
Option Contracts | Minimum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	39.64	36.66
Natural gas forward price (per mmbtu)		4.10
Implied electricity price volatilities (as a percent)	17.00%	15.00%
Implied natural gas price volatilities (as a percent)	16.00%	17.00%
Option Contracts | Maximum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	84.73	92.19
Natural gas forward price (per mmbtu)		4.25
Implied electricity price volatilities (as a percent)	98.00%	66.00%
Implied natural gas price volatilities (as a percent)	32.00%	36.00%
Option Contracts | Weighted Average | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	58.26	60.97
Natural gas forward price (per mmbtu)		4.20
Implied electricity price volatilities (as a percent)	46.00%	39.00%
Implied natural gas price volatilities (as a percent)	21.00%	23.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets		5
Liabilities	$ 3	$ 1
Natural gas forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per mmbtu)	3.36	3.25
Natural gas forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per mmbtu)	3.36	4.44
Natural gas forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per mmbtu)	3.36	3.93

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Commitments and Contingencies (Details 2) (USD $) In Millions, unless otherwise specified	1 Months Ended		6 Months Ended		6 Months Ended
	Feb. 29, 2008 Climate Change Lawsuit item	Sep. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY kV item MW	Jun. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY item	Sep. 08, 2011 ARIZONA PUBLIC SERVICE COMPANY	Jun. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY Contaminated groundwater wells item
Superfund-Related Matters
Costs related to investigation and study under Superfund site			$ 2
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit					40
Number of oil companies	9
Number of power companies	14
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			34
Outstanding letters of credit to support natural gas tolling contract obligations			$ 60

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Derivative Accounting (Details 2) (Commodity Contracts, USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain (loss) recognized in OCI on derivative instruments (effective portion)	$ (265,000)	$ 4,509,000	$ (169,000)	$ (37,394,000)
Loss reclassified from accumulated other comprehensive income into income (effective portion realized)	(7,146,000)	(23,015,000)	(15,499,000)	(37,515,000)
Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)		32,000		117,000
Estimated net loss before income taxes to be reclassified from AOCI			37,000,000
Gains and losses from derivative instruments
Amount reclassified from AOCI to earnings related to discontinued cash flow hedges	0	(1,800,000)	0	(1,800,000)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net gain (loss) recognized in income from Derivative Instruments	(27,436,000)	26,129,000	(10,203,000)	751,000
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net gain (loss) recognized in income from Derivative Instruments	322,000	87,000	205,000	(239,000)
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net gain (loss) recognized in income from Derivative Instruments	$ (27,758,000)	$ 26,042,000	$ (10,408,000)	$ 990,000

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Income tax benefit on discontinued operations	$ 535	$ 1,040

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Palo Verde Sale Leaseback Variable Interest Entities

6 Months Ended

Jun. 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 six months ended June 30, 2013 of $8 million and $17 million, respectively, and for the three and six months ended June 30, 2012 of $8 million and $16 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 June 30, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

	June 30, 2013		December 31, 2012
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	127	$	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	137		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 June 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.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net unrealized gain (loss), tax benefit (expense)	$ 105	$ (1,781)	$ 67	$ 14,770
Reclassification of net realized loss, tax benefit	2,824	9,090	6,124	14,818
Pension and other postretirement benefits activity, tax expense (benefit)	$ (449)	$ 526	$ 182	$ 1,157

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
OPERATING EXPENSES
Fuel and purchased power	$ 277,584	$ 264,723	$ 508,263	$ 481,032
Operations and maintenance	229,300	216,236	452,550	426,899
Depreciation and amortization	106,292	100,606	210,022	200,715
Taxes other than income taxes	40,814	41,289	80,835	83,764
Total	656,010	624,087	1,255,739	1,196,711
OPERATING INCOME	259,812	254,489	346,735	302,496
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	6,265	5,175	13,129	9,931
Other income (Note S-2)	469	177	1,227	937
Other expense (Note S-2)	(2,234)	(2,669)	(5,986)	(6,737)
Total	4,500	2,683	8,370	4,131
INTEREST EXPENSE
Allowance for borrowed funds used during construction	(3,636)	(3,447)	(7,626)	(6,598)
Total	47,671	49,553	93,159	103,369
NET INCOME	139,598	130,111	172,434	129,630
Less: Net income attributable to noncontrolling interests (Note 6)	8,391	7,766	16,783	15,542
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	131,207	122,345	155,651	114,088
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	915,065	877,587	1,600,892	1,497,835
OPERATING EXPENSES
Fuel and purchased power	277,584	264,723	508,263	481,032
Operations and maintenance	224,950	213,746	445,702	422,193
Depreciation and amortization	106,268	100,583	209,974	200,668
Income taxes	81,952	80,696	98,012	79,882
Taxes other than income taxes	40,583	41,018	80,351	83,244
Total	731,337	700,766	1,342,302	1,267,019
OPERATING INCOME	183,728	176,821	258,590	230,816
OTHER INCOME (DEDUCTIONS)
Income taxes	3,100	2,030	5,432	3,736
Allowance for equity funds used during construction	6,265	5,175	13,129	9,931
Other income (Note S-2)	948	1,018	2,291	1,528
Other expense (Note S-2)	(4,844)	(3,993)	(11,140)	(8,617)
Total	5,469	4,230	9,712	6,578
INTEREST EXPENSE
Interest on long-term debt	47,543	48,838	93,764	101,575
Interest on short-term borrowings	1,968	1,914	3,397	3,949
Debt discount, premium and expense	982	1,052	1,993	2,112
Allowance for borrowed funds used during construction	(3,636)	(3,447)	(7,626)	(6,598)
Total	46,857	48,357	91,528	101,038
NET INCOME	142,340	132,694	176,774	136,356
Less: Net income attributable to noncontrolling interests (Note 6)	8,391	7,766	16,783	15,533
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 133,949	$ 124,928	$ 159,991	$ 120,823

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
OPERATING REVENUES	$ 915,822	$ 878,576	$ 1,602,474	$ 1,499,207
OPERATING EXPENSES
Fuel and purchased power	277,584	264,723	508,263	481,032
Operations and maintenance	229,300	216,236	452,550	426,899
Depreciation and amortization	106,292	100,606	210,022	200,715
Taxes other than income taxes	40,814	41,289	80,835	83,764
Other expenses	2,020	1,233	4,069	4,301
Total	656,010	624,087	1,255,739	1,196,711
OPERATING INCOME	259,812	254,489	346,735	302,496
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	6,265	5,175	13,129	9,931
Other income (Note 10)	469	177	1,227	937
Other expense (Note 10)	(2,234)	(2,669)	(5,986)	(6,737)
Total	4,500	2,683	8,370	4,131
INTEREST EXPENSE
Interest charges	51,307	53,000	100,785	109,967
Allowance for borrowed funds used during construction	(3,636)	(3,447)	(7,626)	(6,598)
Total	47,671	49,553	93,159	103,369
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	216,641	207,619	261,946	203,258
INCOME TAXES	77,043	76,689	89,512	72,044
INCOME FROM CONTINUING OPERATIONS	139,598	130,930	172,434	131,214
LOSS FROM DISCONTINUED OPERATIONS
Net of income tax benefit of $535 for three months ended June 30, 2012 and $1,040 for six months ended June 30, 2012		(819)		(1,584)
NET INCOME	139,598	130,111	172,434	129,630
Less: Net income attributable to noncontrolling interests (Note 6)	8,391	7,766	16,783	15,542
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	131,207	122,345	155,651	114,088
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	109,962	109,491	109,898	109,395
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	110,932	110,359	110,843	110,183
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders - basic (in dollars per share)	$ 1.19	$ 1.12	$ 1.42	$ 1.06
Net income attributable to common shareholders - basic (in dollars per share)	$ 1.19	$ 1.12	$ 1.42	$ 1.04
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)	$ 1.18	$ 1.12	$ 1.40	$ 1.05
Net income attributable to common shareholders - diluted (in dollars per share)	$ 1.18	$ 1.11	$ 1.40	$ 1.04
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 1.09	$ 1.05	$ 1.09	$ 1.575
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	131,207	123,164	155,651	115,681
Discontinued operations, net of tax		(819)		(1,593)
Net income attributable to common shareholders	$ 131,207	$ 122,345	$ 155,651	$ 114,088

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Commitments and Contingencies (Details 3) (ARIZONA PUBLIC SERVICE COMPANY, USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Four Corners
Environmental Matters
Expected environmental cost	$ 300
Navajo Plant
Environmental Matters
Expected environmental cost	158
Cholla
Environmental Matters
Expected environmental cost	187
Cholla Units 1-3
Environmental Matters
Expected environmental cost	$ 124

XML

Derivative Accounting (Tables)

6 Months Ended

Jun. 30, 2013

Derivative Accounting

Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)

As of June 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	7,668	gigawatt hours
Gas	129	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 June 30,						Six Months Ended June 30,
Commodity Contracts	Financial Statement Location	2013			2012			2013			2012
Gain (loss) recognized in OCI on derivative instruments (effective portion)	Other comprehensive income (loss) - derivative instruments	$	(265	)	$	4,509		$	(169	)	$	(37,394	)
Loss reclassified from accumulated other comprehensive income into income (effective portion realized) (a)	Fuel and purchased power (b)	(7,146		)	(23,015		)	(15,499		)	(37,515		)
Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)	Fuel and purchased power (b)	—			32			—			117

(a) During the three and six months ended June 30, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income (“AOCI”) to earnings related to discontinued cash flow hedges.  During the three and six months ended June 30, 2013,  we had no amounts 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

		Three Months Ended June 30,					Six Months Ended June 30,
Commodity Contracts	Financial Statement Location	2013			2012		2013			2012
Net gain (loss) recognized in income	Operating revenues (a)	$	322		$	87	$	205		$	(239	)
Net gain (loss) recognized in income	Fuel and purchased power expense (a)	(27,758		)	26,042		(10,408		)	990
Total		$	(27,436	)	$	26,129	$	(10,203	)	$	751

(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 June 30, 2013:(dollars in thousands)	Gross Recognized Derivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			Amount Reported on Balance Sheet
Current Assets	$	32,642		$	(10,669	)	$	21,973		$	602		$	22,575
Investments and Other Assets	34,486			(2,568		)	31,918			—			31,918
Total Assets	67,128			(13,237		)	53,891			602			54,493
Current Liabilities	(82,710		)	34,318			(48,392		)	(19,463		)	(67,855		)
Deferred Credits and Other	(93,093		)	7,619			(85,474		)	—			(85,474		)
Total Liabilities	(175,803		)	41,937			(133,866		)	(19,463		)	(153,329		)
Total	$	(108,675	)	$	28,700		$	(79,975	)	$	(18,861	)	$	(98,836	)

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

(b) Includes cash collateral provided to counterparties of $28,700.

(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 $602.

As of December 31, 2012:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
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 June 30, 2013 (dollars in millions):

	June 30, 2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	176
Cash Collateral Posted	29
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	116

(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

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Changes in Accumulated Other Comprehensive Loss

6 Months Ended

Jun. 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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,481	)	$	(63,450	)	$	(107,931	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
Other comprehensive loss before reclassifications	(160		)	(1,635		)	(1,795		)	(102		)	(1,635		)	(1,737		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	947		(b)	5,269			9,375		(a)	1,913		(b)	11,288
Net current period other comprehensive income (loss)	4,162			(688		)	3,474			9,273			278			9,551
Ending balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(40,319	)	$	(64,138	)	$	(104,457	)

(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.

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Derivative Accounting (Details)	Jun. 30, 2013 GW
Commodity - Power
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	7,668
Commodity - Gas
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	129,000
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%

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Fair Value Measurements (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Assets
Nuclear decommissioning trust	$ 595,231,000		$ 595,231,000		$ 570,625,000
Total assets	53,000,000		53,000,000		62,000,000
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	(53,000,000)	(58,000,000)	(48,000,000)	(51,000,000)
Total net gains (losses) realized/unrealized:
Included in earnings		1,000,000		2,000,000
Included in OCI		3,000,000		(2,000,000)
Deferred as a regulatory asset or liability	(4,000,000)	12,000,000	(5,000,000)	7,000,000
Settlements	4,000,000	(1,000,000)	2,000,000
Transfers into Level 3 from Level 2			(1,000,000)	2,000,000
Transfers from Level 3 into Level 2		(2,000,000)	(1,000,000)	(3,000,000)
Net derivative balance at end of period	(53,000,000)	(45,000,000)	(53,000,000)	(45,000,000)
Transfers in or out of Level 1 to or from any other hierarchy level			0
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash Equivalents	3,000,000		3,000,000		16,000,000
Nuclear decommissioning trust	111,000,000		111,000,000		110,000,000
Total assets	114,000,000		114,000,000		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	110,000,000		110,000,000		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	1,000,000		1,000,000		6,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Risk management activities-derivative instruments: Commodity Contracts	13,000,000		13,000,000		22,000,000
Nuclear decommissioning trust	490,000,000		490,000,000		465,000,000
Total assets	503,000,000		503,000,000		487,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(70,000,000)		(70,000,000)		(96,000,000)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Nuclear decommissioning trust	233,000,000		233,000,000		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	10,000,000		10,000,000		13,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	79,000,000		79,000,000		80,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	83,000,000		83,000,000		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		71,000,000		74,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Nuclear decommissioning trust	14,000,000		14,000,000		11,000,000
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Risk management activities-derivative instruments: Commodity Contracts	53,000,000		53,000,000		62,000,000
Total assets	53,000,000		53,000,000		62,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(106,000,000)		(106,000,000)		(110,000,000)
Fair value measurement on a recurring basis | Other
Assets
Risk management activities-derivative instruments: Commodity Contracts	(11,000,000)		(11,000,000)		(22,000,000)
Nuclear decommissioning trust	(6,000,000)		(6,000,000)		(4,000,000)
Total assets	(17,000,000)		(17,000,000)		(26,000,000)
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	23,000,000		23,000,000		47,000,000
Fair value measurement on a recurring basis | Other | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	(6,000,000)		(6,000,000)		(4,000,000)
Fair value measurement on a recurring basis | Fair Value
Assets
Cash Equivalents	3,000,000		3,000,000		16,000,000
Risk management activities-derivative instruments: Commodity Contracts	55,000,000		55,000,000		62,000,000
Nuclear decommissioning trust	595,000,000		595,000,000		571,000,000
Total assets	653,000,000		653,000,000		649,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(153,000,000)		(153,000,000)		(159,000,000)
Fair value measurement on a recurring basis | Fair Value | US commingled equity funds
Assets
Nuclear decommissioning trust	233,000,000		233,000,000		204,000,000
Fair value measurement on a recurring basis | Fair Value | U.S. Treasury
Assets
Nuclear decommissioning trust	110,000,000		110,000,000		104,000,000
Fair value measurement on a recurring basis | Fair Value | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	5,000,000		5,000,000		15,000,000
Fair value measurement on a recurring basis | Fair Value | Corporate debt
Assets
Nuclear decommissioning trust	79,000,000		79,000,000		80,000,000
Fair value measurement on a recurring basis | Fair Value | Mortgage-backed securities
Assets
Nuclear decommissioning trust	83,000,000		83,000,000		83,000,000
Fair value measurement on a recurring basis | Fair Value | Municipality bonds
Assets
Nuclear decommissioning trust	71,000,000		71,000,000		74,000,000
Fair value measurement on a recurring basis | Fair Value | Other
Assets
Nuclear decommissioning trust	$ 14,000,000		$ 14,000,000		$ 11,000,000

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Changes in Accumulated Other Comprehensive Loss (APSC)

6 Months Ended

Jun. 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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,481	)	$	(63,450	)	$	(107,931	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
Other comprehensive loss before reclassifications	(160		)	(1,635		)	(1,795		)	(102		)	(1,635		)	(1,737		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	947		(b)	5,269			9,375		(a)	1,913		(b)	11,288
Net current period other comprehensive income (loss)	4,162			(688		)	3,474			9,273			278			9,551
Ending balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(40,319	)	$	(64,138	)	$	(104,457	)

(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

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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,482	)	$	(38,621	)	$	(83,103	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
Other comprehensive loss before reclassifications	(160		)	(1,630		)	(1,790		)	(102		)	(1,630		)	(1,732		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	1,019		(b)	5,341			9,374		(a)	1,901		(b)	11,275
Net current period other comprehensive income (loss)	4,162			(611		)	3,551			9,272			271			9,543
Ending balance	$	(40,320	)	$	(39,232	)	$	(79,552	)	$	(40,320	)	$	(39,232	)	$	(79,552	)

(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.

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Regulatory Matters (Details 2) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Detail of regulatory assets
Regulatory assets, current	$ 106,000,000	$ 144,000,000
Regulatory assets, non-current	1,120,366,000	1,099,900,000
Pension and other postretirement benefits
Detail of regulatory assets
Regulatory assets, non-current	766,000,000	780,000,000
Income taxes allowance for funds used during construction (AFUDC) equity
Detail of regulatory assets
Regulatory assets, current	4,000,000	4,000,000
Regulatory assets, non-current	97,000,000	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	28,000,000	21,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	18,000,000	23,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	8,000,000	8,000,000
Regulatory assets, non-current	22,000,000	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	27,000,000	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	16,000,000	17,000,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000,000	2,000,000
Regulatory assets, non-current	18,000,000	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	31,000,000	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	8,000,000	13,000,000
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	14,000,000	7,000,000
Regulatory assets, non-current	1,000,000
Transmission cost adjustor
Detail of regulatory assets
Regulatory assets, current	13,000,000	10,000,000
Regulatory assets, non-current	3,000,000
Other
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	$ 17,000,000	$ 14,000,000

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Changes in Accumulated Other Comprehensive Loss (Tables)

6 Months Ended

Jun. 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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,481	)	$	(63,450	)	$	(107,931	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
Other comprehensive loss before reclassifications	(160		)	(1,635		)	(1,795		)	(102		)	(1,635		)	(1,737		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	947		(b)	5,269			9,375		(a)	1,913		(b)	11,288
Net current period other comprehensive income (loss)	4,162			(688		)	3,474			9,273			278			9,551
Ending balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(40,319	)	$	(64,138	)	$	(104,457	)

(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.

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Consolidation and Nature of Operations (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Cash Flows from Operating Activities
Deferred income taxes	$ 68,526	$ 61,109
Deferred investment tax credit	119,979	5,033	99,819
Deferred credits - other	191,259		183,835
Cash paid during the period for:
Income taxes, net of (refunds)	(9)	(649)
Interest, net of amounts capitalized	91,346	94,680
Significant non-cash investing and financing activities:
Accrued capital expenditures	8,904	14,745
Dividends accrued but not paid	59,946	57,479
As previously reported
Cash Flows from Operating Activities
Deferred income taxes		66,142
Deferred credits - other			283,654
Reclassifications
Cash Flows from Operating Activities
Deferred income taxes		(5,033)
Deferred investment tax credit		5,033	99,819
Deferred credits - other			$ (99,819)

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Income Taxes

6 Months Ended

Jun. 30, 2013

Income Taxes

Income Taxes

5. Income Taxes

The $71 million long-term income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  Subsequent to June 30, 2013, IRS guidance was released which provided clarification regarding the timing of this cash receipt.  As a result of the release of this guidance, the $71 million income tax receivable will be reclassified to short-term for the quarter ended September 30, 2013.  Additionally, as a result of this IRS guidance, it is possible that uncertain tax positions could decrease by approximately $65-$75 million within the next 12 months.  This decrease would be substantially offset by an increase in deferred tax liabilities.

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009.  We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

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 is expected to delay 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.  As of June 30, 2013, approximately $39 million of the $78 million in federal general business tax credit carryforwards have been reclassified to long-term deferred income taxes as they are no longer expected to be realized within the next twelve months.

As of June 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.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (APSC) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 172,434	$ 129,630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	249,482	239,743
Deferred fuel and purchased power	36,183	82,261
Deferred fuel and purchased power amortization	10,921	(54,388)
Allowance for equity funds used during construction	(13,129)	(9,931)
Deferred income taxes	68,526	61,109
Deferred investment tax credit	20,159	5,033
Change in derivative instruments fair value	349	(2,618)
Changes in current assets and liabilities:
Customer and other receivables	(79,408)	(21,424)
Accrued unbilled revenues	(68,763)	(43,211)
Materials, supplies and fossil fuel	(4,002)	(21,012)
Other current assets	(14,439)	(9,407)
Accounts payable	85,563	9,199
Accrued taxes and income taxes receivable - net	5,032	19,775
Other current liabilities	(26,098)	807
Change in margin and collateral accounts - assets	(1,111)	124
Change in margin and collateral accounts - liabilities	14,600	69,602
Change in other long-term assets	(23,796)	(1,692)
Change in other long-term liabilities	21,753	5,035
Net cash flow provided by operating activities	454,256	458,635
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(376,601)	(424,775)
Contributions in aid of construction	21,236	25,800
Allowance for borrowed funds used during construction	(7,626)	(6,598)
Proceeds from nuclear decommissioning trust sales	253,996	211,138
Investment in nuclear decommissioning trust	(262,621)	(219,762)
Other	(262)	(525)
Net cash flow used for investing activities	(371,878)	(414,722)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	351,081
Short-term borrowings - net	(62,075)	109,000
Repayment of long-term debt	(40,127)	(421,451)
Dividends paid on common stock	(116,231)	(111,297)
Noncontrolling interests	(9,197)	(2,630)
Net cash flow used for financing activities	(80,777)	(66,268)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,601	(22,355)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	26,202	33,583
CASH AND CASH EQUIVALENTS AT END OF PERIOD	27,803	11,228
Cash paid during the period for:
Interest, net of amounts capitalized	91,346	94,680
Significant non-cash investing and financing activities:
Accrued capital expenditures	8,904	14,745
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	176,774	136,356
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	249,434	239,696
Deferred fuel and purchased power	36,183	82,261
Deferred fuel and purchased power amortization	10,921	(54,388)
Allowance for equity funds used during construction	(13,129)	(9,931)
Deferred income taxes	66,947	64,639
Deferred investment tax credit	20,159	5,033
Change in derivative instruments fair value	349	(2,618)
Changes in current assets and liabilities:
Customer and other receivables	(80,854)	(23,015)
Accrued unbilled revenues	(68,763)	(43,211)
Materials, supplies and fossil fuel	(4,002)	(21,012)
Other current assets	(14,067)	(9,797)
Accounts payable	86,338	9,406
Accrued taxes and income taxes receivable - net	12,892	23,759
Other current liabilities	(28,506)	(3,095)
Change in margin and collateral accounts - assets	(1,111)	124
Change in margin and collateral accounts - liabilities	14,600	69,602
Change in other long-term assets	(21,658)	(2,456)
Change in other long-term liabilities	26,628	5,180
Net cash flow provided by operating activities	469,135	466,533
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(376,601)	(424,775)
Contributions in aid of construction	21,236	25,800
Allowance for borrowed funds used during construction	(7,626)	(6,598)
Proceeds from nuclear decommissioning trust sales	253,996	211,138
Investment in nuclear decommissioning trust	(262,621)	(219,762)
Other	(270)	(525)
Net cash flow used for investing activities	(371,886)	(414,722)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	351,081
Short-term borrowings - net	(62,075)	109,000
Repayment of long-term debt	(40,127)	(421,451)
Dividends paid on common stock	(119,700)	(104,900)
Noncontrolling interests	(9,197)	(2,630)
Net cash flow used for financing activities	(94,792)	(68,900)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2,457	(17,089)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,499	19,873
CASH AND CASH EQUIVALENTS AT END OF PERIOD	5,956	2,784
Cash paid during the period for:
Interest, net of amounts capitalized	89,676	92,473
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 8,904	$ 14,745

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Changes in Equity (Tables)

6 Months Ended

Jun. 30, 2013

Changes in Equity

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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,014,455		$	137,875		$	4,152,330		$	3,744,917		$	116,512		$	3,861,429
Net income	131,207			8,391			139,598			122,345			7,766			130,111
Other comprehensive income	3,474			—			3,474			17,459			—			17,459
Total comprehensive income	134,681			8,391			143,072			139,804			7,766			147,570
Issuance of capital stock	2,363			—			2,363			2,525			—			2,525
Reissuance of treasury stock — net	366			—			366			5,113			—			5,113
Other (primarily stock compensation)	185			—			185			631			—			631
Dividends on common stock	(119,885		)	—			(119,885		)	(114,955		)	—			(114,955		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
Net income	155,651			16,783			172,434			114,088			15,542			129,630
Other comprehensive income	9,551			—			9,551			1,845			—			1,845
Total comprehensive income	165,202			16,783			181,985			115,933			15,542			131,475
Issuance of capital stock	4,937			—			4,937			5,225			—			5,225
Reissuance (purchase) of treasury stock - net	(5,905		)	—			(5,905		)	3,359			—			3,359
Other (primarily stock compensation)	15,010			—			15,010			3,981			—			3,981
Dividends on common stock	(119,885		)	—			(119,885		)	(172,313		)	—			(172,313		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

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Income Taxes (Details) (USD $)	3 Months Ended	6 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2012
Income Taxes
Long-term income tax receivables		$ 71,274,000	$ 70,389,000
Income Tax Receivables		2,317,000	2,423,000
Income tax receivable that will be reclassified from long term to short-term	71,274,000
Decrease in uncertain tax positions lower bound		65,000,000
Decrease in uncertain tax positions upper bound		75,000,000
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 reclassified to long-term deferred income taxes		39,000,000
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		71,669,000	70,784,000
Income tax receivable that will be reclassified from long term to short-term	71,669,000
Decrease in uncertain tax positions lower bound		65,000,000
Decrease in uncertain tax positions upper bound		$ 75,000,000

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Changes in Equity

6 Months Ended

Jun. 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,014,455		$	137,875		$	4,152,330		$	3,744,917		$	116,512		$	3,861,429
Net income	131,207			8,391			139,598			122,345			7,766			130,111
Other comprehensive income	3,474			—			3,474			17,459			—			17,459
Total comprehensive income	134,681			8,391			143,072			139,804			7,766			147,570
Issuance of capital stock	2,363			—			2,363			2,525			—			2,525
Reissuance of treasury stock — net	366			—			366			5,113			—			5,113
Other (primarily stock compensation)	185			—			185			631			—			631
Dividends on common stock	(119,885		)	—			(119,885		)	(114,955		)	—			(114,955		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
Net income	155,651			16,783			172,434			114,088			15,542			129,630
Other comprehensive income	9,551			—			9,551			1,845			—			1,845
Total comprehensive income	165,202			16,783			181,985			115,933			15,542			131,475
Issuance of capital stock	4,937			—			4,937			5,225			—			5,225
Reissuance (purchase) of treasury stock - net	(5,905		)	—			(5,905		)	3,359			—			3,359
Other (primarily stock compensation)	15,010			—			15,010			3,981			—			3,981
Dividends on common stock	(119,885		)	—			(119,885		)	(172,313		)	—			(172,313		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

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Retirement Plans and Other Benefits

6 Months Ended

Jun. 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 as a regulatory asset for future recovery, pursuant to an ACC regulatory order.  We deferred pension and other postretirement benefit costs of approximately $5 million for the three months ended June 30, 2012, and approximately $14 million for the six months ended June 30, 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 June 30, 2013, and approximately $4 million for the six months ended June 30, 2013.  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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost - benefits earned during the period	$	15		$	15		$	32		$	32		$	6		$	6		$	12		$	14
Interest cost on benefit obligation	28			30			56			60			10			11			20			23
Expected return on plan assets	(36		)	(35		)	(73		)	(71		)	(12		)	(11		)	(23		)	(23		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	10			12			20			22			3			4			6			10
Net periodic benefit cost	$	17		$	22		$	36		$	44		$	7		$	10		$	15		$	24
Portion of cost charged to expense	$	9		$	8		$	19		$	13		$	4		$	3		$	9		$	6

Contributions

We have contributed $87 million to our pension plan year to date 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 voluntary contributions totaling $140 million to the pension plan in 2013, and contributions up to approximately $175 million in each of 2014 and 2015.  The contributions to our other postretirement benefit plans for 2013, 2014 and 2015 are expected to be approximately $20 million each year.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jun. 30, 2013	Dec. 31, 2012
EQUITY (Note 8)
Common stock, par value	$ 0.00	$ 0.00

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Other Income and Other Expense (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Other income:
Interest income	$ 467	$ 107	$ 1,176	$ 712
Miscellaneous	2	70	51	225
Total other income	469	177	1,227	937
Other expense:
Non-operating costs	(1,990)	(2,389)	(3,923)	(4,239)
Investment losses - net	(96)	(58)	(208)	(112)
Miscellaneous	(148)	(222)	(1,855)	(2,386)
Total other expense	$ (2,234)	$ (2,669)	$ (5,986)	$ (6,737)

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Derivative Accounting (Details 4) (Commodity Contracts, USD $)	6 Months Ended
	Jun. 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	86.00%
Risk management activities-derivative instruments: Commodity Contracts	$ 54,000,000
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	176,000,000
Cash Collateral Posted	29,000,000
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	116,000,000
Additional collateral to counterparties for energy related non-derivative instrument contracts	$ 174,000,000

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 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 June 30, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at June 30, 2013
Assets
Cash equivalents	$	3	$	—		$	—		$	—		$	3
Risk management activities — derivative instruments:
Commodity Contracts	—		13			53			(11		)(b)	55
Nuclear decommissioning trust:
U.S. commingled equity funds	—		233			—			—			233
Fixed income securities:
U.S. Treasury	110		—			—			—			110
Cash and cash equivalent funds	1		10			—			(6		)(c)	5
Corporate debt	—		79			—			—			79
Mortgage-backed securities	—		83			—			—			83
Municipality bonds	—		71			—			—			71
Other	—		14			—			—			14
Subtotal nuclear decommissioning trust	111		490			—			(6		)	595
Total	$	114	$	503		$	53		$	(17	)	$	653
Liabilities
Risk management activities — derivative instruments:	$	—	$	(70	)	$	(106	)	$	23	(b)	$	(153	)

(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 in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at December 31, 2012
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

The following tables provide information regarding our significant unobservable inputs used to value our Level 3 instruments at June 30, 2013 and December 31, 2012:

	June 30, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	53	$	76	Discounted cash flows	Electricity forward price (per MWh)	$24.77-$70.12	$	42.10
Option Contracts			27		Option model	Electricity forward price (per MWh)	$39.64-$84.73	$	58.26
						Implied electricity price volatilities	17%-98%	46		%
						Implied natural gas price volatilities	16%-32%	21		%
Natural Gas:
Forward Contracts (a)	—		3		Discounted cash flows	Natural gas forward price (per mmbtu)	$3.36-$3.36	$	3.36
Total	$	53	$	106

(a) Includes swaps and physical and financial contracts.

	December 31, 2012 Fair Value (millions)				Valuation	Significant		Weighted-
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	$	4.20
						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 six months ended June 30, 2013 and 2012 (dollars in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2013			2012			2013			2012
Net derivative balance at beginning of period	$	(53	)	$	(58	)	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			1			—			2
Included in OCI	—			3			—			(2		)
Deferred as a regulatory asset or liability	(4		)	12			(5		)	7
Settlements	4			(1		)	2			—
Transfers into Level 3 from Level 2	—			—			(1		)	2
Transfers from Level 3 into Level 2	—			(2		)	(1		)	(3		)
Net derivative balance at end of period	$	(53	)	$	(45	)	$	(53	)	$	(45	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

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Changes in Equity (APSC) (Tables)

6 Months Ended

Jun. 30, 2013

Changes in shareholder 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,014,455		$	137,875		$	4,152,330		$	3,744,917		$	116,512		$	3,861,429
Net income	131,207			8,391			139,598			122,345			7,766			130,111
Other comprehensive income	3,474			—			3,474			17,459			—			17,459
Total comprehensive income	134,681			8,391			143,072			139,804			7,766			147,570
Issuance of capital stock	2,363			—			2,363			2,525			—			2,525
Reissuance of treasury stock — net	366			—			366			5,113			—			5,113
Other (primarily stock compensation)	185			—			185			631			—			631
Dividends on common stock	(119,885		)	—			(119,885		)	(114,955		)	—			(114,955		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586
Net income	155,651			16,783			172,434			114,088			15,542			129,630
Other comprehensive income	9,551			—			9,551			1,845			—			1,845
Total comprehensive income	165,202			16,783			181,985			115,933			15,542			131,475
Issuance of capital stock	4,937			—			4,937			5,225			—			5,225
Reissuance (purchase) of treasury stock - net	(5,905		)	—			(5,905		)	3,359			—			3,359
Other (primarily stock compensation)	15,010			—			15,010			3,981			—			3,981
Dividends on common stock	(119,885		)	—			(119,885		)	(172,313		)	—			(172,313		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,976		)	(2,976		)
Ending balance, June 30	$	4,032,165		$	137,070		$	4,169,235		$	3,778,035		$	121,302		$	3,899,337

ARIZONA PUBLIC SERVICE COMPANY

Changes in shareholder 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, April 1	$	4,125,032		$	137,875		$	4,262,907		$	3,865,748		$	116,166		$	3,981,914
Net income	133,949			8,391			142,340			124,928			7,766			132,694
OCI	3,551			—			3,551			17,117			—			17,117
Total comprehensive income	137,500			8,391			145,891			142,045			7,766			149,811
Dividends on common stock	(119,800		)	—			(119,800		)	(105,000		)	—			(105,000		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,630		)	(2,630		)
Other	(6		)	—			(6		)	(2		)	—			(2		)
Ending balance, June 30	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, January 1	$	4,093,000		$	129,483		$	4,222,483		$	3,943,007		$	108,399		$	4,051,406
Net income	159,991			16,783			176,774			120,823			15,533			136,356
OCI	9,543			—			9,543			1,362			—			1,362
Total comprehensive income	169,534			16,783			186,317			122,185			15,533			137,718
Dividends on common stock	(119,800		)	—			(119,800		)	(162,400		)	—			(162,400		)
Net capital activities by noncontrolling interests	—			(9,196		)	(9,196		)	—			(2,630		)	(2,630		)
Other	(8		)	—			(8		)	(1		)	—			(1		)
Ending balance, June 30	$	4,142,726		$	137,070		$	4,279,796		$	3,902,791		$	121,302		$	4,024,093

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
NET INCOME	$ 139,598	$ 130,111	$ 172,434	$ 129,630
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $105 and $(1,781) for three months ended June 30, 2013 and 2012 and of $67 and $14,773 for six months ended June 30, 2013 and 2012	(160)	2,728	(102)	(22,624)
Reclassification of net realized loss, net of tax benefit of $2,824 and $9,092 for three months ended June 30, 2013 and 2012 and of $6,124 and $14,820 for six months ended June 30, 2013 and 2012	4,322	13,925	9,375	22,697
Pension and other postretirement benefits activity, net of tax benefit (expense) of $399 and $(305) for three months ended June 30, 2013 and 2012 and of $(177) and $(841) for six months ended June 30, 2013 and 2012	(688)	806	278	1,772
Total other comprehensive income	3,474	17,459	9,551	1,845
COMPREHENSIVE INCOME	143,072	147,570	181,985	131,475
Less: Comprehensive income attributable to noncontrolling interests	8,391	7,766	16,783	15,542
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	134,681	139,804	165,202	115,933
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	142,340	132,694	176,774	136,356
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $105 and $(1,781) for three months ended June 30, 2013 and 2012 and of $67 and $14,773 for six months ended June 30, 2013 and 2012	(160)	2,727	(102)	(22,621)
Reclassification of net realized loss, net of tax benefit of $2,824 and $9,092 for three months ended June 30, 2013 and 2012 and of $6,124 and $14,820 for six months ended June 30, 2013 and 2012	4,322	13,922	9,374	22,694
Pension and other postretirement benefits activity, net of tax benefit (expense) of $399 and $(305) for three months ended June 30, 2013 and 2012 and of $(177) and $(841) for six months ended June 30, 2013 and 2012	(611)	468	271	1,289
Total other comprehensive income	3,551	17,117	9,543	1,362
COMPREHENSIVE INCOME	145,891	149,811	186,317	137,718
Less: Comprehensive income attributable to noncontrolling interests	8,391	7,766	16,783	15,533
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 137,500	$ 142,045	$ 169,534	$ 122,185

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Earnings Per Share

6 Months Ended

Jun. 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 six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	1.19	$	1.12		$	1.42	$	1.06
Loss from discontinued operations	—		—			—		(0.02		)
Earnings per share — basic	$	1.19	$	1.12		$	1.42	$	1.04
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	1.18	$	1.12		$	1.40	$	1.05
Loss from discontinued operations	—		(0.01		)	—		(0.01		)
Earnings per share — diluted	$	1.18	$	1.11		$	1.40	$	1.04

Performance shares and restricted stock units (which are contingently issuable) increased the weighted average common shares outstanding by approximately 970,000 shares and 868,000 shares for the three months ended June 30, 2013 and 2012, respectively, and by approximately 945,000 shares and 788,000 shares for the six months ended June 30, 2013 and 2012, respectively.

For the three and six months ended June 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.

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Derivative Accounting

6 Months Ended

Jun. 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 relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 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 June 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	7,668	gigawatt hours
Gas	129	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 June 30,						Six Months Ended June 30,
Commodity Contracts	Financial Statement Location	2013			2012			2013			2012
Gain (loss) recognized in OCI on derivative instruments (effective portion)	Other comprehensive income (loss) - derivative instruments	$	(265	)	$	4,509		$	(169	)	$	(37,394	)
Loss reclassified from accumulated other comprehensive income into income (effective portion realized) (a)	Fuel and purchased power (b)	(7,146		)	(23,015		)	(15,499		)	(37,515		)
Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)	Fuel and purchased power (b)	—			32			—			117

(a) During the three and six months ended June 30, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income (“AOCI”) to earnings related to discontinued cash flow hedges.  During the three and six months ended June 30, 2013,  we had no amounts 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 $37 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 six months ended June 30, 2013 and 2012 (dollars in thousands):

		Three Months Ended June 30,					Six Months Ended June 30,
Commodity Contracts	Financial Statement Location	2013			2012		2013			2012
Net gain (loss) recognized in income	Operating revenues (a)	$	322		$	87	$	205		$	(239	)
Net gain (loss) recognized in income	Fuel and purchased power expense (a)	(27,758		)	26,042		(10,408		)	990
Total		$	(27,436	)	$	26,129	$	(10,203	)	$	751

(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 June 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.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2013:(dollars in thousands)	Gross Recognized Derivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			Amount Reported on Balance Sheet
Current Assets	$	32,642		$	(10,669	)	$	21,973		$	602		$	22,575
Investments and Other Assets	34,486			(2,568		)	31,918			—			31,918
Total Assets	67,128			(13,237		)	53,891			602			54,493
Current Liabilities	(82,710		)	34,318			(48,392		)	(19,463		)	(67,855		)
Deferred Credits and Other	(93,093		)	7,619			(85,474		)	—			(85,474		)
Total Liabilities	(175,803		)	41,937			(133,866		)	(19,463		)	(153,329		)
Total	$	(108,675	)	$	28,700		$	(79,975	)	$	(18,861	)	$	(98,836	)

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

(b) Includes cash collateral provided to counterparties of $28,700.

(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 $602.

As of December 31, 2012:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
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 86% of Pinnacle West’s $54 million of risk management assets as of June 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 June 30, 2013 (dollars in millions):

	June 30, 2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	176
Cash Collateral Posted	29
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	116

(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 $174 million if our debt credit ratings were to fall below investment grade.

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Changes in Accumulated Other Comprehensive Loss (APSC) (Tables)

6 Months Ended

Jun. 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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,481	)	$	(63,450	)	$	(107,931	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
Other comprehensive loss before reclassifications	(160		)	(1,635		)	(1,795		)	(102		)	(1,635		)	(1,737		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	947		(b)	5,269			9,375		(a)	1,913		(b)	11,288
Net current period other comprehensive income (loss)	4,162			(688		)	3,474			9,273			278			9,551
Ending balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(40,319	)	$	(64,138	)	$	(104,457	)

(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 six months ended June 30, 2013 (dollars in thousands):

	Three Months Ended June 30, 2013									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance	$	(44,482	)	$	(38,621	)	$	(83,103	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
Other comprehensive loss before reclassifications	(160		)	(1,630		)	(1,790		)	(102		)	(1,630		)	(1,732		)
Amounts reclassified from accumulated other comprehensive loss	4,322		(a)	1,019		(b)	5,341			9,374		(a)	1,901		(b)	11,275
Net current period other comprehensive income (loss)	4,162			(611		)	3,551			9,272			271			9,543
Ending balance	$	(40,320	)	$	(39,232	)	$	(79,552	)	$	(40,320	)	$	(39,232	)	$	(79,552	)

(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.

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New Accounting Standards

6 Months Ended

Jun. 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.

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Fair Value Measurements

6 Months Ended

Jun. 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 June 30, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at June 30, 2013
Assets
Cash equivalents	$	3	$	—		$	—		$	—		$	3
Risk management activities — derivative instruments:
Commodity Contracts	—		13			53			(11		)(b)	55
Nuclear decommissioning trust:
U.S. commingled equity funds	—		233			—			—			233
Fixed income securities:
U.S. Treasury	110		—			—			—			110
Cash and cash equivalent funds	1		10			—			(6		)(c)	5
Corporate debt	—		79			—			—			79
Mortgage-backed securities	—		83			—			—			83
Municipality bonds	—		71			—			—			71
Other	—		14			—			—			14
Subtotal nuclear decommissioning trust	111		490			—			(6		)	595
Total	$	114	$	503		$	53		$	(17	)	$	653
Liabilities
Risk management activities — derivative instruments:	$	—	$	(70	)	$	(106	)	$	23	(b)	$	(153	)

(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 in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at December 31, 2012
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 implied volatilities.  If electricity prices and electricity price implied 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 implied 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 implied 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 June 30, 2013 and December 31, 2012:

	June 30, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	53	$	76	Discounted cash flows	Electricity forward price (per MWh)	$24.77-$70.12	$	42.10
Option Contracts			27		Option model	Electricity forward price (per MWh)	$39.64-$84.73	$	58.26
						Implied electricity price volatilities	17%-98%	46		%
						Implied natural gas price volatilities	16%-32%	21		%
Natural Gas:
Forward Contracts (a)	—		3		Discounted cash flows	Natural gas forward price (per mmbtu)	$3.36-$3.36	$	3.36
Total	$	53	$	106

(a) Includes swaps and physical and financial contracts.

	December 31, 2012 Fair Value (millions)				Valuation	Significant		Weighted-
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	$	4.20
						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 six months ended June 30, 2013 and 2012 (dollars in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2013			2012			2013			2012
Net derivative balance at beginning of period	$	(53	)	$	(58	)	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			1			—			2
Included in OCI	—			3			—			(2		)
Deferred as a regulatory asset or liability	(4		)	12			(5		)	7
Settlements	4			(1		)	2			—
Transfers into Level 3 from Level 2	—			—			(1		)	2
Transfers from Level 3 into Level 2	—			(2		)	(1		)	(3		)
Net derivative balance at end of period	$	(53	)	$	(45	)	$	(53	)	$	(45	)
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.

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2013	Jul. 29, 2013
Document and Entity Information
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	0000764622
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		109,996,850
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2

XML

Nuclear Decommissioning Trusts

6 Months Ended

Jun. 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 June 30, 2013 and December 31, 2012 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2013
Equity securities	$	233		$	93	$	—
Fixed income securities	368			14		(6		)
Net payables (a)	(6		)	—		—
Total	$	595		$	107	$	(6	)

(a) Net payables relate to pending securities sales and purchases.

	Fair Value			Total Unrealized Gains		Total Unrealized 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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized gains	$	1		$	2		$	3		$	4
Realized losses	(1		)	(1		)	(2		)	(2		)
Proceeds from the sale of securities (a)	119			119			254			211

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2013 is as follows (dollars in millions):

	Fair Value
Less than one year	$		11
1 year - 5 years	106
5 years - 10 years	100
Greater than 10 years	151
Total	$	368

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CONDENSED CONSOLIDATED BALANCE SHEETS (APSC) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$ 14,503,810	$ 14,346,367
Accumulated depreciation and amortization	(5,022,729)	(4,929,613)
Net	9,481,081	9,416,754
Construction work in progress	545,231	565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	127,060	128,995
Intangible assets, net of accumulated amortization	162,715	162,150
Nuclear fuel, net of accumulated amortization	156,252	122,778
Total property, plant and equipment	10,472,339	10,396,393
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	595,231	570,625
Assets from risk management activities (Note 7)	31,918	35,891
Other assets	64,304	62,694
Total investments and other assets	691,453	669,210
CURRENT ASSETS
Cash and cash equivalents	27,803	26,202
Customer and other receivables	345,581	277,225
Accrued unbilled revenues	163,608	94,845
Allowance for doubtful accounts	(2,821)	(3,340)
Materials and supplies (at average cost)	220,025	218,096
Fossil fuel (at average cost)	33,407	31,334
Deferred fuel and purchased power regulatory asset (Note 3)	26,526	72,692
Other regulatory assets (Note 3)	79,405	71,257
Deferred income taxes	105,146	152,191
Assets from risk management activities (Note 7)	22,575	25,699
Other current assets	42,717	37,102
Total current assets	1,066,289	1,005,726
DEFERRED DEBITS
Regulatory assets (Note 3)	1,120,366	1,099,900
Income tax receivable (Note 5)	71,274	70,389
Other	140,973	137,997
Total deferred debits	1,332,613	1,308,286
TOTAL ASSETS	13,562,694	13,379,615
CAPITALIZATION
Common stock	2,476,754	2,462,712
Retained earnings	1,659,868	1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(64,138)	(64,416)
Derivative instruments	(40,319)	(49,592)
Total shareholders' equity	4,032,165	3,972,806
Noncontrolling interests (Note 6)	137,070	129,483
Total equity	4,169,235	4,102,289
Long-term debt less current maturities (Note 2)	2,782,758	3,160,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414	38,869
CURRENT LIABILITIES
Short-term borrowings	30,100	92,175
Current maturities of long-term debt (Note 2)	599,131	122,828
Accounts payable	287,368	221,312
Accrued taxes (Note 5)	129,865	124,939
Accrued interest	49,199	49,380
Common dividends payable	59,946	59,789
Customer deposits	78,795	79,689
Liabilities from risk management activities (Note 7)	67,855	73,741
Regulatory liabilities (Note 3)	80,763	88,116
Other current liabilities	154,196	171,573
Total current liabilities	1,537,218	1,083,542
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,175,865	2,151,371
Regulatory liabilities (Note 3)	790,788	759,201
Liability for asset retirements	362,619	357,097
Liabilities for pension and other postretirement benefits (Note 4)	1,013,976	1,058,755
Deferred investment tax credit	119,979	99,819
Liabilities from risk management activities (Note 7)	85,474	85,264
Customer advances	108,335	109,359
Coal mine reclamation	115,145	118,860
Unrecognized tax benefits (Note 5)	72,629	71,135
Other	191,259	183,835
Total deferred credits and other	5,036,069	4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	13,562,694	13,379,615
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,499,944	14,342,501
Accumulated depreciation and amortization	(5,019,059)	(4,925,990)
Net	9,480,885	9,416,511
Construction work in progress	545,231	565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	127,060	128,995
Intangible assets, net of accumulated amortization	162,560	161,995
Nuclear fuel, net of accumulated amortization	156,252	122,778
Total property, plant and equipment	10,471,988	10,395,995
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	595,231	570,625
Assets from risk management activities (Note 7)	31,918	35,891
Other assets	31,912	31,650
Total investments and other assets	659,061	638,166
CURRENT ASSETS
Cash and cash equivalents	5,956	3,499
Customer and other receivables	344,617	274,815
Accrued unbilled revenues	163,608	94,845
Allowance for doubtful accounts	(2,821)	(3,340)
Materials and supplies (at average cost)	220,025	218,096
Fossil fuel (at average cost)	33,407	31,334
Deferred fuel and purchased power regulatory asset (Note 3)	26,526	72,692
Other regulatory assets (Note 3)	79,405	71,257
Deferred income taxes	86,219	74,420
Assets from risk management activities (Note 7)	22,575	25,699
Other current assets	42,320	37,666
Total current assets	1,021,837	900,983
DEFERRED DEBITS
Regulatory assets (Note 3)	1,120,366	1,099,900
Unamortized debt issue costs	22,718	22,492
Income tax receivable (Note 5)	71,669	70,784
Other	117,123	114,222
Total deferred debits	1,331,876	1,307,398
TOTAL ASSETS	13,484,762	13,242,542
CAPITALIZATION
Common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,664,420	1,624,237
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(39,232)	(39,503)
Derivative instruments	(40,320)	(49,592)
Total shareholders' equity	4,142,726	4,093,000
Noncontrolling interests (Note 6)	137,070	129,483
Total equity	4,279,796	4,222,483
Long-term debt less current maturities (Note 2)	2,657,758	3,035,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414	38,869
Total capitalization	6,974,968	7,296,571
CURRENT LIABILITIES
Short-term borrowings	30,100	92,175
Current maturities of long-term debt (Note 2)	599,131	122,828
Accounts payable	282,408	215,577
Accrued taxes (Note 5)	129,003	116,700
Accrued interest	48,993	49,135
Common dividends payable	59,900	59,800
Customer deposits	78,795	79,689
Liabilities from risk management activities (Note 7)	67,855	73,741
Regulatory liabilities (Note 3)	80,763	88,116
Other current liabilities	125,501	145,326
Total current liabilities	1,502,449	1,043,087
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,215,730	2,133,976
Regulatory liabilities (Note 3)	790,788	759,201
Liability for asset retirements	362,619	357,097
Liabilities for pension and other postretirement benefits (Note 4)	974,877	1,017,556
Deferred investment tax credit	119,979	99,819
Liabilities from risk management activities (Note 7)	85,474	85,264
Customer advances	108,335	109,359
Coal mine reclamation	115,145	118,860
Unrecognized tax benefits (Note 5)	72,423	70,932
Other	161,975	150,820
Total deferred credits and other	5,007,345	4,902,884
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$ 13,484,762	$ 13,242,542

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Net unrealized gain (loss), tax benefit (expense)	$ 105	$ (1,781)	$ 67	$ 14,770
Reclassification of net realized loss, tax benefit	2,824	9,090	6,124	14,818
Pension and other postretirement benefits activity, tax expense (benefit)	(449)	526	182	1,157
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized gain (loss), tax benefit (expense)	105	(1,781)	67	14,773
Reclassification of net realized loss, tax benefit	2,824	9,092	6,124	14,820
Pension and other postretirement benefits activity, tax expense (benefit)	$ (399)	$ 305	$ 177	$ 841