10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

OR

oTRANSITION 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 Exchange Act Rule 12b-2).

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 27, 2012: 109,543,792
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of July 27, 2012: 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	43
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	72
	Item 4.	Controls and Procedures	72
Part II			73
	Item 1.	Legal Proceedings	73
	Item 1A.	Risk Factors	73
	Item 5.	Other Information	73
	Item 6.	Exhibits	78
Signatures			81

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, 2011 (“2011 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 operation 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 and nuclear plant operations;

·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 2011 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,
	2012			2011
OPERATING REVENUES	$	878,576		$	799,799
OPERATING EXPENSES
Fuel and purchased power	264,723			244,049
Operations and maintenance	216,236			210,590
Depreciation and amortization	100,606			106,617
Taxes other than income taxes	41,289			40,155
Other expenses	1,233			1,396
Total	624,087			602,807
OPERATING INCOME	254,489			196,992
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,175			5,924
Other income (Note 11)	177			557
Other expense (Note 11)	(2,669		)	(3,186		)
Total	2,683			3,295
INTEREST EXPENSE
Interest charges	53,000			60,140
Allowance for borrowed funds used during construction	(3,447		)	(3,856		)
Total	49,553			56,284
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	207,619			144,003
INCOME TAXES	76,689			50,818
INCOME FROM CONTINUING OPERATIONS	130,930			93,185
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(535) and $773 (Note 13)	(819		)	654
NET INCOME	130,111			93,839
Less: Net income attributable to noncontrolling interests (Note 7)	7,766			7,154
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	122,345		$	86,685
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,491			109,044
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,359			109,718
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	1.12		$	0.79
Net income attributable to common shareholders — basic	1.12			0.80
Income from continuing operations attributable to common shareholders — diluted	1.12			0.78
Net income attributable to common shareholders — diluted	1.11			0.79
DIVIDENDS DECLARED PER SHARE	$	1.05		$	1.05
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	123,164		$	86,001
Discontinued operations, net of tax	(819		)	684
Net income attributable to common shareholders	$	122,345		$	86,685

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,
	2012		2011
NET INCOME	$	130,111	$	93,839
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(1,781) and $6,448	2,728		(9,875		)
Reclassification of net realized loss, net of tax benefit of $9,090 and $9,988	13,925		15,299
Pension and other postretirement benefits activity, net of tax expense of $526 and $797	806		1,222
Total other comprehensive income	17,459		6,646
COMPREHENSIVE INCOME	147,570		100,485
Less: Comprehensive income attributable to noncontrolling interests	7,766		7,154
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	139,804	$	93,331

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,
	2012			2011
OPERATING REVENUES	$	1,499,207		$	1,448,646
OPERATING EXPENSES
Fuel and purchased power	481,032			456,056
Operations and maintenance	426,899			465,619
Depreciation and amortization	200,715			213,200
Taxes other than income taxes	83,764			77,779
Other expenses	4,301			3,216
Total	1,196,711			1,215,870
OPERATING INCOME	302,496			232,776
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	9,931			11,319
Other income (Note 11)	937			2,247
Other expense (Note 11)	(6,737		)	(4,927		)
Total	4,131			8,639
INTEREST EXPENSE
Interest charges	109,967			121,217
Allowance for borrowed funds used during construction	(6,598		)	(7,432		)
Total	103,369			113,785
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	203,258			127,630
INCOME TAXES	72,044			44,813
INCOME FROM CONTINUING OPERATIONS	131,214			82,817
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(1,040) and $906 (Note 13)	(1,584		)	1,348
NET INCOME	129,630			84,165
Less: Net income attributable to noncontrolling interests (Note 7)	15,542			12,615
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	114,088		$	71,550
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,395			108,939
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,183			109,540
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	1.06		$	0.64
Net income attributable to common shareholders — basic	1.04			0.66
Income from continuing operations attributable to common shareholders — diluted	1.05			0.64
Net income attributable to common shareholders — diluted	1.04			0.65
DIVIDENDS DECLARED PER SHARE	$	1.575		$	1.575
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	115,681		$	70,163
Discontinued operations, net of tax	(1,593		)	1,387
Net income attributable to common shareholders	$	114,088		$	71,550

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,
	2012			2011
NET INCOME	$	129,630		$	84,165
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $14,770 and $6,058	(22,624		)	(9,277		)
Reclassification of net realized loss, net of tax benefit of $14,818 and $15,852	22,697			24,281
Pension and other postretirement benefits activity, net of tax expense of $1,157 and $1,363	1,772			2,088
Total other comprehensive income	1,845			17,092
COMPREHENSIVE INCOME	131,475			101,257
Less: Comprehensive income attributable to noncontrolling interests	15,542			12,615
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	115,933		$	88,642

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, 2012			December 31, 2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	11,228		$	33,583
Customer and other receivables	316,722			284,183
Accrued unbilled revenues	168,450			125,239
Allowance for doubtful accounts	(3,302		)	(3,748		)
Materials and supplies (at average cost)	217,222			204,387
Fossil fuel (at average cost)	30,177			22,000
Deferred income taxes	87,690			130,571
Income tax receivable (Note 6)	885			6,466
Assets from risk management activities (Note 8)	29,991			30,264
Deferred fuel and purchased power regulatory asset (Note 3)	—			27,549
Other regulatory assets (Note 3)	54,857			69,072
Other current assets	33,496			26,904
Total current assets	947,416			956,470
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)	43,526			49,322
Nuclear decommissioning trust (Note 15)	544,933			513,733
Other assets	64,800			64,588
Total investments and other assets	653,259			627,643
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,048,957			13,753,971
Accumulated depreciation and amortization	(4,843,868		)	(4,709,991		)
Net	9,205,089			9,043,980
Construction work in progress	458,441			496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	130,929			132,864
Intangible assets, net of accumulated amortization	163,727			170,571
Nuclear fuel, net of accumulated amortization	159,493			118,098
Total property, plant and equipment	10,117,679			9,962,258
DEFERRED DEBITS
Regulatory assets (Note 3)	1,283,322			1,352,079
Income tax receivable (Note 6)	69,508			68,633
Other	143,223			143,935
Total deferred debits	1,496,053			1,564,647
TOTAL ASSETS	$	13,214,407		$	13,111,018

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, 2012			December 31, 2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	316,329		$	326,987
Accrued taxes (Note 6)	133,766			120,289
Accrued interest	61,451			54,872
Common dividends payable	57,479			—
Short-term borrowings	109,000			—
Current maturities of long-term debt	57,962			477,435
Customer deposits	74,575			72,176
Liabilities from risk management activities (Note 8)	64,442			53,968
Deferred fuel and purchased power regulatory liability (Note 3)	325			—
Other regulatory liabilities (Note 3)	89,433			88,362
Other current liabilities	139,561			148,616
Total current liabilities	1,104,323			1,342,705
LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities	3,313,992			2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	57,420			65,547
Total long-term debt less current maturities	3,371,412			3,019,054
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,946,540			1,925,388
Regulatory liabilities (Note 3)	738,693			737,332
Liability for asset retirements	289,641			279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,243,256			1,268,910
Liabilities from risk management activities (Note 8)	108,554			82,495
Customer advances	111,655			116,805
Coal mine reclamation	118,374			117,896
Unrecognized tax benefits (Note 6)	72,977			72,270
Other	209,645			217,934
Total deferred credits and other	4,839,335			4,818,673
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 9)
Common stock, no par value	2,453,453			2,444,247
Treasury stock	(1,359		)	(4,717		)
Total common stock	2,452,094			2,439,530
Retained earnings	1,476,259			1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(63,675		)	(65,447		)
Derivative instruments	(86,643		)	(86,716		)
Total accumulated other comprehensive loss	(150,318		)	(152,163		)
Total shareholders’ equity	3,778,035			3,821,850
Noncontrolling interests (Note 7)	121,302			108,736
Total equity	3,899,337			3,930,586
TOTAL LIABILITIES AND EQUITY	$	13,214,407		$	13,111,018

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,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	129,630		$	84,165
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	239,743			245,700
Deferred fuel and purchased power	82,261			64,679
Deferred fuel and purchased power amortization	(54,388		)	(68,762		)
Allowance for equity funds used during construction	(9,931		)	(11,319		)
Deferred income taxes	66,142			11,945
Change in derivative instruments fair value	(2,618		)	(279		)
Changes in current assets and liabilities:
Customer and other receivables	(21,424		)	43,271
Accrued unbilled revenues	(43,211		)	(60,390		)
Materials, supplies and fossil fuel	(21,012		)	(18,226		)
Other current assets	(9,407		)	(37,053		)
Accounts payable	9,199			37,817
Accrued taxes and income tax receivable — net	19,775			29,530
Other current liabilities	807			3,967
Change in margin and collateral accounts — assets	124			21,185
Change in margin and collateral accounts — liabilities	69,602			39,567
Change in unrecognized tax benefits	—			18,959
Change in other long-term assets	(1,692		)	(26,225		)
Change in other long-term liabilities	5,035			57,748
Net cash flow provided by operating activities	458,635			436,279
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(424,775		)	(387,272		)
Contributions in aid of construction	25,800			21,905
Allowance for borrowed funds used during construction	(6,598		)	(7,432		)
Proceeds from nuclear decommissioning trust sales	211,138			299,600
Investment in nuclear decommissioning trust	(219,762		)	(308,222		)
Proceeds from sale of life insurance policies	—			55,444
Other	(525		)	(2,352		)
Net cash flow used for investing activities	(414,722		)	(328,329		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081			175,000
Repayment of long-term debt	(421,451		)	(187,962		)
Short-term borrowings and payments — net	109,000			(9,300		)
Dividends paid on common stock	(111,297		)	(112,537		)
Common stock equity issuance	8,869			14,520
Distributions to noncontrolling interests	(2,630		)	(2,610		)
Other	160			(2,975		)
Net cash flow used for financing activities	(66,268		)	(125,864		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(22,355		)	(17,914		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	33,583			110,188
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	11,228		$	92,274
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	(649	)	$	—
Interest, net of amounts capitalized	$	94,680		$	110,659

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”) and APS Energy Services Company, Inc. (“APSES”).  See Note 13 for discussion of the bankruptcy filing of SunCor and the sale of APSES.  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 7 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 2011 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

See Note 16 for discussion of amended guidance on the presentation of comprehensive income.

The following tables show the impact of the reclassifications to prior year (previously reported) amounts (dollars in thousands):

10

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Statement of Income for the Three Months Ended June 30, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	798,669	$	(798,669	)	$	—
Other revenues	1,130		(1,130		)	—
Operating revenues	—		799,799			799,799

Statement of Income for the Six Months Ended June 30, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	1,446,643	$	(1,446,643	)	$	—
Other revenues	2,003		(2,003		)	—
Operating revenues	—		1,448,646			1,448,646

Statement of Cash Flows for the Six Months Ended June 30, 2011	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Expenditures for real estate investments	$	(40	)	$	40		$	—
Change in other long-term assets	(26,185		)	(40		)	(26,225		)

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, 2012, 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, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

11

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS

On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029.  On June 1, 2012 we remarketed these bonds.  Currently, the interest rate on these bonds is reset daily by a remarketing agent.  The daily rate at June 30, 2012 was 0.17%.  Additionally, the bonds are supported by a letter of credit.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A.  The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014.  During this time, the bonds will bear interest at a rate of 1.25% per annum.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

At June 30, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, 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, 2012, APS had commercial paper borrowings of $109 million, and no outstanding borrowings or letters of credit under these facilities.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 14 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, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	123	$	125	$	123
APS	3,304		3,794		3,371		3,803
Total	$	3,429	$	3,917	$	3,496	$	3,926

Debt Provisions

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, 2012, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $3.9 billion, and total capitalization was approximately $7.1 billion.  APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $2.8 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 or ability to pay dividends to shareholders.

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 APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have 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 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.

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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 current 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 currently exists in the PSA to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

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·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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million.  On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million.  Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 megawatts (“MW”) under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015.  In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications.  Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $92.8 million to $102.4 million.  The budget range stems from options related to distributed energy; if the ACC decides to promote more distributed energy by selecting the higher budget, APS requested that the 2013 incentives for photovoltaic distributed energy begin at $0.20 and step down gradually based upon market participation.  APS’s filing also proposed a system of establishing compliance with distributed energy requirements that depends upon tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  Further, APS described its Community Solar program, a utility-owned 25 MW program that will be split into 3 to 7 separate projects throughout communities in APS’s service territory (this is the 25 MW program described in clause (iv) of the preceding paragraph).  APS expects a decision from the ACC around year end.

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.  In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand side management programs over the current year.  Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis.  The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives.

The ACC previously approved recovery of all 2009 program costs plus incentives.  The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2008 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery.  As requested by APS, 2009 program cost recovery is to be amortized over a three-year period, which ends in 2012.

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 over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates.

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On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later this year, APS intends to file a supplement to its plan that will include a proposed budget for 2013.

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2012 and 2011 (dollars in millions):

	Six Months Ended June 30,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(82		)	(65		)
Amounts refunded through revenues	54			69
Ending balance	$	—		$	(54	)

The PSA rate for the PSA year beginning February 1, 2012 is negative $0.0042 per kWh as compared to negative $0.0057 per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

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-collected amounts.

Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning

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June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula.  Approximately $38 million of this revenue increase relates to Retail Transmission Charges.  The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

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.  Because of higher relative system demand by APS’s retail customers, the approximately $16 million increase roughly reflects a $2 million decrease for wholesale customers and an $18 million increase for APS retail customers.

On May 14, 2012, APS filed an application with the ACC to implement the FERC-approved transmission rates for retail customers.  On July 18, 2012, the ACC approved the application authorizing the implementation of the FERC-approved transmission rates for retail customers to be effective beginning in August 2012.

Regulatory Assets and Liabilities

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

	June 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	954	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		85		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	18		35		43		34
Transmission vegetation management	9		27		9		32
Coal reclamation	8		28		2		35
Palo Verde VIEs (Note 7)	—		37		—		35
Deferred compensation	—		34		—		33
Deferred fuel and purchased power (a)	—		—		28		—
Tax expense of Medicare subsidy	2		18		2		18
Loss on reacquired debt	1		19		1		19
Income taxes — investment tax credit basis adjustment	1		16		—		15
Pension and other postretirement benefits deferral	8		17		—		12
Demand side management (a)	4		—		7		1
Other	1		13		2		14
Total regulatory assets (b)	$	55	$	1,283	$	97	$	1,352

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

(b)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):

	June 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	25	$	340	$	22	$	349
Asset retirement obligations	—		240		—		225
Renewable energy standard (b)	46		—		54		—
Income taxes — change in rates	—		60		—		59
Spent nuclear fuel	9		38		5		44
Deferred gains on utility property	3		13		2		14
Income taxes- deferred investment tax credit	1		33		1		30
Other	6		15		4		16
Total regulatory liabilities	$	90	$	739	$	88	$	737

(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 are 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 and $3 million for the three months ended June 30, 2012 and 2011, respectively, and approximately $14 million and $6 million for the six months ended June 30, 2012 and 2011, respectively.  The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged 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,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost - benefits earned during the period	$	15		$	13		$	32		$	29		$	6		$	5		$	14		$	11
Interest cost on benefit obligation	30			31			60			62			11			12			23			23
Expected return on plan assets	(35		)	(33		)	(71		)	(67		)	(11		)	(11		)	(23		)	(21		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	12			7			22			13			4			4			10			8
Net periodic benefit cost	$	22		$	18		$	44		$	38		$	10		$	10		$	24		$	21
Portion of cost charged to expense	$	8		$	7		$	13		$	15		$	3		$	4		$	6		$	8

Contributions

We expect to contribute to our pension plan approximately $65 million in 2012 (of which $15 million was contributed in July 2012), approximately $150 million in 2013 and approximately $160 million in 2014.  The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year.

5.Business Segments

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.

Financial data for the three and six months ended June 30, 2012 and 2011 and at June 30, 2012 and December 31, 2011 is provided as follows (dollars in millions):

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Operating revenues:
Regulated electricity segment	$	878		$	799	$	1,498		$	1,447
All other	1			1		1			2
Total	$	879		$	800	$	1,499		$	1,449
Net income attributable to common shareholders:
Regulated electricity segment	$	123		$	86	$	117		$	71
All other (a)	(1		)	1		(3		)	1
Total	$	122		$	87	$	114		$	72

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	As of June 30, 2012		As of December 31, 2011
Assets:
Regulated electricity segment	$	13,178	$	13,068
All other (a)	36		43
Total	$	13,214	$	13,111

(a)All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.  See Note 13 for discussion of discontinued operations.

6.Income Taxes

The $70 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.  This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt.  Further clarification of the timing is expected from the IRS within the next twelve months.

Net Income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 7).  As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.

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.  At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made.  However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.

As of June 30, 2012, 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 2007.

7.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 2012 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 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, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

	June 30, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	131	$	133
Current maturities of long-term debt	26		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	57		66
Equity — Noncontrolling interests	121		108

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, 2012, APS would have been required to pay the noncontrolling equity participants approximately $142 million and assume $83 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.

8.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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 that the forecasted transaction is no longer probable of occurring.  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 14 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

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

Prior to the recent 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 recent 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2012, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	9,914	gigawatt hours
Gas	178	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 during the three and six months ended June 30, 2012 and 2011 (dollars in thousands).  As cash flow hedge accounting treatment was discontinued for the significant majority of our contracts on June 1, 2012, the table below reflects activity occurring prior to that date:

		Three Months Ended						Six Months Ended
	Financial Statement	June 30,						June 30,
Commodity Contracts	Location	2012			2011			2012			2011
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive income (loss) - derivative instruments	$	4,509		$	(16,323	)	$	(37,394	)	$	(15,335	)
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized) (a)	Fuel and purchased power	(23,015		)	(25,287		)	(37,515		)	(40,133		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power	32			(176		)	117			(164		)

(a)During the three and six months ended June 30, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges.

During the next twelve months, we estimate that a net loss of $77 million before income taxes will be reclassified from accumulated other comprehensive income 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, 2012 and 2011 (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

		Three Months Ended					Six Months Ended
	Financial Statement	June 30,					June 30,
Commodity Contracts	Location	2012		2011			2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues	$	87	$	(503	)	$	(239	)	$	1,004
Net Gain (Loss) Recognized in Income	Fuel and purchased power	26,042		(2,892		)	990			(11,919		)
Total		$	26,129	$	(3,395	)	$	751		$	(10,915	)

Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

The following table provides information about the fair value of our risk management activities reported on a gross basis.  Transactions with counterparties that have master netting arrangements are reported net on the Condensed Consolidated Balance Sheets.  These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.  Amounts are as of June 30, 2012 (dollars in thousands):

Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties			Other (b)			Total
Current Assets	$	—		$	66,712		$	390	$	—		$	(37,111	)	$	29,991
Investments and Other Assets	—			51,690			—		—			(8,164		)	43,526
Total Assets	—			118,402			390		—			(45,275		)	73,517
Current Liabilities	(1,185		)	(173,495		)	83,234		(11,145		)(a)	38,149			(64,442		)
Deferred Credits and Other	(4,594		)	(133,720		)	20,086		—			9,674			(108,554		)
Total Liabilities	(5,779		)	(307,215		)	103,320		(11,145		)	47,823			(172,996		)
Total	$	(5,779	)	$	(188,813	)	$	103,710	$	(11,145	)	$	2,548		$	(99,479	)

(a)Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)Other represents derivative instrument netting, options, and other risk management contracts.

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The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2011 (dollars in thousands):

Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties			Other (b)			Total
Current Assets	$	7,287		$	76,162		$	1,630	$	—		$	(54,815	)	$	30,264
Investments and Other Assets	3,804			58,273			—		—			(12,755		)	49,322
Total Assets	11,091			134,435			1,630		—			(67,570		)	79,586
Current Liabilities	(82,195		)	(124,028		)	107,228		(11,145		)(a)	56,172			(53,968		)
Deferred Credits and Other	(68,137		)	(92,880		)	65,768		—			12,754			(82,495		)
Total Liabilities	(150,332		)	(216,908		)	172,996		(11,145		)	68,926			(136,463		)
Total Derivative Instruments	$	(139,241	)	$	(82,473	)	$	174,626	$	(11,145	)	$	1,356		$	(56,877	)

(a)Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)Other represents derivative instrument netting, options, and other risk management contracts.

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 83% of Pinnacle West’s $74 million of risk management assets as of June 30, 2012.  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 subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2012 (dollars in millions):

	June 30, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	306
Cash Collateral Posted	96
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	136

(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 $184 million if our debt credit ratings were to fall below investment grade.

9.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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,744,917		$	116,512		$	3,861,429		$	3,631,411		$	97,360		$	3,728,771
Net income	122,345			7,766			130,111			86,685			7,154			93,839
Other comprehensive income	17,459			—			17,459			6,646			—			6,646
Total comprehensive income	139,804			7,766			147,570			93,331			7,154			100,485
Issuance of capital stock	2,525			—			2,525			3,505			—			3,505
Reissuance of treasury stock - net	5,113			—			5,113			—			—			—
Other (primarily stock compensation)	631			—			631			(33		)	—			(33		)
Dividends on common stock	(114,955		)	—			(114,955		)	(114,509		)	—			(114,509		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,821,850		$	108,736		$	3,930,586		$	3,683,327		$	91,899		$	3,775,226
Net income	114,088			15,542			129,630			71,550			12,615			84,165
Other comprehensive income	1,845			—			1,845			17,092			—			17,092
Total comprehensive income	115,933			15,542			131,475			88,642			12,615			101,257
Issuance of capital stock	5,225			—			5,225			17,065			—			17,065
Reissuance (purchase) of treasury stock - net	3,359			—			3,359			(3,530		)	—			(3,530		)
Other (primarily stock compensation)	3,981			—			3,981			(181		)	—			(181		)
Dividends on common stock	(172,313		)	—			(172,313		)	(171,618		)	—			(171,618		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

10.Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

APS currently estimates it will incur $122 million (in 2010 dollars) 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, 2012, APS had a regulatory liability of $47 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence.  As required by the Price Anderson Nuclear Industries Indemnity Act, 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 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 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

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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”).  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 and exclusions.

Contractual Obligations

As of June 30, 2012, certain contractual obligations have increased approximately $0.3 billion from December 31, 2011 as discussed in the 2011 Form 10-K.  As of June 30, 2012, the updated contractual obligations are as follows (dollars in billions):

Year	2012		2013		2014		2015		2016		Thereafter		Total
Fuel and purchased power commitments	$	0.3	$	0.5	$	0.6	$	0.5	$	0.5	$	6.8	$	9.2
Renewable energy credits	0.1		—		—		0.1		—		0.5		0.7

FERC Market Issues

On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest.  The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding.  This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to the FERC for further consideration.  On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001.  FERC rejected a market-wide remedy approach and instead directed that buyers seeking refunds must demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.

The hearing is currently expected to commence in April 2013.  Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

Superfund

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

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Protection Agency (“EPA”) advised APS that the 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 the EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with the 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 $1 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 we cannot accurately estimate our total expenditures.

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 Ninth Circuit Court of Appeals in November 2009, and Pinnacle West filed its reply on June 30, 2010.  On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.

On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants.  However, the Court left open the issue of whether such claims may be available under state law.  Oral argument in the Kivalina case was heard on November 28, 2011; the parties await the court’s decision on both federal common law and state public nuisance law issues.  We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

Southwest Power Outage

Regulatory Inquiry.  On September 8, 2011 at approximately 3:30PM, 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.  At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly.  Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.

Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico.  A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. 

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Service to all affected APS customers was restored by 9:15PM on September 8.  Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9.  APS has an internal review of the September 8 events underway.

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 cannot predict the timing, results or potential impacts of any further inquiries into 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.

Lawsuit.  On September 12, 2011, two purported consumer class action complaints were filed in Federal District Court in San Diego, California, naming APS, Pinnacle West and San Diego Gas & Electric Company (“SDG&E”) as defendants and seeking damages for loss of perishable inventory as a result of interruption of electrical service.  On December 22, 2011, the plaintiffs voluntarily dismissed both lawsuits.  In January 2012, one of the cases was refiled in California Superior Court in San Diego, California, and then removed by defendants to Federal Court in San Diego.  APS and Pinnacle West filed a motion to dismiss that was granted by the Court on March 20, 2012.  The Court stated that the plaintiffs could refile a complaint against APS and Pinnacle West on certain grounds following the release of the Joint Report discussed above. On May 31, 2012, the plaintiff filed an amended complaint against APS and Pinnacle West.  APS and Pinnacle West subsequently filed a motion to dismiss the amended complaint, which was granted on July 27, 2012.

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 Prevention of Significant Deterioration (“PSD”) 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 PSD 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, which are pending.  APS believes the claims in this matter are without merit and will vigorously defend against them.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At June 30, 2012, approximately $76 million of letters of credit were outstanding to support existing variable interest rate 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 obligations to certain equity participants in the Palo Verde sale leaseback transactions (see Note 7 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire in 2015 and totaled approximately $44 million at June 30, 2012.  Additionally, APS has issued letters of credit to support collateral obligations under certain natural gas tolling contracts and hedge contracts entered into with third parties, including a $40 million letter of credit issued in June 2012.  At June 30, 2012, $65 million of such letters of credit were outstanding.  These letters of credit will expire in 2013, 2015 and 2016.

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.

11.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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	107		$	543		$	712		$	935
Investment gains — net	—			12			—			1,307
Miscellaneous	70			2			225			5
Total other income	$	177		$	557		$	937		$	2,247
Other expense:
Non-operating costs	$	(2,389	)	$	(1,629	)	$	(4,239	)	$	(3,119	)
Investment losses — net	(58		)	—			(112		)	—
Miscellaneous	(222		)	(1,557		)	(2,386		)	(1,808		)
Total other expense	$	(2,669	)	$	(3,186	)	$	(6,737	)	$	(4,927	)

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12.Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	1.12		$	0.79	$	1.06		$	0.64
Income (loss) from discontinued operations	—			0.01		(0.02		)	0.02
Earnings per share — basic	$	1.12		$	0.80	$	1.04		$	0.66
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	1.12		$	0.78	$	1.05		$	0.64
Income (loss) from discontinued operations	(0.01		)	0.01		(0.01		)	0.01
Earnings per share — diluted	$	1.11		$	0.79	$	1.04		$	0.65

Dilutive stock options and performance shares (which are contingently issuable) increased average diluted common shares outstanding by approximately 868,000 shares and 674,000 shares for the three months ended June 30, 2012 and 2011, respectively, and by approximately 788,000 shares and 601,000 shares for the six months ended June 30, 2012 and 2011, respectively.

For the three-month and six-month periods ended June 30, 2012 and 2011, 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.

13.Discontinued Operations

SunCor — In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations, or cash flows.  All activity for the income statement for the three and six months ended June 30, 2012 and prior comparative period income statement amounts are included in discontinued operations.

APSES — In 2011, Pinnacle West sold its investment in APSES.  Prior-period income statement amounts related to the sale of APSES and the associated revenues and costs are reflected in discontinued operations.

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2012 and 2011 (dollars in millions):

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Revenue:
SunCor	$	—		$	2	$	—		$	3
APSES	—			15		—			26
Total revenue	$	—		$	17	$	—		$	29
Income (loss) before taxes	$	(1	)	$	1	$	(3	)	$	2
Income (loss) after taxes	$	(1	)	$	1	$	(1	)	$	1

14.Fair Value Measurements

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.  This category includes exchange-traded equities, exchange-traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.

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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 2011 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 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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies including mortgage-backed instruments are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield and interest rate 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 assess these valuations and verify that pricing can be supported by actual recent market transactions.  Additionally, we obtain and review independent audit reports on the trustee’s operating controls and valuation processes.  See Note 15 for additional discussion about our nuclear decommissioning trust.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at June 30, 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 June 30, 2012
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	192		$	—		$	—		$	192
Fixed income securities:
U.S. Treasury	84		—			—			—			84
Cash and cash equivalent funds	—		15			—			(6		)(b)	9
Corporate debt	—		69			—			—			69
Mortgage-backed securities	—		84			—			—			84
Municipality bonds	—		94			—			—			94
Other	—		13			—			—			13
Subtotal nuclear decommissioning trust	84		467			—			(6		)	545
Cash equivalents	2		—			—			—			2
Risk management activities — derivative instruments:
Commodity contracts	—		50			69			(45		)(c)	74
Total	$	86	$	517		$	69		$	(51	)	$	621
Liabilities:
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(199	)	$	(114	)	$	140	(c)	$	(173	)

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

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

(c)Primarily represents counterparty netting, margin and collateral (see Note 8).

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 2011 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, 2011
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	175		$	—		$	—		$	175
Fixed income securities:
U.S. Treasury	69		—			—			—			69
Cash and cash equivalent funds	—		9			—			(1		)(b)	8
Corporate debt	—		73			—			—			73
Mortgage-backed securities	—		78			—			—			78
Municipality bonds	—		90			—			—			90
Other	—		21			—			—			21
Subtotal nuclear decommissioning trust	69		446			—			(1		)	514
Risk management activities — derivative instruments:
Commodity contracts	—		70			74			(64		)(c)	80
Total	$	69	$	516		$	74		$	(65	)	$	594
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(c)	$	(137	)

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

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

(c)Represents counterparty netting, margin and collateral (see Note 8).

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 generally if the price of the underlying commodity increases we would expect the net fair

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

value of contracts related to that commodity to increase, and 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 fair value of these options to increase, and if these valuation inputs decrease we would expect the fair value of these options to decrease. If natural gas prices and natural gas price implied volatilities increase we would expect the fair value of these options to decrease, and if these inputs decrease we would expect the fair value of the options to increase. The commodity prices and 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 table provides information regarding our significant unobservable inputs used to value our Level 3 instruments.

Risk Management Activities — Derivative Instruments:  Commodity Contracts

	June 30, 2012
	Fair Value (millions)				Valuation	Significant
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range
Electricity:
Forward Contracts (a)	$	67	$	88	Discounted cash flows	Electricity forward price (per MWh)(b)	$20.67 - $67.18
Option Contracts	—		25		Option Model	Electricity forward price (per MWh)(b)	$29.13 - $99.27
						Natural gas forward price (per mmbtu)(c)	$2.69 - $4.11
						Implied electricity price volatilities	15% - 151%
						Implied natural gas price volatilities	18% - 56%
Natural Gas:
Forward Contracts (a)	2		1		Discounted cash flows	Natural gas forward price (per mmbtu)(c)	$2.60 - $4.18
Total	$	69	$	114

(a)Includes swaps and physical and financial contracts.

(b)MWh means megawatt-hour, one million watts per hour.

(c)mmbtu means one million British Thermal Units.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2012 and 2011 (dollars in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2012			2011			2012			2011
Net derivative balance at beginning of period	$	(58	)	$	(48	)	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	1			—			2			1
Included in OCI	3			(3		)	(2		)	(1		)
Deferred as a regulatory asset or liability	12			1			7			(6		)
Settlements	(1		)	4			—			4
Transfers into Level 3 from Level 2	—			1			2			(4		)
Transfers from Level 3 into Level 2	(2		)	(2		)	(3		)	(3		)
Net derivative balance at end of period	$	(45	)	$	(47	)	$	(45	)	$	(47	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	1

Amounts included in earnings are recorded in either regulated electricity segment revenue or regulated electricity segment fuel and purchased power depending on the nature of the underlying contract.

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no transfers in or out of Level 1 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.

Nonrecurring Fair Value Measurements

For the periods ended June 30, 2012 and 2011, we had no assets or liabilities measured at fair value on a nonrecurring basis.

Financial Instruments Not Carried at Fair Value

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

15.Nuclear Decommissioning Trust

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 domestic equity securities.  APS classifies investments in decommissioning trust funds as available for sale.  As a result, we record the decommissioning trust

40

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

funds at their fair value on our Condensed Consolidated Balance Sheets.  See Note 14 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 recorded deferred realized and unrealized gains and losses on investment securities in other regulatory liabilities or 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, 2012 and December 31, 2011 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2012
Equity securities	$	192		$	58	$	(1	)
Fixed income securities	359			24		—
Net payables (a)	(6		)	—		—
Total	$	545		$	82	$	(1	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2011
Equity securities	$	175		$	44	$	(1	)
Fixed income securities	340			23		(1		)
Net payables (a)	(1		)	—		—
Total	$	514		$	67	$	(2	)

(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,
	2012			2011			2012			2011
Realized gains	$	2		$	2		$	4		$	3
Realized losses	(1		)	(1		)	(2		)	(3		)
Proceeds from the sale of securities (a)	119			110			211			300

(a)Proceeds are reinvested in the trust.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2012 is as follows (dollars in millions):

	Fair Value
Less than one year	$	24
1 year - 5 years	82
5 years - 10 years	103
Greater than 10 years	150
Total	$	359

16.New Accounting Standards

During the first quarter of 2012, we adopted amended guidance intended to converge fair value measurement and disclosure requirements for GAAP and international financial reporting standards (“IFRS”).  The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures.  The adoption of this new guidance resulted in additional fair value disclosures (see Note 14), but did not impact our financial statement results.

During the first quarter of 2012, we also adopted amended guidance on the presentation of comprehensive income.  As a result of the amended guidance, we have changed our format for presenting comprehensive income.  Previously, components of comprehensive income were presented within changes of equity.  Due to the amended guidance, we now present comprehensive income in a new financial statement titled “Condensed Consolidated Statements of Comprehensive Income”.  The adoption of this guidance changed our format for presenting comprehensive income, but did not impact our financial statement results.

42

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,
	2012			2011
ELECTRIC OPERATING REVENUES	$	877,587		$	798,686
OPERATING EXPENSES
Fuel and purchased power	264,723			244,048
Operations and maintenance	213,746			208,597
Depreciation and amortization	100,583			106,594
Income taxes	80,696			54,259
Taxes other than income taxes	41,018			39,788
Total	700,766			653,286
OPERATING INCOME	176,821			145,400
OTHER INCOME (DEDUCTIONS)
Income taxes	2,030			1,565
Allowance for equity funds used during construction	5,175			5,924
Other income (Note S-2)	1,018			1,233
Other expense (Note S-2)	(3,993		)	(4,651		)
Total	4,230			4,071
INTEREST EXPENSE
Interest on long-term debt	48,838			54,754
Interest on short-term borrowings	1,914			2,521
Debt discount, premium and expense	1,052			1,164
Allowance for borrowed funds used during construction	(3,447		)	(3,857		)
Total	48,357			54,582
NET INCOME	132,694			94,889
Less: Net income attributable to noncontrolling interests (Note 7)	7,766			7,184
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	124,928		$	87,705

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

43

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,
	2012		2011
NET INCOME	$	132,694	$	94,889
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(1,781) and $6,449	2,727		(9,875		)
Reclassification of net realized loss, net of tax benefit of $9,092 and $9,990	13,922		15,297
Pension and other postretirement benefits activity, net of tax expense of $305 and $853	468		1,308
Total other comprehensive income	17,117		6,730
COMPREHENSIVE INCOME	149,811		101,619
Less: Comprehensive income attributable to noncontrolling interests	7,766		7,184
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	142,045	$	94,435

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

44

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2012			2011
ELECTRIC OPERATING REVENUES	$	1,497,835		$	1,446,680
OPERATING EXPENSES
Fuel and purchased power	481,032			456,056
Operations and maintenance	422,193			461,203
Depreciation and amortization	200,668			213,152
Income taxes	79,882			48,255
Taxes other than income taxes	83,244			77,038
Total	1,267,019			1,255,704
OPERATING INCOME	230,816			190,976
OTHER INCOME (DEDUCTIONS)
Income taxes	3,736			225
Allowance for equity funds used during construction	9,931			11,319
Other income (Note S-2)	1,528			3,211
Other expense (Note S-2)	(8,617		)	(8,243		)
Total	6,578			6,512
INTEREST EXPENSE
Interest on long-term debt	101,575			109,491
Interest on short-term borrowings	3,949			4,829
Debt discount, premium and expense	2,112			2,321
Allowance for borrowed funds used during construction	(6,598		)	(7,432		)
Total	101,038			109,209
NET INCOME	136,356			88,279
Less: Net income attributable to noncontrolling interests (Note 7)	15,533			12,654
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	120,823		$	75,625

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)

	Six Months Ended June 30,
	2012			2011
NET INCOME	$	136,356		$	88,279
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $14,773 and $6,059	(22,621		)	(9,277		)
Reclassification of net realized loss, net of tax benefit of $14,820 and $15,855	22,694			24,278
Pension and other postretirement benefits activity, net of tax expense of $841 and $1,362	1,289			2,087
Total other comprehensive income	1,362			17,088
COMPREHENSIVE INCOME	137,718			105,367
Less: Comprehensive income attributable to noncontrolling interests	15,533			12,654
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	122,185		$	92,713

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30,			December 31,
	2012			2011
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	14,045,091		$	13,750,105
Accumulated depreciation and amortization	(4,840,292		)	(4,706,462		)
Net	9,204,799			9,043,643
Construction work in progress	458,441			496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	130,929			132,864
Intangible assets, net of accumulated amortization	163,572			170,416
Nuclear fuel, net of accumulated amortization	159,493			118,098
Total property, plant and equipment	10,117,234			9,961,766
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)	544,933			513,733
Assets from risk management activities (Note 8)	43,526			49,322
Other assets	31,076			30,551
Total investments and other assets	619,535			593,606
CURRENT ASSETS
Cash and cash equivalents	2,784			19,873
Customer and other receivables	314,230			280,100
Accrued unbilled revenues	168,450			125,239
Allowance for doubtful accounts	(3,302		)	(3,748		)
Materials and supplies (at average cost)	217,222			204,387
Fossil fuel (at average cost)	30,177			22,000
Deferred fuel and purchased power regulatory asset (Note 3)	—			27,549
Other regulatory assets (Note 3)	54,857			69,072
Deferred income taxes	68,622			111,503
Income tax receivable	—			2,869
Assets from risk management activities (Note 8)	29,991			30,264
Other current assets	33,468			26,486
Total current assets	916,499			915,594
DEFERRED DEBITS
Regulatory assets (Note 3)	1,283,322			1,352,079
Income tax receivable (Note 6)	69,903			69,028
Unamortized debt issue costs	23,611			21,181
Other	116,293			118,983
Total deferred debits	1,493,129			1,561,271
TOTAL ASSETS	$	13,146,397		$	13,032,237

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 BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30,			December 31,
	2012			2011
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,469,162			1,510,740
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(37,597		)	(38,886		)
Derivative instruments	(86,632		)	(86,705		)
Total shareholder equity	3,902,791			3,943,007
Noncontrolling interests (Note 7)	121,302			108,399
Total equity	4,024,093			4,051,406
Long-term debt less current maturities	3,188,992			2,828,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	57,420			65,547
Total capitalization	7,270,505			6,945,460
CURRENT LIABILITIES
Short-term borrowings	109,000			—
Current maturities of long-term debt	57,962			477,435
Accounts payable	311,596			322,047
Accrued taxes (Note 6)	134,103			113,930
Accrued interest	61,065			54,611
Common dividends payable	57,500			—
Customer deposits	74,575			72,176
Liabilities from risk management activities (Note 8)	64,442			53,968
Deferred fuel and purchased power regulatory liability (Note 3)	325			—
Other regulatory liabilities (Note 3)	89,433			88,362
Other current liabilities	127,352			140,185
Total current liabilities	1,087,353			1,322,714
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,976,973			1,952,608
Regulatory liabilities (Note 3)	738,693			737,332
Liability for asset retirements	289,641			279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,198,943			1,222,542
Liabilities from risk management activities (Note 8)	108,554			82,495
Customer advances	111,655			116,805
Coal mine reclamation	118,374			117,896
Unrecognized tax benefits (Note 6)	72,777			72,073
Other	172,929			182,669
Total deferred credits and other	4,788,539			4,764,063
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	13,146,397		$	13,032,237

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	136,356		$	88,279
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	239,696			245,617
Deferred fuel and purchased power	82,261			64,679
Deferred fuel and purchased power amortization	(54,388		)	(68,762		)
Allowance for equity funds used during construction	(9,931		)	(11,319		)
Deferred income taxes	69,672			11,488
Change in derivative instruments fair value	(2,618		)	(279		)
Changes in current assets and liabilities:
Customer and other receivables	(23,015		)	11,104
Accrued unbilled revenues	(43,211		)	(60,390		)
Materials, supplies and fossil fuel	(21,012		)	(18,226		)
Other current assets	(6,928		)	(9,458		)
Accounts payable	9,406			49,939
Accrued taxes	20,890			35,852
Other current liabilities	(3,095		)	(3,531		)
Change in margin and collateral accounts — assets	124			21,185
Change in margin and collateral accounts — liabilities	69,602			39,567
Change in other long-term assets	(2,456		)	(25,004		)
Change in other long-term liabilities	5,180			85,262
Net cash flow provided by operating activities	466,533			456,003
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(424,775		)	(387,932		)
Contributions in aid of construction	25,800			21,905
Allowance for borrowed funds used during construction	(6,598		)	(7,432		)
Proceeds from sale of life insurance policies	—			44,183
Proceeds from nuclear decommissioning trust sales	211,138			299,600
Investment in nuclear decommissioning trust	(219,762		)	(308,222		)
Other	(525		)	(2,352		)
Net cash flow used for investing activities	(414,722		)	(340,250		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081			—
Short-term borrowing and payments - net	109,000			—
Repayment of long-term debt	(421,451		)	(12,962		)
Dividends paid on common stock	(104,900		)	(114,300		)
Noncontrolling interests	(2,630		)	(2,610		)
Net cash flow used for financing activities	(68,900		)	(129,872		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(17,089		)	(14,119		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	19,873			99,937
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,784		$	85,818
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	—		$	—
Interest, net of amounts capitalized	$	92,473		$	106,546

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

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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	—
Business Segments	Note 5	—
Income Taxes	Note 6	—
Palo Verde Sale Leaseback Variable Interest Entities	Note 7	—
Derivative Accounting	Note 8	—
Changes in Equity	Note 9	Note S-1
Commitments and Contingencies	Note 10	—
Other Income and Other Expense	Note 11	Note S-2
Earnings Per Share	Note 12	—
Discontinued Operations	Note 13	—
Fair Value Measurements	Note 14	—
Nuclear Decommissioning Trust	Note 15	—
New Accounting Standards	Note 16	—

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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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,865,748		$	116,166		$	3,981,914		$	3,766,131		$	96,554		$	3,862,685
Net income	124,928			7,766			132,694			87,705			7,184			94,889
OCI	17,117			—			17,117			6,730			—			6,730
Total comprehensive income	142,045			7,766			149,811			94,435			7,184			101,619
Dividends on common stock	(105,000		)	—			(105,000		)	(114,500		)	—			(114,500		)
Net capital activities by noncontrolling interests	—			(2,630		)	(2,630		)	—			(2,610		)	(2,610		)
Other	(2		)	—			(2		)	1			—			1
Ending balance, June 30	$	3,902,791		$	121,302		$	4,024,093		$	3,746,067		$	101,128		$	3,847,195

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,943,007		$	108,399		$	4,051,406		$	3,824,953		$	91,084		$	3,916,037
Net income	120,823			15,533			136,356			75,625			12,654			88,279
OCI	1,362			—			1,362			17,088			—			17,088
Total comprehensive income	122,185			15,533			137,718			92,713			12,654			105,367
Dividends on common stock	(162,400		)	—			(162,400		)	(171,600		)	—			(171,600		)
Net capital activities by noncontrolling interests	—			(2,630		)	(2,630		)	—			(2,610		)	(2,610		)
Other	(1		)	—			(1		)	1			—			1
Ending balance, June 30	$	3,902,791		$	121,302		$	4,024,093		$	3,746,067		$	101,128		$	3,847,195

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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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	77		$	89		$	184		$	219
Investment gains — net	—			268			—			1,418
Miscellaneous	941			876			1,344			1,574
Total other income	$	1,018		$	1,233		$	1,528		$	3,211
Other expense:
Non-operating costs (a)	$	(2,941	)	$	(2,400	)	$	(4,682	)	$	(4,214	)
Asset dispositions	(195		)	—			(418		)	(823		)
Miscellaneous	(857		)	(2,251		)	(3,517		)	(3,206		)
Total other expense	$	(3,993	)	$	(4,651	)	$	(8,617	)	$	(8,243	)

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

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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 I, Item 1A of the 2011 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 the Palo Verde Nuclear Generating Station.  APS management is working closely with regulators and others in the nuclear industry to analyze the lessons learned and address any rulemaking or improvements resulting from the March 2011 events impacting the Fukushima Daiichi Nuclear Power Station in Japan.

Coal and Related Environmental Matters.  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.

Southern California Edison Company (“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 (“APA”), 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.  Completion of the purchase by APS is subject to the receipt of approvals by the ACC, the California Public Utility 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, with a condition that the transaction may not close prior to December 1, 2012.  The APA provides that the purchase price will be reduced by $7.5 million for each month between October 1, 2012 and the closing date.  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

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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 filed in May 2012, and a decision is expected before the end of November 2012.  Closing is also conditioned on the negotiation and execution of a new coal supply contract on terms reasonably acceptable to APS.

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 U.S. 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.

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 all of the conditions necessary to consummate the purchase of SCE’s interest will be met such that closing can occur.

Transmission and Delivery.  APS’s 2012 Ten-Year Transmission Plan filed with the ACC in January 2012 projects that it will invest approximately $550 million in new transmission projects (115 kV and above) over the next ten years, adding 269 miles of new lines.  The first three years of these additions are included in the capital expenditures table presented in the “Liquidity and Capital Resources” section below along with other transmission costs for upgrades and replacements.  APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy.  APS is also working to establish and expand smart grid technology throughout its service territory designed to provide long-term benefits both to APS and its customers.  APS is piloting and deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations and the number of customers that experience outages, and facilitate 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 3.5% of retail electric sales in 2012 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 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 estimated to be 3,400 GWh, or approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year.  A component of the RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

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On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $92.8 million to $102.4 million.  The budget range stems from options related to distributed energy; if the ACC decides to promote more distributed energy by selecting the higher budget, APS requested that the 2013 incentives for photovoltaic distributed energy begin at $0.20 and step down gradually based upon market participation.  APS’s filing also proposed a system of establishing compliance with distributed energy requirements that depends upon tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  Further, APS described its Community Solar Program, a utility-owned 25 MW program that will be split into 3 to 7 separate projects throughout communities in APS’s service territory.  APS expects a decision from the ACC around year end.

The following table summarizes APS’s renewable energy sources in operation and under development as of August 2, 2012.  Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar	56	54
Purchased Power Agreements:
Solar	15	295
Wind	289
Geothermal	10
Biomass	14
Biogas	3	3
Total Purchased Power Agreements	331	298
Total Distributed Energy: Solar	170	111
Total Renewable Portfolio	557	463

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.  On July 27, 2010, the proposed Energy Efficiency Standard was adopted by the ACC, approved by the Arizona Attorney General and became effective on January 1, 2011.  This ambitious standard will likely impact Arizona’s future energy resource needs.  The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates.

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On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later this year, APS intends to file a supplement to its plan that will include a proposed budget for 2013.

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.  On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.  The Settlement Agreement demonstrates cooperation among APS, the ACC staff, the Residential Utility Consumer Office and other intervenors to the rate case, and establishes a future rate case filing plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual rate cases.  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.

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.  In January 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042.  APS used the net proceeds from the sale of the notes along with other funds to pay at maturity its $375 million aggregate principal amount of 6.50% unsecured senior notes that matured on March 1, 2012.

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.  As a result of the continuing distressed conditions in the real estate markets, during 2009 our other first-tier subsidiary, SunCor, undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt.  In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations or cash flows.

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 2009 through 2011, retail electric revenues comprised approximately 93% of our total electric operating revenues.  Our electric operating revenues

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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.  Off-system sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’s retail customers through the PSA.  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, 2012 was 0.9% compared with the comparable prior-year period.  For the three years 2009 through 2011, APS’s customer growth averaged 0.6% per year.  We currently expect annual customer growth to average about 2.0% for 2012 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, for the six-month period ended June 30, 2012 decreased 0.5% compared with the comparable prior-year period, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, partially offset by mildly improving economic conditions.  For the three years 2009 through 2011, APS experienced annual declines in retail electricity sales averaging 0.8%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kilowatt-hours will remain flat on average during 2012 through 2015, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  The 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 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.  Historical 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 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 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 regulated electricity segment operating revenues) and other factors.  In the settlement agreement related to the 2008 retail rate case, APS committed to operational expense reductions from

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2010 through 2014 and received approval to defer certain pension and other postretirement benefit cost increases to be incurred in 2011 and 2012, until the most recent general retail rate case decision became effective on July 1, 2012.

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.  As a result of the twenty-year extensions of the operating licenses for each of the Palo Verde units granted by the NRC in 2011, we decreased our pretax depreciation expense related to Palo Verde by approximately $34 million per year starting on January 1, 2012.

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 9.0% of the assessed value for 2011 and 8.0% for 2010.  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, and certain 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 electricity service to 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, 2012 compared with three-month period ended June 30, 2011

Our consolidated net income attributable to common shareholders for the three months ended June 30, 2012 was $122 million, compared with net income of $87 million for the comparable prior-year period.  The results reflect an increase of approximately $37 million for the regulated electricity segment primarily due to the effects of warmer weather on usage per customer as compared to the prior-year period, lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011, and lower net interest charges due to lower debt balances and interest rates in the current period.  These positive factors were partially offset by an increase in operations and maintenance expense primarily related to higher stock compensation costs.

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

	Three Months Ended June 30,
	2012			2011			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a)	$	613		$	555		$	58
Operations and maintenance (a)	(216		)	(211		)	(5		)
Depreciation and amortization	(101		)	(107		)	6
Taxes other than income taxes	(41		)	(40		)	(1		)
Other income (expenses), net	3			3			—
Interest charges, net of allowance for borrowed funds used during construction	(50		)	(56		)	6
Income taxes (Note 6)	(77		)	(51		)	(26		)
Less income related to noncontrolling interests (Note 7)	(8		)	(7		)	(1		)
Regulated electricity segment net income	123			86			37
Income (Loss) from Discontinued Operations Attributable to Common Shareholders	(1		)	1			(2		)
Net Income Attributable to Common Shareholders	$	122		$	87		$	35

(a)Operating revenues less fuel and purchased power expenses includes amounts related to demand side management and renewable energy and similar regulatory surcharges, which were substantially offset in operations and maintenance expense.

Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $58 million higher for the three months ended June 30, 2012 compared with the prior-year period.  The following table describes the major components of this change:

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	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Effects of weather on usage per customer	$	63		$	21		$	42
Higher retail transmission charges	9			—			9
Lower fuel and purchased power costs, net of off-system sales	—			(7		)	7
Lower PSA refunds	8			6			2
Miscellaneous items, net	(1		)	1			(2		)
Total	$	79		$	21		$	58

Operations and maintenance  Operations and maintenance expenses increased $5 million for the three months ended June 30, 2012 compared with the prior-year period primarily because of:

·An increase of $8 million related to higher stock compensation costs resulting from an improved company stock price and estimated performance; and

·A decrease of $3 million related to costs for demand side management, renewable energy, and similar regulatory programs, which were largely offset in operating revenues.

Depreciation and amortization  Depreciation and amortization expenses were $6 million lower for the three months ended June 30, 2012 compared with the prior-year period primarily due to impacts of the Palo Verde operating license extensions, partially offset by 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 $6 million for the three months ended June 30, 2012 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 $26 million higher for the three months ended June 30, 2012 compared with the prior-year period primarily due to higher pretax income in the current period.

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Operating Results – Six-month period ended June 30, 2012 compared with six-month period ended June 30, 2011

Our consolidated net income attributable to common shareholders for the six months ended June 30, 2012 was $114 million, compared with net income of $72 million for the comparable prior-year period.  The results reflect an increase of approximately $46 million for the regulated electricity segment primarily due to effects of warmer weather on usage per customer as compared to the prior-year period, decreased operations and maintenance expenses, lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011, and lower net interest charges due to lower debt balances and interest rates, partially offset by higher property taxes due to increased property tax rates.

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

	Six Months Ended
	June 30,
	2012			2011			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a) (b)	$	1,017		$	991		$	26
Operations and maintenance (a) (b)	(427		)	(466		)	39
Depreciation and amortization	(201		)	(213		)	12
Taxes other than income taxes	(84		)	(78		)	(6		)
Other income (expenses), net	4			8			(4		)
Interest charges, net of allowances for borrowed funds used during construction	(103		)	(114		)	11
Income taxes (Note 6)	(73		)	(45		)	(28		)
Less income related to noncontrolling interests (Note 7)	(16		)	(12		)	(4		)
Regulated electricity segment net income	117			71			46
All other	(2		)	(1		)	(1		)
Income from Continuing Operations Attributable to Common Shareholders	115			70			45
Income (Loss) from Discontinued Operations Attributable to Common Shareholders	(1		)	2			(3		)
Net Income Attributable to Common Shareholders	$	114		$	72		$	42

(a)Includes effects of 2011 settlement of certain transmission right-of-way costs, which did not affect net income, but increased both electric operating revenues and operations and maintenance expenses by $28 million.  Costs related to the settlement were offset by related revenues from SCE, which leases the related transmission line from APS.

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(b)Operating revenues less fuel and purchased power expenses includes amounts related to demand side management and renewable energy and similar regulatory surcharges, which were substantially offset in operations and maintenance expense.

Operating revenues less fuel and purchased power expenses  Regulated electricity segment operating revenues less fuel and purchased power expenses were $26 million higher for the six months ended June 30, 2012 compared with the prior-year period.  The following table describes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Effects of weather on usage per customer	$	52		$	16		$	36
Higher retail transmission charges	14			—			14
Lower fuel and purchased power costs, net of off-system sales	3			(3		)	6
Lower PSA refunds	14			11			3
Lower usage per customer	(11		)	(3		)	(8		)
Settlement in 2011 of certain prior-period transmission right-of-way revenues	(28		)	—			(28		)
Miscellaneous items, net	7			4			3
Total	$	51		$	25		$	26

Operations and maintenance  Operations and maintenance expenses decreased $39 million for the six months ended June 30, 2012 compared with the prior-year period primarily because of:

·A decrease of $28 million for settlement in 2011 of certain transmission right-of-way costs, which was offset in operating revenues;

·A decrease of $9 million in generation costs, primarily due to lower fossil-fuel power plant maintenance costs as a result of less work being completed early in the year compared to 2011;

·A decrease of $7 million related to costs for demand side management, renewable energy, and similar regulatory programs, which were largely offset in operating revenues;

·An increase of $7 million related to higher stock compensation costs resulting from an improved company stock price and estimated performance; and

·A decrease of $2 million due to other miscellaneous factors.

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Depreciation and amortization  Depreciation and amortization expenses were $12 million lower for the six months ended June 30, 2012 compared with the prior-year period primarily due to the impacts of Palo Verde operating license extensions, partially offset by increased plant in service.

Taxes other than income taxes  Taxes other than income taxes increased $6 million for the six months ended June 30, 2012 compared with the prior-year period primarily because of higher property tax rates in the current period.

Interest charges, net of allowance for borrowed funds used during construction  Interest charges, net of allowance for borrowed funds used during construction, decreased $11 million for the six months ended June 30, 2012 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 $28 million higher for the six months ended June 30, 2012 compared with the prior-year period primarily due to higher pre-tax income in the current period.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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 of our Board of Directors based on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

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, 2012, APS’s common equity ratio, as defined, was 55%.  Its total shareholder equity was approximately $3.9 billion, and total capitalization was approximately $7.1 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $2.8 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 Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 includes provisions making qualified property placed into service after September 8, 2010 and before January 1, 2012 eligible for 100% bonus depreciation for federal income tax purposes.  In addition, qualified property placed into service in 2012 is eligible for 50% bonus depreciation for federal income tax purposes.  These provisions of the recent tax legislation are expected to generate approximately $400-450 million of cash tax benefits for APS through accelerated depreciation.  It is anticipated that these cash benefits

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will be fully realized by APS by the end of 2013, with a majority of the benefit realized in 2012.  The cash generated is an acceleration of tax benefits that APS would have otherwise received over 20 years.

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, 2012 and 2011 (dollars in millions):

Pinnacle West Consolidated

	Six Months Ended June 30,						Net
	2012			2011			Change
Net cash flow provided by operating activities	$	459		$	436		$	23
Net cash flow used for investing activities	(415		)	(328		)	(87		)
Net cash flow used for financing activities	(66		)	(126		)	60
Net decrease in cash and cash equivalents	$	(22	)	$	(18	)	$	(4	)

Arizona Public Service Company

	Six Months Ended June 30,						Net
	2012			2011			Change
Net cash flow provided by operating activities	$	467		$	456		$	11
Net cash flow used for investing activities	(415		)	(340		)	(75		)
Net cash flow used for financing activities	(69		)	(130		)	61
Net decrease in cash and cash equivalents	$	(17	)	$	(14	)	$	(3	)

Operating Cash Flows

Six-month period ended June 30, 2012 compared with six-month period ended June 30, 2011.  Pinnacle West’s consolidated net cash provided by operating activities was $459 million in 2012, compared to $436 million in 2011, an increase of $23 million in net cash provided.  The increase is primarily related to changes in working capital and a net $9 million change in collateral and margin posted due to the issuance of a letter of credit to support collateral obligations and the expiration of prior hedge contracts, partially offset by changes in commodity prices.

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 obligation.  Under ERISA, the qualified pension plan was 89% funded as of January 1, 2011 and 84% funded as of January 1, 2012.  The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.  Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We expect to contribute to our pension plan approximately $65 million in 2012 (of which $15 million was contributed in July 2012), approximately $150 million in 2013 and approximately $160 million in 2014.  The contributions to our

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other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year.

The $70 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.  This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt.  Further clarification of the timing is expected from the IRS within the next twelve months.

Investing Cash Flows

Six-month period ended June 30, 2012 compared with six-month period ended June 30, 2011.  Pinnacle West’s consolidated net cash used for investing activities was $415 million in 2012, compared to $328 million in 2011, an increase of $87 million in net cash used.  The increase in net cash used for investing activities is primarily due to an increase of approximately $33 million in capital expenditures and the absence of $55 million in proceeds from the sale of life insurance policies in 2011.

Capital Expenditures.  The following table summarizes the estimated capital expenditures for the next three years:

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2012		2013		2014
APS
Generation:
Nuclear Fuel	$	73	$	80	$	85
Renewables	196		222		124
Environmental	12		64		89
Four Corners Units 4 and 5	294		—		—
Other Generation	141		120		243
Distribution	241		268		287
Transmission	122		123		168
Other (a)	36		50		61
Total APS	$	1,115	$	927	$	1,057

(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.  Included under Renewables is the AZ Sun Program, which reflects capital funding from the 2012 RES implementation plan, which was approved by the ACC on December 14, 2011.  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 $294 million purchase price under Generation

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and have not included environmental expenditures for Units 1-3.  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.

Financing Cash Flows and Liquidity

Six-month period ended June 30, 2012 compared with six-month period ended June 30, 2011.  Pinnacle West’s consolidated net cash used for financing activities was $66 million in 2012, compared to $126 million in 2011, a decrease of $60 million in net cash used.  The decrease in net cash used for financing activities is primarily due to $109 million of short-term debt borrowings at APS in 2012, a portion of which was used to repay $57 million of long-term debt repayments, net of issuances of long-term debt (see below).

Significant Financing Activities.  On June 20, 2012, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on September 4, 2012, to shareholders of record on August 1, 2012.

On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029.  On June 1, 2012 we remarketed these bonds.  Currently, the interest rate on these bonds is reset daily by a remarketing agent.  The daily rate at June 30, 2012 was 0.17%.  Additionally, the bonds are supported by a letter of credit.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A.  The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014.  During this time, the bonds will bear interest at a rate of 1.25% per annum.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

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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, 2012, 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, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

At June 30, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, 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, 2012, APS had commercial paper borrowings of $109 million, and no outstanding borrowings or letters of credit under these facilities.

See “Financial Assurances” in Note 10 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 8 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, 2012, the ratio was approximately 48% for Pinnacle West and 47% for APS.  Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.  See further discussion of “cross-default” provisions below.

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

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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.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of July 27, 2012 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 liquidity to cover 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	F3
Outlook	Stable	Positive	Stable
APS
Corporate credit rating	Baa1	BBB	BBB
Senior unsecured	Baa1	BBB	BBB+
Secured lease obligation bonds	Baa1	BBB	BBB+
Commercial paper	P-2	A-2	F3
Outlook	Stable	Positive	Stable

Off-Balance Sheet Arrangements

See Note 7 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

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Financial Assurances

See “Financial Assurances” in Note 10 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, 2012.

Contractual Obligations

As of June 30, 2012, certain contractual obligations have increased approximately $0.3 billion from December 31, 2011 as discussed in the 2011 Form 10-K.  As of June 30, 2012, the updated contractual obligations are as follows (dollars in billions):

Year	2012		2013-2014		2015-2016		Thereafter		Total
Fuel and purchased power commitments	$	0.3	$	1.0	$	1.1	$	6.8	$	9.2
Renewable energy credits	0.1		—		0.1		0.5		0.7

Changes have also occurred relating to long-term debt payments and interest.  See Note 2 for a discussion of these changes.

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 2011 Form 10-K.  See “Critical Accounting Policies” in Item 7 of the 2011 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

See Note 16 for adoption of amended accounting guidance relating to fair value measurements and disclosures and the presentation of comprehensive income.

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 trust fund (see Notes 14 and 15) and benefit plan assets.  The nuclear

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decommissioning trust fund and benefit plan assets also have risks associated with the changing value of their investments.  Nuclear decommissioning 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, 2012 and 2011 (dollars in millions):

	Six Months Ended June 30,
	2012			2011
Mark-to-market of net positions at beginning of period	$	(222	)	$	(239	)
Recognized in earnings (a):
Change in mark-to-market losses for future period deliveries	3			—
Decrease (increase) in regulatory asset	24			13
Recognized in OCI:
Change in mark-to-market gains (losses) for future period deliveries (b)	(37		)	(15		)
Mark-to-market losses realized during the period	37			40
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(195	)	$	(201	)

(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, 2012 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 2011 Form 10-K and Note 14 for more discussion of our valuation methods.

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Source of Fair Value	2012			2013			2014			2015			2016			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(75	)	$	(49	)	$	(22	)	$	(3	)	$	—		$	—		$	(149	)
Prices based on unobservable inputs	(7		)	(9		)	(6		)	(8		)	(6		)	(10		)	(46		)
Total by maturity	$	(82	)	$	(58	)	$	(28	)	$	(11	)	$	(6	)	$	(10	)	$	(195	)

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, 2012 and December 31, 2011 (dollars in millions):

	June 30, 2012 Gain (Loss)					December 31, 2011 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings (a)
Electricity	$	—	$	—		$	1	$	(1	)
Natural gas	—		—			—		—
Regulatory asset (liability) or OCI (b)	10		(10		)	—		—
Electricity	—		—			5		(5		)
Natural gas	28		(28		)	27		(27		)
Total	$	38	$	(38	)	$	33	$	(33	)

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

(b)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 14 for a discussion of our credit valuation adjustment policy.  See Note 8 for a further discussion of credit risk.

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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, 2012.  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.

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, 2012.  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, 2012 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 Part II, Item 5 of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, and “Business of Arizona Public Service Company – Environmental Matters” in Item 1 of the 2011 Form 10-K in regard to pending or threatened litigation or other disputes.

See Note 3 for ACC and FERC-related matters.

See Note 10 for information regarding FERC proceedings on Pacific Northwest energy market issues, environmental and climate change lawsuits, a Superfund matter 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 2011 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 2011 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

During the first quarter of 2012, we adopted amended guidance on the presentation of comprehensive income.  See Note 16.  The following unaudited information presents retrospective application of this new guidance to the consolidated financial statements of Pinnacle West Capital Corporation, and the consolidated financial statements of Arizona Public Service Company, as a separate comprehensive income statement for the years ended December 31, 2011, 2010, and 2009.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2011			2010			2009
NET INCOME	$	366,940		$	370,209		$	72,764
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $37,389, $61,348 and $61,329	(57,271		)	(93,939		)	(93,996		)
Reclassification of net realized loss, net of tax benefit of $46,288, $48,453 and $72,877	70,902			74,287			112,452
Pension and other postretirement benefits activity, net of tax benefit of $3,935, $5,608 and $2,264	(6,026		)	(8,528		)	(3,345		)
Total other comprehensive income (loss)	7,605			(28,180		)	15,111
COMPREHENSIVE INCOME	374,545			342,029			87,875
Less: Comprehensive income attributable to noncontrolling interests	27,467			20,156			4,434
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	347,078		$	321,873		$	83,441

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2011			2010			2009
NET INCOME	$	363,773		$	355,826		$	270,434
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $37,397, $61,358 and $61,317	(57,262		)	(93,929		)	(94,008		)
Reclassification of net realized loss, net of tax benefit of $46,298, $48,462 and $73,261	70,891			74,278			112,068
Pension and other postretirement benefits activity, net of tax benefit of $1,910, $4,493 and $1,361	(2,925		)	(6,848		)	(2,154		)
Total other comprehensive income (loss)	10,704			(26,499		)	15,906
COMPREHENSIVE INCOME	374,477			329,327			286,340
Less: Comprehensive income attributable to noncontrolling interests	27,524			20,163			19,209
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	346,953		$	309,164		$	267,131

Environmental Matters

Climate Change

Regulatory Initiatives.  In December 2009, the EPA determined that greenhouse gas emissions endanger public health and welfare.  This determination was made in response to a 2007 United States Supreme Court ruling that greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act.  As a result of this “endangerment finding,” the EPA determined that the Clean Air Act required new regulatory requirements for new and modified major greenhouse gas emitting sources, including power plants.  On June 3, 2010, the EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new greenhouse gas emissions thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits.  “New Source Review” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source.  The tailoring rule became effective on August 2, 2010 and it became applicable to power plants on January 2, 2011.  Several groups filed lawsuits challenging the EPA’s endangerment finding and the tailoring rule, but on June 26, 2012, the United States Court of Appeals for the District of Columbia Circuit issued its decision upholding the rules.

APS does not expect the tailoring rule to have a significant impact on its current operations.  The rule will require APS to consider the impact of greenhouse gas emissions as part of its traditional New Source Review analysis for new sources and major modifications to existing plants.

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EPA Environmental Regulation

Regional Haze Rules.  Over a decade ago, the EPA announced regional haze rules to reduce visibility impairment in national parks and wilderness areas.  The rules require states (or, for sources located on tribal land, the EPA) to determine what pollution control technologies constitute the “best available retrofit technology” (“BART”) for certain older major stationary sources.  The EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis.

The Four Corners and Navajo Generating Station participants’ obligations to comply with the EPA’s final BART determinations (and the Cholla Power Plant’s (“Cholla”) obligations to comply with Arizona Department of Environmental Quality’s (“ADEQ”) and EPA’s determinations), coupled with the financial impact of potential future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.

Cholla.  In 2007, ADEQ required APS to perform a BART analysis for Cholla pursuant to the Clean Air Visibility Rule.  APS completed the BART analysis for Cholla and submitted its BART recommendations to ADEQ on February 4, 2008.  The recommendations include the installation of certain pollution control equipment that APS believes constitutes BART.  ADEQ reviewed APS’s recommendations and submitted its proposed BART State Implementation Plan (“SIP”) for Cholla and other sources within the state on March 2, 2011.

On December 2, 2011, the EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental organizations, which alleged that the EPA failed to promulgate Federal Implementation Plans (“FIPs”) for states that have not yet submitted all or part of the required regional haze SIPs.  In accordance with the consent decree, on July 2, 2012, EPA issued a proposed BART rule applicable to Cholla proposing to approve ADEQ’s BART emissions limits for sulfur dioxide and particulate emissions, but proposing to disapprove ADEQ’s BART emissions limits for oxides of nitrogen (“NOx”), for which EPA is proposing to promulgate a FIP.  If finalized as proposed (the consent decree establishes a final promulgation deadline of November 15, 2012), EPA’s FIP would establish a new, more stringent NOx emissions rate for the two BART-eligible Cholla units owned by APS.  In order to comply with this new rate, APS would be required to install selective catalytic reduction technology on both units.  APS’s total costs for these post-combustion controls would be approximately $182 million, which is not included in our current environmental estimates described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 2.  Under the proposed rule, APS would have five years to complete installation of the equipment and achieve the BART emissions limits.  The EPA extended the original public comment period for this proposed BART rule, which now ends on September 18, 2012.  APS cannot currently predict the content of the final rule or the impact these extension requests may have on timing of the final rule.

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 the DOI, alleging that OSM failed to engage in mandatory Endangered Species Act (“ESA”) 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 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’

76

lawsuit without prejudice.  On May 14, 2012, the plaintiffs appealed the court’s order to the United States Court of Appeals for the Tenth Circuit.

Water Supply

Assured supplies of water are important for APS’s generating plants.  Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS operations.

Little Colorado River Adjudication.  APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985.  APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case.  APS’s claims dispute the court’s jurisdiction over its groundwater rights.  Alternatively, APS seeks confirmation of such rights.  Other claims have been identified as ready for litigation in motions filed with the court.  No trial date concerning APS’s water rights claims has been set in this matter.

A number of parties, including APS, the Navajo Nation, the Hopi Tribe, and other claimants in the Little Colorado River Adjudication have been engaged in settlement negotiations to resolve competing water claims.  On June 3, 2011, counsel for all the parties to the settlement discussions, including APS, signed, on behalf of their respective clients, a document expressing their agreement to recommend that the settlement be approved by their respective clients.  However, on July 5, 2012, the Navajo Nation Council voted not to approve the settlement agreement and to oppose various provisions of the federal legislation, which would implement the agreement.  As a result, we do not know when, or if, there will be a settlement among claimants in the Little Colorado River Adjudication.

Although the above matters remain subject to further evaluation, APS does not expect that the described litigation or settlement will have a material adverse impact on its financial position, results of operations or cash flows.

Nuclear Industry Matters

On June 8, 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel.  The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision.

Previous versions of the Waste Confidence Decision had expressed the NRC’s confidence, in a generic fashion, that high level nuclear waste and spent nuclear fuel could be safely stored on the sites of the country’s commercial nuclear power plants until a mined geologic repository becomes available.

The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act (“NEPA”), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions.  The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.  The NRC has not announced its intentions regarding the D.C. Circuit’s decision; therefore, APS is unable to predict the impact that the decision may have on its operation of Palo Verde.

77

Item 6.EXHIBITS

(a)           Exhibits

Exhibit No.	Registrant(s)	Description
10.1	APS	Supplemental Agreement dated June 19, 2012 between APS and Randall K. Edington
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, Senior 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, Senior 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

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Exhibit No.	Registrant(s)	Description
101.CAL*	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document
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, 2012		By:	/s/ James R. Hatfield
		James R. Hatfield
		Sr. 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, 2012		By:	/s/ James R. Hatfield
		James R. Hatfield
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)

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EX-10.1

Exhibit 10.1

SUPPLEMENTAL AGREEMENT BETWEEN

ARIZONA PUBLIC SERVICE COMPANY AND RANDALL K. EDINGTON

This Supplemental Agreement (the “Agreement”) is entered into by and between Arizona Public Service Company (the “Company”) and Randall K. Edington (“Executive”).

1.             Background.  The Company previously entered into a Supplemental Agreement dated December 26, 2008 (the “2008 Agreement”) with Executive.  By letter dated March 12, 2012 (the “Letter Agreement”), the Company and Executive agreed to certain additions to the terms and conditions of Executive’s employment to those set forth in the 2008 Agreement, subject to the receipt of appropriate corporate approval which was obtained on June 20, 2012.

2.             Effective Date.  Except as otherwise noted below, this Agreement shall be effective as of the date on which it is executed.  This Agreement supersedes and replaces the Letter Agreement as to all matters addressed herein and therein.

3.             Salary Increases.  Effective as of January 1, 2012, Executive’s base salary shall be increased to $900,000.  Effective as of January 1, 2013, Executive’s base salary shall be increased to $925,000, and effective as of January 1, 2014, Executive’s base salary shall be increased to $950,000.

4.             2014 Supplemental Pension Benefit.  In addition to the pension benefit set forth in the 2008 Agreement, if Executive is actively employed by the Company on December 31, 2013, the supplemental pension benefit amount calculated in accordance with the first paragraph of Section 5(b) of the 2008 Agreement shall be increased by an amount equal to 5% of the benefit that would have otherwise been payable. If Executive is actively employed by the Company on December 31, 2014, the supplemental pension benefit amount calculated in accordance with the first paragraph of Section 5(b) (prior to the increase called for by the preceding sentence) shall be increased by an amount equal to 10% of the benefit that would have otherwise been payable.

5.             Supplemental Deferred Compensation Arrangement.  The Company shall provide Executive with a deferred compensation benefit that will be credited in three equal installments to accounts established for the benefit of Executive and will vest in accordance with the terms and conditions described in the attached Exhibit A.

6.             Potential Repurchase of Arizona Home.  If Executive incurs a termination of employment after December 31, 2014, and within six months of such termination of employment, Executive decides to relocate from Arizona but is unable to sell his Arizona home for a net price equal to Executive’s original purchase price (after making reasonable efforts to do so), the Company will purchase Executive’s primary Arizona residence for the original purchase price.  If Executive terminates employment due to death or disability prior to December 31, 2014, and within six months of Executive’s termination of employment, Executive (or Executive’s executor or representative) decides to relocate from Arizona but is unable to sell Executive’s Arizona home for a net price equal to the original purchase price (after making reasonable efforts to do so), the Company will purchase Executive’s primary Arizona residence for the original purchase price.  For purposes of this Agreement, the term “disability” shall have

the meaning ascribed to it in the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates, and the term “original purchase price” shall mean the agreed price contracted between Executive and the original seller and shall not include any real estate commissions or settlement charges which may have been paid by Executive as part of the purchase transaction.

7.             Amendment of 2011 and 2012 Restricted Stock Unit Agreements.  The definition of “Retirement” in clause (i) of the second paragraph of Section 3 of each of the February 15, 2011 and February 21, 2012 Restricted Stock Unit Agreements under the Pinnacle West Capital Corporation 2007 and 2012 Long-Term Incentive Plans issued to Executive is hereby amended as follows:

(i) “Retirement” means Employee’s Separation from Service (as defined in the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (as in effect on the date of this Amendment)) for any reason on or after December 31, 2014,

8.             Amendments of Supplemental 2010 Award.  The February 15, 2011 Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan issued to Executive (Supplemental 2010 Award) (the “Supplemental 2010 Award Agreement”) is hereby amended by the addition of the following new sentence to the end of Section 3 thereof:

In addition, the Restricted Stock Units will fully vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement upon Employee’s Retirement.  For purposes of this Agreement, “Retirement” means Employee’s Separation from Service for any reason on or after December 31, 2014.

Section 4(a) of the Supplemental 2010 Award Agreement is also amended by deleting the first sentence thereof.

9.             Impact on 2008 Agreement.  This Agreement supplements the 2008 Agreement which otherwise remains in full force and effect.

10.          Status of Exhibit.  Exhibit A is deemed to be a part of this Agreement as if fully set forth herein.

[REMAINDER OF PAGE INTENTIONALLY BLANK]

2

IN WITNESS WHEREOF, the Company and Executive have caused this Agreement to be executed as of the date set forth below.

ARIZONA PUBLIC SERVICE COMPANY
By:	/s/ Donald E. Brandt
	Its: Chief Executive Officer
6/19/2012
Date
EXECUTIVE
/s/ Randall K. Edington
Randall K. Edington
6/19/2012
Date

3

Exhibit A

SUPPLEMENTAL DEFERRED COMPENSATION PROGRAM

FOR RANDALL K. EDINGTON

1.             Purpose.  By an Agreement approved on June 20, 2012 between Arizona Public Service Company (the “Company”) and Randall K. Edington (“Executive”), the Company agreed to establish a supplemental deferred compensation arrangement for the benefit of Executive (the “Supplemental Deferred Compensation Benefit”).  The purpose of this document is to establish this arrangement through Discretionary Credits to accounts established for the benefit of Executive pursuant to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (the “Deferred Compensation Plan”).

2.             Definitions.  Defined terms used herein shall have the respective meanings ascribed to them in the Deferred Compensation Plan.

3.             Discretionary Credits.  Three Discretionary Credits in the aggregate amount of $1,050,000 will be allocated to three Discretionary Credit Accounts (“Discretionary Credit Account A,” “Discretionary Credit Account B” and “Discretionary Credit Account C”) established for the benefit of Executive pursuant to Section 3.9 of the Deferred Compensation Plan.  Discretionary Credit Account A shall be credited with $350,000 as of January 1, 2012.  Discretionary Credit Account B shall be credited with $350,000 on January 1, 2013 and Discretionary Credit Account C shall be credited with $350,000 on January 1, 2014.

4.             Interest.  The Discretionary Credit Accounts shall be credited with interest in accordance with Sections 3.5 and 3.7(a) of the Deferred Compensation Plan.  Discretionary Credit Account A shall be credited with interest from January 1, 2012.  Discretionary Credit Account B shall be credited with interest from January 1, 2013 and Discretionary Credit Account C shall be credited with interest from January 1, 2014.

5.             Vesting.  The Discretionary Credit Accounts vest on December 31, 2014.  If Executive Separates from Service prior to December 31, 2014, the amounts allocated to the Discretionary Credit Accounts will be forfeited; provided, however, that if Executive Separates from Service due to death or Disability prior to December 31, 2014, all amounts previously credited to the Discretionary Credit Accounts prior to the date of such Separation from Service will be fully vested.

6.             Payment of Discretionary Credits.  Executive’s vested interest in his Discretionary Credit Accounts will be paid to Executive (or to the Beneficiary designated by Executive pursuant to the Deferred Compensation Plan in the event of Executive’s death) in installments over a period of 10 years following Executive’s Separation from Service in accordance with Sections 3.7 and 5.1 of the Deferred Compensation Plan.  As provided in the Deferred Compensation Plan, the first installment payment shall be made within 30 days following Executive’s Separation from Service, unless Executive is a Specified Employee on the date of his Separation from Service.  If Executive is a Specified Employee on the date of his Separation from Service, the payment of Executive’s vested interest in his Discretionary Credit Accounts may not commence prior to the first day of the seventh month following Executive’s

A-1

Separation from Service.  The Discretionary Credit Accounts may not be distributed as a Short-Term Payout or due to an Unforeseeable Financial Emergency.

7.             Executive’s Plan Status.  This document shall be deemed to be Executive’s Election Form with respect to the Discretionary Credits for purposes of Section 2.2 of the Deferred Compensation Plan.

8.             Relationship to Other Benefits.  The Discretionary Credits allocated to Executive shall not be taken into account as compensation or for purposes of determining any benefits due to Executive pursuant to the terms of any pension, retirement, savings, profit sharing, incentive, group insurance or other tax qualified or nonqualified benefit plan sponsored by the Company, Pinnacle West Capital Corporation or any affiliate of either.  In addition, any amounts payable to Executive pursuant to this document shall be disregarded for purposes of the benefit plans referred to in the preceding sentence.

9.             Plan Document.  This Program is established pursuant to the provisions of Section 3.9 of the Deferred Compensation Plan.  Accordingly, except as otherwise set forth in this document, the provisions of the Deferred Compensation Plan shall apply in determining the rights of Executive as well as the administration of Executive’s Discretionary Credit Accounts.  In cases of conflict, this document controls over any conflicting provisions of the Deferred Compensation Plan, except as may be required by Section 409A of the Internal Revenue Code or the provisions of any other applicable law or regulation.

10.          Amendments.  This document may not be modified, altered or changed, except by a written agreement signed by the Company and Executive.

11.          Entire Agreement.  This document and the Deferred Compensation Plan constitute the entire agreement between the Company and Executive regarding the Supplemental Deferred Compensation Arrangement.

12.          Severability.  If any provision of this document is held to be invalid, the remaining provisions shall remain in full force and effect.

A-2

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,
	2012		2011		2010		2009		2008		2007
Earnings:
Income from continuing operations attributable to common shareholders	$	115,681	$	328,110	$	324,688	$	236,839	$	259,871	$	286,512
Income taxes	72,044		183,604		160,869		138,551		95,231		144,673
Fixed charges	112,457		246,462		248,664		241,807		224,760		213,801
Total earnings	$	300,182	$	758,176	$	734,221	$	617,197	$	579,862	$	644,986
Fixed Charges:
Interest expense	$	109,967	$	241,995	$	244,174	$	237,766	$	220,223	$	209,624
Estimated interest portion of annual rents	2,490		4,467		4,490		4,041		4,537		4,177
Total fixed charges	$	112,457	$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Ratio of Earnings to Fixed Charges (rounded down)	2.66		3.07		2.95		2.55		2.57		3.01

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,
	2012		2011		2010		2009		2008		2007
Earnings:
Income from continuing operations attributable to common shareholders	$	120,823	$	336,249	$	335,663	$	251,225	$	262,344	$	283,940
Income taxes	76,146		192,542		170,465		152,574		107,261		151,157
Fixed charges	109,945		238,286		234,184		227,274		206,896		195,144
Total earnings	$	306,914	$	767,077	$	740,312	$	631,073	$	576,501	$	630,241
Fixed Charges:
Interest charges	$	105,524	$	229,326	$	225,269	$	218,969	$	197,964	$	186,702
Amortization of debt discount	2,112		4,616		4,559		4,675		4,702		4,639
Estimated interest portion of annual rents	2,309		4,344		4,356		3,630		4,230		3,803
Total fixed charges	$	109,945	$	238,286	$	234,184	$	227,274	$	206,896	$	195,144
Ratio of Earnings to Fixed Charges (rounded down)	2.79		3.21		3.16		2.77		2.78		3.22

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,
	2012		2011		2010		2009		2008		2007
Earnings:
Income from continuing operations attributable to common shareholders	$	115,681	$	328,110	$	324,688	$	236,839	$	259,871	$	286,512
Income taxes	72,044		183,604		160,869		138,551		95,231		144,673
Fixed charges	112,457		246,462		248,664		241,807		224,760		213,801
Total earnings	$	300,182	$	758,176	$	734,221	$	617,197	$	579,862	$	644,986
Fixed Charges:
Interest expense	$	109,967	$	241,995	$	244,174	$	237,766	$	220,223	$	209,624
Estimated interest portion of annual rents	2,490		4,467		4,490		4,041		4,537		4,177
Total fixed charges	$	112,457	$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	187,725	$	511,714	$	485,557	$	375,390	$	355,102	$	431,185
Net income from continuing operations attributable to common shareholders	115,681		328,110		324,688		236,839		259,871		286,512
Ratio of income before income taxes to net income	1.62		1.56		1.50		1.59		1.37		1.50
Preferred stock dividends	—		—		—		—		—		—
Preferred stock dividend requirements — ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	112,457	$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Preferred stock dividend requirements	—		—		—		—		—		—
Total	$	112,457	$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Ratio of Earnings to Fixed Charges (rounded down)	2.66		3.07		2.95		2.55		2.57		3.01

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, 2012.

/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, 2012.

/s/ James R. Hatfield

James R. Hatfield

Senior 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, 2012.

/s/ Donald E. Brandt

Donald E. Brandt

Chairman 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, 2012.

/s/ James R. Hatfield

James R. Hatfield

Senior 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 fiscal quarter ended June 30, 2012 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, 2012.

/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 fiscal quarter ended June 30, 2012 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, 2012.

/s/ James R. Hatfield

James R. Hatfield

Senior 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 fiscal quarter ended June 30, 2012 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, 2012.

/s/ Donald E. Brandt

Donald E. Brandt

Chairman 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 fiscal quarter ended June 30, 2012 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, 2012.

/s/ James R. Hatfield

James R. Hatfield

Senior Vice President and

Chief Financial Officer

XML

Long-Term Debt and Liquidity Matters (Details) (USD $)																1 Months Ended		1 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Pinnacle West	Dec. 31, 2011 Pinnacle West	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC Minimum	Jun. 30, 2012 Long term debt ARIZONA PUBLIC SERVICE COMPANY item	Jun. 30, 2012 Revolving credit facility maturing in 2015 ARIZONA PUBLIC SERVICE COMPANY	Jun. 30, 2012 Revolving credit facility maturing in 2016 Pinnacle West	Jun. 30, 2012 Revolving credit facility maturing in 2016 ARIZONA PUBLIC SERVICE COMPANY	Jun. 30, 2012 Pollution Control Revenue Refunding Bonds, 2009 Series B ARIZONA PUBLIC SERVICE COMPANY	May 01, 2012 Pollution Control Revenue Refunding Bonds, 2009 Series B ARIZONA PUBLIC SERVICE COMPANY	Jun. 02, 2012 Pollution Control Revenue Refunding Bonds, 2009 Series A ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 2012 6.50% senior notes due March 1, 2012 ARIZONA PUBLIC SERVICE COMPANY	Mar. 01, 2012 6.50% senior notes due March 1, 2012 ARIZONA PUBLIC SERVICE COMPANY	Jan. 31, 2012 4.50% unsecured senior notes that mature on April 1, 2042 ARIZONA PUBLIC SERVICE COMPANY	Jan. 13, 2012 4.50% unsecured senior notes that mature on April 1, 2042 ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters
Number of line of credit facilities									2
Carrying Amount	$ 3,429,000,000	$ 3,496,000,000	$ 125,000,000	$ 125,000,000	$ 3,304,000,000	$ 3,371,000,000
Daily rate (as a percent)													0.17%
Interest rate (as a percent)															1.25%		6.50%		4.50%
Repayment of debt																375,000,000
Current borrowing capacity on credit facility									1,000,000,000	500,000,000	200,000,000	500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders										700,000,000	300,000,000	700,000,000
Notes issued																		325,000,000
Commercial paper borrowings outstanding									109,000,000
Maximum commercial paper support available under credit facility									250,000,000		200,000,000
Aggregate outstanding amount														32,000,000	38,000,000
Estimated fair value of long-term debt, including current maturities
Fair Value	3,917,000,000	3,926,000,000	123,000,000	123,000,000	3,794,000,000	3,803,000,000
Debt Provisions
Total shareholder equity	3,778,035,000	3,821,850,000			3,902,791,000	3,943,007,000	3,900,000,000
Total capitalization							7,100,000,000
Dividend restrictions, shareholder equity required								$ 2,800,000,000
Required common equity ratio ordered by ACC (as a percent)								40.00%

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Earnings Per Share (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$ 1.12	$ 0.79	$ 1.06	$ 0.64
Income (loss) from discontinued operations (in dollars per share)		$ 0.01	$ (0.02)	$ 0.02
Earnings per share - basic (in dollars per share)	$ 1.12	$ 0.80	$ 1.04	$ 0.66
Diluted earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$ 1.12	$ 0.78	$ 1.05	$ 0.64
Income (loss) from discontinued operations (in dollars per share)	$ (0.01)	$ 0.01	$ (0.01)	$ 0.01
Earnings per share - diluted (in dollars per share)	$ 1.11	$ 0.79	$ 1.04	$ 0.65
Dilutive stock options and performance shares	868,000	674,000	788,000	601,000

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Derivative Accounting (Details 2) (Commodity Contracts, USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	$ 4,509,000	$ (16,323,000)	$ (37,394,000)	$ (15,335,000)
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized)	(23,015,000)	(25,287,000)	(37,515,000)	(40,133,000)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	32,000	(176,000)	117,000	(164,000)
Amount reclassified from AOCI to earnings related to discontinued cash flow hedges	1,800,000		1,800,000
Estimated net loss before income taxes to be reclassified from accumulated other comprehensive income			77,000,000
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	26,129,000	(3,395,000)	751,000	(10,915,000)
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	87,000	(503,000)	(239,000)	1,004,000
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	$ 26,042,000	$ (2,892,000)	$ 990,000	$ (11,919,000)

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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, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Other income:
Interest income	$ 107	$ 543	$ 712	$ 935
Investment gains - net		12		1,307
Miscellaneous	70	2	225	5
Total other income	177	557	937	2,247
Other expense:
Non-operating costs	(2,389)	(1,629)	(4,239)	(3,119)
Miscellaneous	(222)	(1,557)	(2,386)	(1,808)
Total other expense	(2,669)	(3,186)	(6,737)	(4,927)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	77	89	184	219
Investment gains - net		268		1,418
Miscellaneous	941	876	1,344	1,574
Total other income	1,018	1,233	1,528	3,211
Other expense:
Non-operating costs	(2,941)	(2,400)	(4,682)	(4,214)
Asset dispositions	(195)		(418)	(823)
Miscellaneous	(857)	(2,251)	(3,517)	(3,206)
Total other expense	$ (3,993)	$ (4,651)	$ (8,617)	$ (8,243)

XML

Discontinued Operations (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Discontinued Operations
Revenue		$ 17,000,000		$ 29,000,000
Income (loss) before taxes	(1,000,000)	1,000,000	(3,000,000)	2,000,000
Income (loss) after taxes	(819,000)	684,000	(1,593,000)	1,387,000
SunCor
Discontinued Operations
Revenue		2,000,000		3,000,000
APSES
Discontinued Operations
Revenue		$ 15,000,000		$ 26,000,000

XML

Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 7,766,000	$ 7,154,000	$ 15,542,000	$ 12,615,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	130,929,000		130,929,000		132,864,000
Current maturities of long-term debt	57,962,000		57,962,000		477,435,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	57,420,000		57,420,000		65,547,000
Equity-Noncontrolling interests	121,302,000		121,302,000		108,736,000
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	7,766,000	7,184,000	15,533,000	12,654,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	130,929,000		130,929,000		132,864,000
Current maturities of long-term debt	57,962,000		57,962,000		477,435,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	57,420,000		57,420,000		65,547,000
Equity-Noncontrolling interests	121,302,000		121,302,000		108,399,000
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	8,000,000		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	131,000,000		131,000,000		133,000,000
Current maturities of long-term debt	26,000,000		26,000,000		31,000,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	57,000,000		57,000,000		66,000,000
Equity-Noncontrolling interests	121,000,000		121,000,000		108,000,000
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			$ 83,000,000

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Other Income and Other Expense (Tables)

6 Months Ended

Jun. 30, 2012

Other Income and Other Expense

Detail of other income and other expense

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	107		$	543		$	712		$	935
Investment gains — net	—			12			—			1,307
Miscellaneous	70			2			225			5
Total other income	$	177		$	557		$	937		$	2,247
Other expense:
Non-operating costs	$	(2,389	)	$	(1,629	)	$	(4,239	)	$	(3,119	)
Investment losses — net	(58		)	—			(112		)	—
Miscellaneous	(222		)	(1,557		)	(2,386		)	(1,808		)
Total other expense	$	(2,669	)	$	(3,186	)	$	(6,737	)	$	(4,927	)

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 69
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	67
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 2

XML

Long-Term Debt and Liquidity Matters (Tables)

6 Months Ended

Jun. 30, 2012

Long-Term Debt and Liquidity Matters

Schedule of estimated fair value of long-term debt, including current maturities

	As of June 30, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	123	$	125	$	123
APS	3,304		3,794		3,371		3,803
Total	$	3,429	$	3,917	$	3,496	$	3,926

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Changes in Equity (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Changes in equity
Balance at beginning of period	$ 3,861,429	$ 3,728,771	$ 3,930,586	$ 3,775,226
Net income	130,111	93,839	129,630	84,165
Other comprehensive income	17,459	6,646	1,845	17,092
COMPREHENSIVE INCOME	147,570	100,485	131,475	101,257
Issuance of capital stock	2,525	3,505	5,225	17,065
Reissuance of treasury stock - net	5,113		3,359	(3,530)
Other (primarily stock compensation)	631	(33)	3,981	(181)
Dividends on common stock	(114,955)	(114,509)	(172,313)	(171,618)
Net capital activities by noncontrolling interests	(2,976)	(2,609)	(2,976)	(2,609)
Balance at end of period	3,899,337	3,715,610	3,899,337	3,715,610
Common Shareholders
Changes in equity
Balance at beginning of period	3,744,917	3,631,411	3,821,850	3,683,327
Net income	122,345	86,685	114,088	71,550
Other comprehensive income	17,459	6,646	1,845	17,092
COMPREHENSIVE INCOME	139,804	93,331	115,933	88,642
Issuance of capital stock	2,525	3,505	5,225	17,065
Reissuance of treasury stock - net	5,113		3,359	(3,530)
Other (primarily stock compensation)	631	(33)	3,981	(181)
Dividends on common stock	(114,955)	(114,509)	(172,313)	(171,618)
Balance at end of period	3,778,035	3,613,705	3,778,035	3,613,705
Noncontrolling Interests
Changes in equity
Balance at beginning of period	116,512	97,360	108,736	91,899
Net income	7,766	7,154	15,542	12,615
COMPREHENSIVE INCOME	7,766	7,154	15,542	12,615
Net capital activities by noncontrolling interests	(2,976)	(2,609)	(2,976)	(2,609)
Balance at end of period	$ 121,302	$ 101,905	$ 121,302	$ 101,905

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Regulatory Matters (Details 3) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Detail of regulatory liabilities
Regulatory liabilities, current	$ 90,000,000	$ 88,000,000
Regulatory liabilities, non-current	738,693,000	737,332,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	25,000,000	22,000,000
Regulatory liabilities, non-current	340,000,000	349,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, non-current	240,000,000	225,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	46,000,000	54,000,000
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, non-current	60,000,000	59,000,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	9,000,000	5,000,000
Regulatory liabilities, non-current	38,000,000	44,000,000
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	3,000,000	2,000,000
Regulatory liabilities, non-current	13,000,000	14,000,000
Income taxes-deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	1,000,000	1,000,000
Regulatory liabilities, non-current	33,000,000	30,000,000
Other
Detail of regulatory liabilities
Regulatory liabilities, current	6,000,000	4,000,000
Regulatory liabilities, non-current	$ 15,000,000	$ 16,000,000

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Nuclear Decommissioning Trust (Tables)

6 Months Ended

Jun. 30, 2012

Nuclear Decommissioning Trust

Fair value of APS's nuclear decommissioning trust fund assets

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2012
Equity securities	$	192		$	58	$	(1	)
Fixed income securities	359			24		—
Net payables (a)	(6		)	—		—
Total	$	545		$	82	$	(1	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2011
Equity securities	$	175		$	44	$	(1	)
Fixed income securities	340			23		(1		)
Net payables (a)	(1		)	—		—
Total	$	514		$	67	$	(2	)

(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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Realized gains	$	2		$	2		$	4		$	3
Realized losses	(1		)	(1		)	(2		)	(3		)
Proceeds from the sale of securities (a)	119			110			211			300

(a)Proceeds are reinvested in the trust.

Fair value of fixed income securities, summarized by contractual maturities

	Fair Value
Less than one year	$	24
1 year - 5 years	82
5 years - 10 years	103
Greater than 10 years	150
Total	$	359

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Commitments and Contingencies (Details 2) (USD $)	6 Months Ended	1 Months Ended
	Jun. 30, 2012	Jan. 31, 2012 Lawsuit item	Sep. 30, 2011 Lawsuit item	Feb. 29, 2008 Climate Change Lawsuit item	Sep. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY item	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY	Sep. 08, 2011 ARIZONA PUBLIC SERVICE COMPANY	Jun. 30, 2012 Fuel and purchased power commitments	Jun. 30, 2012 Renewable energy credits
Contractual Obligations
Contractual obligations increase	$ 300,000,000
2012								300,000,000	100,000,000
2013								500,000,000
2014								600,000,000
2015								500,000,000	100,000,000
2016								500,000,000
Thereafter								6,800,000,000	500,000,000
Total commitments								9,200,000,000	700,000,000
Superfund
Number of consumer class action complaints filed		1	2
Number of oil companies				9
Number of power companies				14
Costs related to investigation and study under Superfund site					1,000,000
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 (in minutes)					10
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							1,000,000
Financial Assurances
Outstanding letters of credit to support existing variable interest rate pollution control bonds						76,000,000
Letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions						44,000,000
Letters of credit issued to support natural gas tolling contract obligations						40,000,000
Outstanding letters of credit to support natural gas tolling contract obligations						$ 65,000,000

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Changes in Equity (APSC) (Tables)

6 Months Ended

Jun. 30, 2012

Changes in shareholders' equity and changes in equity of noncontrolling interests

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,744,917		$	116,512		$	3,861,429		$	3,631,411		$	97,360		$	3,728,771
Net income	122,345			7,766			130,111			86,685			7,154			93,839
Other comprehensive income	17,459			—			17,459			6,646			—			6,646
Total comprehensive income	139,804			7,766			147,570			93,331			7,154			100,485
Issuance of capital stock	2,525			—			2,525			3,505			—			3,505
Reissuance of treasury stock - net	5,113			—			5,113			—			—			—
Other (primarily stock compensation)	631			—			631			(33		)	—			(33		)
Dividends on common stock	(114,955		)	—			(114,955		)	(114,509		)	—			(114,509		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,821,850		$	108,736		$	3,930,586		$	3,683,327		$	91,899		$	3,775,226
Net income	114,088			15,542			129,630			71,550			12,615			84,165
Other comprehensive income	1,845			—			1,845			17,092			—			17,092
Total comprehensive income	115,933			15,542			131,475			88,642			12,615			101,257
Issuance of capital stock	5,225			—			5,225			17,065			—			17,065
Reissuance (purchase) of treasury stock - net	3,359			—			3,359			(3,530		)	—			(3,530		)
Other (primarily stock compensation)	3,981			—			3,981			(181		)	—			(181		)
Dividends on common stock	(172,313		)	—			(172,313		)	(171,618		)	—			(171,618		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

ARIZONA PUBLIC SERVICE COMPANY

Changes in shareholders' equity and changes in equity of noncontrolling interests

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,865,748		$	116,166		$	3,981,914		$	3,766,131		$	96,554		$	3,862,685
Net income	124,928			7,766			132,694			87,705			7,184			94,889
OCI	17,117			—			17,117			6,730			—			6,730
Total comprehensive income	142,045			7,766			149,811			94,435			7,184			101,619
Dividends on common stock	(105,000		)	—			(105,000		)	(114,500		)	—			(114,500		)
Net capital activities by noncontrolling interests	—			(2,630		)	(2,630		)	—			(2,610		)	(2,610		)
Other	(2		)	—			(2		)	1			—			1
Ending balance, June 30	$	3,902,791		$	121,302		$	4,024,093		$	3,746,067		$	101,128		$	3,847,195

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,943,007		$	108,399		$	4,051,406		$	3,824,953		$	91,084		$	3,916,037
Net income	120,823			15,533			136,356			75,625			12,654			88,279
OCI	1,362			—			1,362			17,088			—			17,088
Total comprehensive income	122,185			15,533			137,718			92,713			12,654			105,367
Dividends on common stock	(162,400		)	—			(162,400		)	(171,600		)	—			(171,600		)
Net capital activities by noncontrolling interests	—			(2,630		)	(2,630		)	—			(2,610		)	(2,610		)
Other	(1		)	—			(1		)	1			—			1
Ending balance, June 30	$	3,902,791		$	121,302		$	4,024,093		$	3,746,067		$	101,128		$	3,847,195

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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, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
NET INCOME	$ 130,111	$ 93,839	$ 129,630	$ 84,165
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(1,781) and $6,449 for three months ended June 30, 2012 and 2011 and $14,773 and $6,059 for six months ended June 30, 2012 and 2011, respectively	2,728	(9,875)	(22,624)	(9,277)
Reclassification of net realized loss, net of tax benefit of $9,092 and $9,990 for three months ended June 30, 2012 and 2011 and $14,820 and $15,855 for six months ended June 30, 2012 and 2011, respectively	13,925	15,299	22,697	24,281
Pension and other postretirement benefits activity, net of tax expense $305 and $853 for three months ended June 30, 2012 and 2011 and $841 and $1,362 for six months ended June 30, 2012 and 2011, respectively	806	1,222	1,772	2,088
Total other comprehensive income	17,459	6,646	1,845	17,092
COMPREHENSIVE INCOME	147,570	100,485	131,475	101,257
Less: Comprehensive income attributable to noncontrolling interests	7,766	7,154	15,542	12,615
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	139,804	93,331	115,933	88,642
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	132,694	94,889	136,356	88,279
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(1,781) and $6,449 for three months ended June 30, 2012 and 2011 and $14,773 and $6,059 for six months ended June 30, 2012 and 2011, respectively	2,727	(9,875)	(22,621)	(9,277)
Reclassification of net realized loss, net of tax benefit of $9,092 and $9,990 for three months ended June 30, 2012 and 2011 and $14,820 and $15,855 for six months ended June 30, 2012 and 2011, respectively	13,922	15,297	22,694	24,278
Pension and other postretirement benefits activity, net of tax expense $305 and $853 for three months ended June 30, 2012 and 2011 and $841 and $1,362 for six months ended June 30, 2012 and 2011, respectively	468	1,308	1,289	2,087
Total other comprehensive income	17,117	6,730	1,362	17,088
COMPREHENSIVE INCOME	149,811	101,619	137,718	105,367
Less: Comprehensive income attributable to noncontrolling interests	7,766	7,184	15,533	12,654
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$ 142,045	$ 94,435	$ 122,185	$ 92,713

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Derivative Accounting (Details)	Jun. 30, 2012 item
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	9,914
British thermal units equivalent to one MMBCF	178
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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Long-Term Debt and Liquidity Matters

6 Months Ended

Jun. 30, 2012

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, 2012, 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, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029.  On June 1, 2012 we remarketed these bonds.  Currently, the interest rate on these bonds is reset daily by a remarketing agent.  The daily rate at June 30, 2012 was 0.17%.  Additionally, the bonds are supported by a letter of credit.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A.  The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014.  During this time, the bonds will bear interest at a rate of 1.25% per annum.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2012 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2011.

At June 30, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, 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, 2012, APS had commercial paper borrowings of $109 million, and no outstanding borrowings or letters of credit under these facilities.

See “Financial Assurances” in Note 10 for 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 14 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, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	123	$	125	$	123
APS	3,304		3,794		3,371		3,803
Total	$	3,429	$	3,917	$	3,496	$	3,926

Debt Provisions

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, 2012, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $3.9 billion, and total capitalization was approximately $7.1 billion.  APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $2.8 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 or ability to pay dividends to shareholders.

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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, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Net unrealized gain (loss), tax benefit (expense)	$ (1,781)	$ 6,448	$ 14,770	$ 6,058
Reclassification of net realized loss, tax benefit	9,090	9,988	14,818	15,852
Pension and other postretirement benefits activity, tax expense	526	797	1,157	1,363
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized gain (loss), tax benefit (expense)	(1,781)	6,449	14,773	6,059
Reclassification of net realized loss, tax benefit	9,092	9,990	14,820	15,855
Pension and other postretirement benefits activity, tax expense	$ 305	$ 853	$ 841	$ 1,362

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Retirement Plans and Other Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Defined Pension and Other Postretirement Benefit Costs
Amount of pension and other postretirement benefit costs deferred	$ 5	$ 3	$ 14	$ 6
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	15	13	32	29
Interest cost on benefit obligation	30	31	60	62
Expected return on plan assets	(35)	(33)	(71)	(67)
Amortization of prior service cost			1	1
Amortization of net actuarial loss	12	7	22	13
Net periodic benefit cost	22	18	44	38
Portion of cost charged to expense	8	7	13	15
Contributions
Expected contributions in 2012	65		65
Expected contributions in 2013	150		150
Expected contributions in 2014	160		160
Contributions paid during the period			15
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	6	5	14	11
Interest cost on benefit obligation	11	12	23	23
Expected return on plan assets	(11)	(11)	(23)	(21)
Amortization of net actuarial loss	4	4	10	8
Net periodic benefit cost	10	10	24	21
Portion of cost charged to expense	3	4	6	8
Contributions
Expected contributions in 2012	20		20
Expected contributions in 2013	20		20
Expected contributions in 2014	$ 20		$ 20

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2012

Palo Verde Sale Leaseback Variable Interest Entities

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

	June 30, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	131	$	133
Current maturities of long-term debt	26		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	57		66
Equity — Noncontrolling interests	121		108

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Business Segments (Tables)

6 Months Ended

Jun. 30, 2012

Business Segments

Financial data by business segment

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Operating revenues:
Regulated electricity segment	$	878		$	799	$	1,498		$	1,447
All other	1			1		1			2
Total	$	879		$	800	$	1,499		$	1,449
Net income attributable to common shareholders:
Regulated electricity segment	$	123		$	86	$	117		$	71
All other (a)	(1		)	1		(3		)	1
Total	$	122		$	87	$	114		$	72

	As of June 30, 2012		As of December 31, 2011
Assets:
Regulated electricity segment	$	13,178	$	13,068
All other (a)	36		43
Total	$	13,214	$	13,111

(a)All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.  See Note 13 for discussion of discontinued operations.

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Fair Value Measurements (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Assets
Nuclear decommissioning trust	$ 544,933,000		$ 544,933,000		$ 513,733,000
Risk management activities: commodity contracts	73,517,000		73,517,000		79,586,000
Total assets	69,000,000		69,000,000
Liabilities
Risk management activities: commodity contracts	(172,996,000)		(172,996,000)		(136,463,000)
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs
Net derivative balance at beginning of period	(58,000,000)	(48,000,000)	(51,000,000)	(38,000,000)
Total net gains (losses) realized/unrealized:
Included in earnings	1,000,000		2,000,000	1,000,000
Included in OCI	3,000,000	(3,000,000)	(2,000,000)	(1,000,000)
Deferred as a regulatory asset or liability	12,000,000	1,000,000	7,000,000	(6,000,000)
Settlements	(1,000,000)	4,000,000		4,000,000
Transfers into Level 3 from Level 2		1,000,000	2,000,000	(4,000,000)
Transfers from Level 3 into Level 2	(2,000,000)	(2,000,000)	(3,000,000)	(3,000,000)
Net derivative balance at end of period	(45,000,000)	(47,000,000)	(45,000,000)	(47,000,000)
Net unrealized gains included in earnings related to instruments still held at end of period				1,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Nuclear decommissioning trust	84,000,000		84,000,000		69,000,000
Cash Equivalents	2,000,000		2,000,000
Total assets	86,000,000		86,000,000		69,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Nuclear decommissioning trust	84,000,000		84,000,000		69,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Nuclear decommissioning trust	467,000,000		467,000,000		446,000,000
Risk management activities: commodity contracts	50,000,000		50,000,000		70,000,000
Total assets	517,000,000		517,000,000		516,000,000
Liabilities
Risk management activities: commodity contracts	(199,000,000)		(199,000,000)		(241,000,000)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Nuclear decommissioning trust	192,000,000		192,000,000		175,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	15,000,000		15,000,000		9,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	69,000,000		69,000,000		73,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	84,000,000		84,000,000		78,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Nuclear decommissioning trust	94,000,000		94,000,000		90,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Nuclear decommissioning trust	13,000,000		13,000,000		21,000,000
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Risk management activities: commodity contracts	69,000,000		69,000,000		74,000,000
Total assets	69,000,000		69,000,000		74,000,000
Liabilities
Risk management activities: commodity contracts	(114,000,000)		(114,000,000)		(125,000,000)
Fair value measurement on a recurring basis | Other
Assets
Nuclear decommissioning trust	(6,000,000)		(6,000,000)		(1,000,000)
Risk management activities: commodity contracts	(45,000,000)		(45,000,000)		(64,000,000)
Total assets	(51,000,000)		(51,000,000)		(65,000,000)
Liabilities
Risk management activities: commodity contracts	140,000,000		140,000,000		229,000,000
Fair value measurement on a recurring basis | Other | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	(6,000,000)		(6,000,000)		(1,000,000)
Fair value measurement on a recurring basis | Fair Value
Assets
Nuclear decommissioning trust	545,000,000		545,000,000		514,000,000
Cash Equivalents	2,000,000		2,000,000
Risk management activities: commodity contracts	74,000,000		74,000,000		80,000,000
Total assets	621,000,000		621,000,000		594,000,000
Liabilities
Risk management activities: commodity contracts	(173,000,000)		(173,000,000)		(137,000,000)
Fair value measurement on a recurring basis | Fair Value | US commingled equity funds
Assets
Nuclear decommissioning trust	192,000,000		192,000,000		175,000,000
Fair value measurement on a recurring basis | Fair Value | U.S. Treasury
Assets
Nuclear decommissioning trust	84,000,000		84,000,000		69,000,000
Fair value measurement on a recurring basis | Fair Value | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	9,000,000		9,000,000		8,000,000
Fair value measurement on a recurring basis | Fair Value | Corporate debt
Assets
Nuclear decommissioning trust	69,000,000		69,000,000		73,000,000
Fair value measurement on a recurring basis | Fair Value | Mortgage-backed securities
Assets
Nuclear decommissioning trust	84,000,000		84,000,000		78,000,000
Fair value measurement on a recurring basis | Fair Value | Municipality bonds
Assets
Nuclear decommissioning trust	94,000,000		94,000,000		90,000,000
Fair value measurement on a recurring basis | Fair Value | Other
Assets
Nuclear decommissioning trust	$ 13,000,000		$ 13,000,000		$ 21,000,000

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Business Segments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Financial data by business segment
Operating revenues	$ 878,576	$ 799,799	$ 1,499,207	$ 1,448,646
Net income (loss) attributable to common shareholders	122,345	86,685	114,088	71,550
Assets	13,214,407		13,214,407		13,111,018
Regulated electricity segment
Financial data by business segment
Operating revenues	878,000	799,000	1,498,000	1,447,000
Net income (loss) attributable to common shareholders	123,000	86,000	117,000	71,000
Assets	13,178,000		13,178,000		13,068,000
All other
Financial data by business segment
Operating revenues	1,000	1,000	1,000	2,000
Net income (loss) attributable to common shareholders	(1,000)	1,000	(3,000)	1,000
Assets	$ 36,000		$ 36,000		$ 43,000

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Derivative Accounting (Tables)

6 Months Ended

Jun. 30, 2012

Derivative Accounting

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

Commodity	Quantity
Power	9,914	gigawatt hours
Gas	178	Bcfs (a)

(a)“Bcf” is Billion Cubic Feet.

Gains and losses from derivative instruments in designated accounting hedges relationships

		Three Months Ended						Six Months Ended
	Financial Statement	June 30,						June 30,
Commodity Contracts	Location	2012			2011			2012			2011
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive income (loss) - derivative instruments	$	4,509		$	(16,323	)	$	(37,394	)	$	(15,335	)
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized) (a)	Fuel and purchased power	(23,015		)	(25,287		)	(37,515		)	(40,133		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power	32			(176		)	117			(164		)

(a)During the three and six months ended June 30, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges.

Gains and losses from derivative instruments not designated as accounting hedges instruments

		Three Months Ended					Six Months Ended
	Financial Statement	June 30,					June 30,
Commodity Contracts	Location	2012		2011			2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues	$	87	$	(503	)	$	(239	)	$	1,004
Net Gain (Loss) Recognized in Income	Fuel and purchased power	26,042		(2,892		)	990			(11,919		)
Total		$	26,129	$	(3,395	)	$	751		$	(10,915	)

Fair value of derivative instruments, margin account and cash collateral reported on a gross basis

Amounts are as of June 30, 2012 (dollars in thousands):

Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties			Other (b)			Total
Current Assets	$	—		$	66,712		$	390	$	—		$	(37,111	)	$	29,991
Investments and Other Assets	—			51,690			—		—			(8,164		)	43,526
Total Assets	—			118,402			390		—			(45,275		)	73,517
Current Liabilities	(1,185		)	(173,495		)	83,234		(11,145		)(a)	38,149			(64,442		)
Deferred Credits and Other	(4,594		)	(133,720		)	20,086		—			9,674			(108,554		)
Total Liabilities	(5,779		)	(307,215		)	103,320		(11,145		)	47,823			(172,996		)
Total	$	(5,779	)	$	(188,813	)	$	103,710	$	(11,145	)	$	2,548		$	(99,479	)

(a)Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)Other represents derivative instrument netting, options, and other risk management contracts.

The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2011 (dollars in thousands):

Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties			Other (b)			Total
Current Assets	$	7,287		$	76,162		$	1,630	$	—		$	(54,815	)	$	30,264
Investments and Other Assets	3,804			58,273			—		—			(12,755		)	49,322
Total Assets	11,091			134,435			1,630		—			(67,570		)	79,586
Current Liabilities	(82,195		)	(124,028		)	107,228		(11,145		)(a)	56,172			(53,968		)
Deferred Credits and Other	(68,137		)	(92,880		)	65,768		—			12,754			(82,495		)
Total Liabilities	(150,332		)	(216,908		)	172,996		(11,145		)	68,926			(136,463		)
Total Derivative Instruments	$	(139,241	)	$	(82,473	)	$	174,626	$	(11,145	)	$	1,356		$	(56,877	)

(a)Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)Other represents derivative instrument netting, options, and other risk management contracts.

Information about derivative instruments that have credit-risk-related contingent features

	June 30, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	306
Cash Collateral Posted	96
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	136

(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 Equity (Tables)

6 Months Ended

Jun. 30, 2012

Changes in Equity

Changes in shareholders' equity and changes in equity of noncontrolling interests

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,744,917		$	116,512		$	3,861,429		$	3,631,411		$	97,360		$	3,728,771
Net income	122,345			7,766			130,111			86,685			7,154			93,839
Other comprehensive income	17,459			—			17,459			6,646			—			6,646
Total comprehensive income	139,804			7,766			147,570			93,331			7,154			100,485
Issuance of capital stock	2,525			—			2,525			3,505			—			3,505
Reissuance of treasury stock - net	5,113			—			5,113			—			—			—
Other (primarily stock compensation)	631			—			631			(33		)	—			(33		)
Dividends on common stock	(114,955		)	—			(114,955		)	(114,509		)	—			(114,509		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,821,850		$	108,736		$	3,930,586		$	3,683,327		$	91,899		$	3,775,226
Net income	114,088			15,542			129,630			71,550			12,615			84,165
Other comprehensive income	1,845			—			1,845			17,092			—			17,092
Total comprehensive income	115,933			15,542			131,475			88,642			12,615			101,257
Issuance of capital stock	5,225			—			5,225			17,065			—			17,065
Reissuance (purchase) of treasury stock - net	3,359			—			3,359			(3,530		)	—			(3,530		)
Other (primarily stock compensation)	3,981			—			3,981			(181		)	—			(181		)
Dividends on common stock	(172,313		)	—			(172,313		)	(171,618		)	—			(171,618		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

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Consolidation and Nature of Operations

6 Months Ended

Jun. 30, 2012

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”) and APS Energy Services Company, Inc. (“APSES”).  See Note 13 for discussion of the bankruptcy filing of SunCor and the sale of APSES.  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 7 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 2011 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

See Note 16 for discussion of amended guidance on the presentation of comprehensive income.

The following tables show the impact of the reclassifications to prior year (previously reported) amounts (dollars in thousands):

Statement of Income for the Three Months Ended June 30, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	798,669	$	(798,669	)	$	—
Other revenues	1,130		(1,130		)	—
Operating revenues	—		799,799			799,799

Statement of Income for the Six Months Ended June 30, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	1,446,643	$	(1,446,643	)	$	—
Other revenues	2,003		(2,003		)	—
Operating revenues	—		1,448,646			1,448,646

Statement of Cash Flows for the Six Months Ended June 30, 2011	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Expenditures for real estate investments	$	(40	)	$	40		$	—
Change in other long-term assets	(26,185		)	(40		)	(26,225		)

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies

Schedule of updated contractual obligations

Year	2012		2013		2014		2015		2016		Thereafter		Total
Fuel and purchased power commitments	$	0.3	$	0.5	$	0.6	$	0.5	$	0.5	$	6.8	$	9.2
Renewable energy credits	0.1		—		—		0.1		—		0.5		0.7

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Regulatory Matters (Details) (USD $)	6 Months Ended				1 Months Ended						3 Months Ended	1 Months Ended				1 Months Ended	6 Months Ended		1 Months Ended		1 Months Ended					1 Months Ended		6 Months Ended		1 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY	Jun. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 RES Maximum USDPerWatt	Jul. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 RES Maximum	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 RES Minimum USDPerWatt	Jul. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 RES Minimum	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 RES Cost Recovery Mechanisms USDPerWatt	Dec. 14, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 RES Cost Recovery Mechanisms MW	Mar. 31, 2010 ARIZONA PUBLIC SERVICE COMPANY ACC 2010 DSMAC Cost Recovery Mechanisms Y	Jun. 29, 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. 02, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms Y	Jun. 03, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 DSMAC Cost Recovery Mechanisms	Feb. 28, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms USDPerkWh	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms	Jun. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 RES	Jun. 29, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 RES MW	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 RES Maximum	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2013 RES Minimum	Jan. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission D month	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 USDPerkWh	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. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY FERC Transmission Rates and Transmission Cost Adjustor Cost Recovery Mechanisms	Jun. 30, 2011 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 current sharing provision of fuel and purchased power costs																							9
Period to process the subsequent rate cases (in months)																							12
ACC staff sufficiency findings, general period of time (in days)																							30
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
Funding request						152,000,000		129,000,000													102,400,000	92,800,000
Funding approval as per budget authorized									110,000,000
Additional capacity from APS-owned AZ Sun projects (in MW)										100
Total capacity from APS-owned AZ Sun projects (in MW)										200
Second additional solar capacity for which revenue requirements were authorized to be recovered										100
Costs associated with program to be recovered through base rates or other mechanisms or next retail rate base (in MW)										100
Additional capacity from APS-owned facilities on schools and government facilities (in MW)										6.25
Initial upfront incentive per watt of solar capacity (in dollars per watt)									0.75
Amount for residential incentives for next fiscal year (in dollars per watt)					0.20		0.10
Additional capacity of renewable generation to be described later and installed in 2014 and 2015 (in MW)										25
Incentive for photovoltaic distributed energy of solar capacity (in dollars per share)																			$ 0.20
Capacity from community solar program (in MW)																				25
Period covered by cost recovery program (in years)											2
Period over which program costs will be amortized (in years)											3
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 (in years)														2
Percentage of cumulative energy savings for current year															5.00%
Costs already being recovered in general rates												10,000,000
Demand-side management adjustor charge (DSMAC)													72,000,000
Increase in annual wholesale transmission rates																														16,000,000	44,000,000
Revenue increase related to transmission services used for APS's retail customers																														18,000,000	38,000,000
Revenue reduction related to transmission services used for wholesale customers																														2,000,000
Changes in the deferred fuel and purchased power regulatory asset (liability)
Beginning balance																	28,000,000	(58,000,000)
Deferred fuel and purchased power costs-current period	82,261,000	64,679,000	82,261,000	64,679,000													(82,000,000)	(65,000,000)
Amounts refunded through revenues	(54,388,000)	(68,762,000)	(54,388,000)	(68,762,000)													54,000,000	69,000,000
Ending balance																		$ (54,000,000)
PSA rate (in dollars per kWh)																(0.0042)
PSA rate for prior year (in dollars per kWh)																(0.0057)

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Other Income and Other Expense (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Other income:
Interest income	$ 107	$ 543	$ 712	$ 935
Investment gains - net		12		1,307
Miscellaneous	70	2	225	5
Total other income	177	557	937	2,247
Other expense:
Non-operating costs	(2,389)	(1,629)	(4,239)	(3,119)
Investment losses - net	(58)		(112)
Miscellaneous	(222)	(1,557)	(2,386)	(1,808)
Total other expense	$ (2,669)	$ (3,186)	$ (6,737)	$ (4,927)

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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, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
OPERATING REVENUES	$ 878,576	$ 799,799	$ 1,499,207	$ 1,448,646
OPERATING EXPENSES
Fuel and purchased power	264,723	244,049	481,032	456,056
Operations and maintenance	216,236	210,590	426,899	465,619
Depreciation and amortization	100,606	106,617	200,715	213,200
Taxes other than income taxes	41,289	40,155	83,764	77,779
Other expenses	1,233	1,396	4,301	3,216
Total	624,087	602,807	1,196,711	1,215,870
OPERATING INCOME	254,489	196,992	302,496	232,776
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,175	5,924	9,931	11,319
Other income (Note 11)	177	557	937	2,247
Other expense (Note 11)	(2,669)	(3,186)	(6,737)	(4,927)
Total	2,683	3,295	4,131	8,639
INTEREST EXPENSE
Interest charges	53,000	60,140	109,967	121,217
Allowance for borrowed funds used during construction	(3,447)	(3,856)	(6,598)	(7,432)
Total	49,553	56,284	103,369	113,785
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	207,619	144,003	203,258	127,630
INCOME TAXES	76,689	50,818	72,044	44,813
INCOME FROM CONTINUING OPERATIONS	130,930	93,185	131,214	82,817
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(535) and $773 for three months ended June 30, 2012 and 2011 and $(1,040) and $906 for six months ended June 30, 2012 and 2011 (Note 13)	(819)	654	(1,584)	1,348
NET INCOME	130,111	93,839	129,630	84,165
Less: Net income attributable to noncontrolling interests (Note 7)	7,766	7,154	15,542	12,615
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	122,345	86,685	114,088	71,550
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	109,491	109,044	109,395	108,939
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	110,359	109,718	110,183	109,540
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders - basic (in dollars per share)	$ 1.12	$ 0.79	$ 1.06	$ 0.64
Net income attributable to common shareholders - basic (in dollars per share)	$ 1.12	$ 0.80	$ 1.04	$ 0.66
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)	$ 1.12	$ 0.78	$ 1.05	$ 0.64
Net income attributable to common shareholders - diluted (in dollars per share)	$ 1.11	$ 0.79	$ 1.04	$ 0.65
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 1.05	$ 1.05	$ 1.575	$ 1.575
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	123,164	86,001	115,681	70,163
Discontinued operations, net of tax	(819)	684	(1,593)	1,387
Net income attributable to common shareholders	$ 122,345	$ 86,685	$ 114,088	$ 71,550

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Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended			6 Months Ended
	Feb. 28, 2011 Y	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY month	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Long-term income tax receivables		$ 69,508	$ 68,633	$ 69,903	$ 69,028
Period over which the cash refunds are not expected to be received (in months)				12
Phase-in period of corporate income tax rate reductions beginning in 2014 (in years)	4

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
CURRENT ASSETS
Cash and cash equivalents	$ 11,228	$ 33,583
Customer and other receivables	316,722	284,183
Accrued unbilled revenues	168,450	125,239
Allowance for doubtful accounts	(3,302)	(3,748)
Materials and supplies (at average cost)	217,222	204,387
Fossil fuel (at average cost)	30,177	22,000
Deferred income taxes	87,690	130,571
Income tax receivable (Note 6)	885	6,466
Assets from risk management activities (Note 8)	29,991	30,264
Deferred fuel and purchased power regulatory asset (Note 3)		27,549
Other regulatory assets (Note 3)	54,857	69,072
Other current assets	33,496	26,904
Total current assets	947,416	956,470
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)	43,526	49,322
Nuclear decommissioning trust (Note 15)	544,933	513,733
Other assets	64,800	64,588
Total investments and other assets	653,259	627,643
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,048,957	13,753,971
Accumulated depreciation and amortization	(4,843,868)	(4,709,991)
Net	9,205,089	9,043,980
Construction work in progress	458,441	496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	130,929	132,864
Intangible assets, net of accumulated amortization	163,727	170,571
Nuclear fuel, net of accumulated amortization	159,493	118,098
Total property, plant and equipment	10,117,679	9,962,258
DEFERRED DEBITS
Regulatory assets (Note 3)	1,283,322	1,352,079
Income tax receivable (Note 6)	69,508	68,633
Other	143,223	143,935
Total deferred debits	1,496,053	1,564,647
TOTAL ASSETS	13,214,407	13,111,018
CURRENT LIABILITIES
Accounts payable	316,329	326,987
Accrued taxes (Note 6)	133,766	120,289
Accrued interest	61,451	54,872
Common dividends payable	57,479
Short-term borrowings	109,000
Current maturities of long-term debt	57,962	477,435
Customer deposits	74,575	72,176
Liabilities from risk management activities (Note 8)	64,442	53,968
Deferred fuel and purchased power regulatory liability (Note 3)	325
Other regulatory liabilities (Note 3)	89,433	88,362
Other current liabilities	139,561	148,616
Total current liabilities	1,104,323	1,342,705
LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities	3,313,992	2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	57,420	65,547
Total long-term debt less current maturities	3,371,412	3,019,054
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,946,540	1,925,388
Regulatory liabilities (Note 3)	738,693	737,332
Liability for asset retirements	289,641	279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,243,256	1,268,910
Liabilities from risk management activities (Note 8)	108,554	82,495
Customer advances	111,655	116,805
Coal mine reclamation	118,374	117,896
Unrecognized tax benefits (Note 6)	72,977	72,270
Other	209,645	217,934
Total deferred credits and other	4,839,335	4,818,673
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 9)
Common stock, no par value	2,453,453	2,444,247
Treasury stock	(1,359)	(4,717)
Total common stock	2,452,094	2,439,530
Retained earnings	1,476,259	1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(63,675)	(65,447)
Derivative instruments	(86,643)	(86,716)
Total accumulated other comprehensive loss	(150,318)	(152,163)
Total shareholders' equity	3,778,035	3,821,850
Noncontrolling interests (Note 7)	121,302	108,736
Total equity	3,899,337	3,930,586
TOTAL LIABILITIES AND EQUITY	$ 13,214,407	$ 13,111,018

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Nuclear Decommissioning Trust (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Nuclear decommissioning trust fund assets
Fair Value	$ 544,933,000		$ 544,933,000		$ 513,733,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities			211,138,000	299,600,000
Fair value of fixed income securities, summarized by contractual maturities
Total	544,933,000		544,933,000		513,733,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	544,933,000		544,933,000		513,733,000
Unrealized Gains	82,000,000		82,000,000		67,000,000
Unrealized Losses	(1,000,000)		(1,000,000)		(2,000,000)
Net payables for securities purchases	(6,000,000)		(6,000,000)		(1,000,000)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	2,000,000	2,000,000	4,000,000	3,000,000
Realized losses	(1,000,000)	(1,000,000)	(2,000,000)	(3,000,000)
Proceeds from the sale of securities	119,000,000	110,000,000	211,138,000	299,600,000
Fair value of fixed income securities, summarized by contractual maturities
Total	544,933,000		544,933,000		513,733,000
ARIZONA PUBLIC SERVICE COMPANY | Equity securities
Nuclear decommissioning trust fund assets
Fair Value	192,000,000		192,000,000		175,000,000
Unrealized Gains	58,000,000		58,000,000		44,000,000
Unrealized Losses	(1,000,000)		(1,000,000)		(1,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Total	192,000,000		192,000,000		175,000,000
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	359,000,000		359,000,000		340,000,000
Unrealized Gains	24,000,000		24,000,000		23,000,000
Unrealized Losses					(1,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	24,000,000		24,000,000
1 year - 5 years	82,000,000		82,000,000
5 years - 10 years	103,000,000		103,000,000
Greater than 10 years	150,000,000		150,000,000
Total	$ 359,000,000		$ 359,000,000		$ 340,000,000

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2012

Discontinued Operations

Revenue, income (loss) before income taxes and income (loss) after taxes from discontinued operations

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Revenue:
SunCor	$	—		$	2	$	—		$	3
APSES	—			15		—			26
Total revenue	$	—		$	17	$	—		$	29
Income (loss) before taxes	$	(1	)	$	1	$	(3	)	$	2
Income (loss) after taxes	$	(1	)	$	1	$	(1	)	$	1

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Changes in Equity (APSC)

6 Months Ended

Jun. 30, 2012

Changes in Equity

9.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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,744,917		$	116,512		$	3,861,429		$	3,631,411		$	97,360		$	3,728,771
Net income	122,345			7,766			130,111			86,685			7,154			93,839
Other comprehensive income	17,459			—			17,459			6,646			—			6,646
Total comprehensive income	139,804			7,766			147,570			93,331			7,154			100,485
Issuance of capital stock	2,525			—			2,525			3,505			—			3,505
Reissuance of treasury stock - net	5,113			—			5,113			—			—			—
Other (primarily stock compensation)	631			—			631			(33		)	—			(33		)
Dividends on common stock	(114,955		)	—			(114,955		)	(114,509		)	—			(114,509		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,821,850		$	108,736		$	3,930,586		$	3,683,327		$	91,899		$	3,775,226
Net income	114,088			15,542			129,630			71,550			12,615			84,165
Other comprehensive income	1,845			—			1,845			17,092			—			17,092
Total comprehensive income	115,933			15,542			131,475			88,642			12,615			101,257
Issuance of capital stock	5,225			—			5,225			17,065			—			17,065
Reissuance (purchase) of treasury stock - net	3,359			—			3,359			(3,530		)	—			(3,530		)
Other (primarily stock compensation)	3,981			—			3,981			(181		)	—			(181		)
Dividends on common stock	(172,313		)	—			(172,313		)	(171,618		)	—			(171,618		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,865,748		$	116,166		$	3,981,914		$	3,766,131		$	96,554		$	3,862,685
Net income	124,928			7,766			132,694			87,705			7,184			94,889
OCI	17,117			—			17,117			6,730			—			6,730
Total comprehensive income	142,045			7,766			149,811			94,435			7,184			101,619
Dividends on common stock	(105,000		)	—			(105,000		)	(114,500		)	—			(114,500		)
Net capital activities by noncontrolling interests	—			(2,630		)	(2,630		)	—			(2,610		)	(2,610		)
Other	(2		)	—			(2		)	1			—			1
Ending balance, June 30	$	3,902,791		$	121,302		$	4,024,093		$	3,746,067		$	101,128		$	3,847,195

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,943,007		$	108,399		$	4,051,406		$	3,824,953		$	91,084		$	3,916,037
Net income	120,823			15,533			136,356			75,625			12,654			88,279
OCI	1,362			—			1,362			17,088			—			17,088
Total comprehensive income	122,185			15,533			137,718			92,713			12,654			105,367
Dividends on common stock	(162,400		)	—			(162,400		)	(171,600		)	—			(171,600		)
Net capital activities by noncontrolling interests	—			(2,630		)	(2,630		)	—			(2,610		)	(2,610		)
Other	(1		)	—			(1		)	1			—			1
Ending balance, June 30	$	3,902,791		$	121,302		$	4,024,093		$	3,746,067		$	101,128		$	3,847,195

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Nuclear Decommissioning Trust

6 Months Ended

Jun. 30, 2012

Nuclear Decommissioning Trust

Nuclear Decommissioning Trust

15.Nuclear Decommissioning Trust

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 domestic 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 14 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 recorded deferred realized and unrealized gains and losses on investment securities in other regulatory liabilities or 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, 2012 and December 31, 2011 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2012
Equity securities	$	192		$	58	$	(1	)
Fixed income securities	359			24		—
Net payables (a)	(6		)	—		—
Total	$	545		$	82	$	(1	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2011
Equity securities	$	175		$	44	$	(1	)
Fixed income securities	340			23		(1		)
Net payables (a)	(1		)	—		—
Total	$	514		$	67	$	(2	)

(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,
	2012			2011			2012			2011
Realized gains	$	2		$	2		$	4		$	3
Realized losses	(1		)	(1		)	(2		)	(3		)
Proceeds from the sale of securities (a)	119			110			211			300

(a)Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2012 is as follows (dollars in millions):

	Fair Value
Less than one year	$	24
1 year - 5 years	82
5 years - 10 years	103
Greater than 10 years	150
Total	$	359

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

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, 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 June 30, 2012
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	192		$	—		$	—		$	192
Fixed income securities:
U.S. Treasury	84		—			—			—			84
Cash and cash equivalent funds	—		15			—			(6		)(b)	9
Corporate debt	—		69			—			—			69
Mortgage-backed securities	—		84			—			—			84
Municipality bonds	—		94			—			—			94
Other	—		13			—			—			13
Subtotal nuclear decommissioning trust	84		467			—			(6		)	545
Cash equivalents	2		—			—			—			2
Risk management activities — derivative instruments:
Commodity contracts	—		50			69			(45		)(c)	74
Total	$	86	$	517		$	69		$	(51	)	$	621
Liabilities:
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(199	)	$	(114	)	$	140	(c)	$	(173	)

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

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

(c)Primarily represents counterparty netting, margin and collateral (see Note 8).

The following table presents the fair value at December 31, 2011 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, 2011
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	175		$	—		$	—		$	175
Fixed income securities:
U.S. Treasury	69		—			—			—			69
Cash and cash equivalent funds	—		9			—			(1		)(b)	8
Corporate debt	—		73			—			—			73
Mortgage-backed securities	—		78			—			—			78
Municipality bonds	—		90			—			—			90
Other	—		21			—			—			21
Subtotal nuclear decommissioning trust	69		446			—			(1		)	514
Risk management activities — derivative instruments:
Commodity contracts	—		70			74			(64		)(c)	80
Total	$	69	$	516		$	74		$	(65	)	$	594
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(c)	$	(137	)

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

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

(c)Represents counterparty netting, margin and collateral (see Note 8).

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

	June 30, 2012
	Fair Value (millions)				Valuation	Significant
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range
Electricity:
Forward Contracts (a)	$	67	$	88	Discounted cash flows	Electricity forward price (per MWh)(b)	$20.67 - $67.18
Option Contracts	—		25		Option Model	Electricity forward price (per MWh)(b)	$29.13 - $99.27
						Natural gas forward price (per mmbtu)(c)	$2.69 - $4.11
						Implied electricity price volatilities	15% - 151%
						Implied natural gas price volatilities	18% - 56%
Natural Gas:
Forward Contracts (a)	2		1		Discounted cash flows	Natural gas forward price (per mmbtu)(c)	$2.60 - $4.18
Total	$	69	$	114

(a)Includes swaps and physical and financial contracts.

(b)MWh means megawatt-hour, one million watts per hour.

(c)mmbtu means one million British Thermal Units.

Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2012			2011			2012			2011
Net derivative balance at beginning of period	$	(58	)	$	(48	)	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	1			—			2			1
Included in OCI	3			(3		)	(2		)	(1		)
Deferred as a regulatory asset or liability	12			1			7			(6		)
Settlements	(1		)	4			—			4
Transfers into Level 3 from Level 2	—			1			2			(4		)
Transfers from Level 3 into Level 2	(2		)	(2		)	(3		)	(3		)
Net derivative balance at end of period	$	(45	)	$	(47	)	$	(45	)	$	(47	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	1

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Consolidation and Nature of Operations (Tables)

6 Months Ended

Jun. 30, 2012

Consolidation and Nature of Operations

Impact of the reclassifications to prior year (previously reported) amounts

Statement of Income for the Three Months Ended June 30, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	798,669	$	(798,669	)	$	—
Other revenues	1,130		(1,130		)	—
Operating revenues	—		799,799			799,799

Statement of Income for the Six Months Ended June 30, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	1,446,643	$	(1,446,643	)	$	—
Other revenues	2,003		(2,003		)	—
Operating revenues	—		1,448,646			1,448,646

Statement of Cash Flows for the Six Months Ended June 30, 2011	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Expenditures for real estate investments	$	(40	)	$	40		$	—
Change in other long-term assets	(26,185		)	(40		)	(26,225		)

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Other Income and Other Expense (APSC) (Tables)

6 Months Ended

Jun. 30, 2012

Detail of other income and other expense

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	107		$	543		$	712		$	935
Investment gains — net	—			12			—			1,307
Miscellaneous	70			2			225			5
Total other income	$	177		$	557		$	937		$	2,247
Other expense:
Non-operating costs	$	(2,389	)	$	(1,629	)	$	(4,239	)	$	(3,119	)
Investment losses — net	(58		)	—			(112		)	—
Miscellaneous	(222		)	(1,557		)	(2,386		)	(1,808		)
Total other expense	$	(2,669	)	$	(3,186	)	$	(6,737	)	$	(4,927	)

ARIZONA PUBLIC SERVICE COMPANY

Detail of other income and other expense

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	77		$	89		$	184		$	219
Investment gains — net	—			268			—			1,418
Miscellaneous	941			876			1,344			1,574
Total other income	$	1,018		$	1,233		$	1,528		$	3,211
Other expense:
Non-operating costs (a)	$	(2,941	)	$	(2,400	)	$	(4,682	)	$	(4,214	)
Asset dispositions	(195		)	—			(418		)	(823		)
Miscellaneous	(857		)	(2,251		)	(3,517		)	(3,206		)
Total other expense	$	(3,993	)	$	(4,651	)	$	(8,617	)	$	(8,243	)

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 129,630	$ 84,165
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	239,743	245,700
Deferred fuel and purchased power	82,261	64,679
Deferred fuel and purchased power amortization	(54,388)	(68,762)
Allowance for equity funds used during construction	(9,931)	(11,319)
Deferred income taxes	66,142	11,945
Change in derivative instruments fair value	(2,618)	(279)
Changes in current assets and liabilities:
Customer and other receivables	(21,424)	43,271
Accrued unbilled revenues	(43,211)	(60,390)
Materials, supplies and fossil fuel	(21,012)	(18,226)
Other current assets	(9,407)	(37,053)
Accounts payable	9,199	37,817
Accrued taxes and income tax receivable - net	19,775	29,530
Other current liabilities	807	3,967
Change in margin and collateral accounts - assets	124	21,185
Change in margin and collateral accounts - liabilities	69,602	39,567
Change in unrecognized tax benefits		18,959
Change in other long-term assets	(1,692)	(26,225)
Change in other long-term liabilities	5,035	57,748
Net cash flow provided by operating activities	458,635	436,279
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(424,775)	(387,272)
Contributions in aid of construction	25,800	21,905
Allowance for borrowed funds used during construction	(6,598)	(7,432)
Proceeds from nuclear decommissioning trust sales	211,138	299,600
Investment in nuclear decommissioning trust	(219,762)	(308,222)
Proceeds from sale of life insurance policies		55,444
Other	(525)	(2,352)
Net cash flow used for investing activities	(414,722)	(328,329)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081	175,000
Repayment of long-term debt	(421,451)	(187,962)
Short-term borrowings and payments - net	109,000	(9,300)
Dividends paid on common stock	(111,297)	(112,537)
Common stock equity issuance	8,869	14,520
Distributions to noncontrolling interests	(2,630)	(2,610)
Other	160	(2,975)
Net cash flow used for financing activities	(66,268)	(125,864)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(22,355)	(17,914)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	33,583	110,188
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11,228	92,274
Cash paid during the period for:
Income taxes, net of (refunds)	(649)
Interest, net of amounts capitalized	$ 94,680	$ 110,659

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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, 2011	Jun. 30, 2012	Jun. 30, 2011
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Income tax expense (benefit) on discontinued operations	$ (535)	$ 773	$ (1,040)	$ 906

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies

Commitments and Contingencies

10.Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

APS currently estimates it will incur $122 million (in 2010 dollars) 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, 2012, APS had a regulatory liability of $47 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence.  As required by the Price Anderson Nuclear Industries Indemnity Act, 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 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 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”).  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 and exclusions.

Contractual Obligations

As of June 30, 2012, certain contractual obligations have increased approximately $0.3 billion from December 31, 2011 as discussed in the 2011 Form 10-K.  As of June 30, 2012, the updated contractual obligations are as follows (dollars in billions):

Year	2012		2013		2014		2015		2016		Thereafter		Total
Fuel and purchased power commitments	$	0.3	$	0.5	$	0.6	$	0.5	$	0.5	$	6.8	$	9.2
Renewable energy credits	0.1		—		—		0.1		—		0.5		0.7

FERC Market Issues

On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest.  The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding.  This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to the FERC for further consideration.  On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001.  FERC rejected a market-wide remedy approach and instead directed that buyers seeking refunds must demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.

The hearing is currently expected to commence in April 2013.  Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

Superfund

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 the 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 the EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with the 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 $1 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 we cannot accurately estimate our total expenditures.

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 Ninth Circuit Court of Appeals in November 2009, and Pinnacle West filed its reply on June 30, 2010.  On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.

On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants.  However, the Court left open the issue of whether such claims may be available under state law.  Oral argument in the Kivalina case was heard on November 28, 2011; the parties await the court’s decision on both federal common law and state public nuisance law issues.  We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

Southwest Power Outage

Regulatory Inquiry.  On September 8, 2011 at approximately 3:30PM, 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.  At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly.  Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.

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

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 cannot predict the timing, results or potential impacts of any further inquiries into 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.

Lawsuit.  On September 12, 2011, two purported consumer class action complaints were filed in Federal District Court in San Diego, California, naming APS, Pinnacle West and San Diego Gas & Electric Company (“SDG&E”) as defendants and seeking damages for loss of perishable inventory as a result of interruption of electrical service.  On December 22, 2011, the plaintiffs voluntarily dismissed both lawsuits.  In January 2012, one of the cases was refiled in California Superior Court in San Diego, California, and then removed by defendants to Federal Court in San Diego.  APS and Pinnacle West filed a motion to dismiss that was granted by the Court on March 20, 2012.  The Court stated that the plaintiffs could refile a complaint against APS and Pinnacle West on certain grounds following the release of the Joint Report discussed above. On May 31, 2012, the plaintiff filed an amended complaint against APS and Pinnacle West.  APS and Pinnacle West subsequently filed a motion to dismiss the amended complaint, which was granted on July 27, 2012.

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 Prevention of Significant Deterioration (“PSD”) 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 PSD 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, which are pending.  APS believes the claims in this matter are without merit and will vigorously defend against them.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At June 30, 2012, approximately $76 million of letters of credit were outstanding to support existing variable interest rate 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 obligations to certain equity participants in the Palo Verde sale leaseback transactions (see Note 7 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire in 2015 and totaled approximately $44 million at June 30, 2012.  Additionally, APS has issued letters of credit to support collateral obligations under certain natural gas tolling contracts and hedge contracts entered into with third parties, including a $40 million letter of credit issued in June 2012.  At June 30, 2012, $65 million of such letters of credit were outstanding.  These letters of credit will expire in 2013, 2015 and 2016.

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.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Jul. 27, 2012
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, 2012
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		109,543,792
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2

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Other Income and Other Expense

6 Months Ended

Jun. 30, 2012

Other Income and Other Expense

Other Income and Other Expense

11.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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	107		$	543		$	712		$	935
Investment gains — net	—			12			—			1,307
Miscellaneous	70			2			225			5
Total other income	$	177		$	557		$	937		$	2,247
Other expense:
Non-operating costs	$	(2,389	)	$	(1,629	)	$	(4,239	)	$	(3,119	)
Investment losses — net	(58		)	—			(112		)	—
Miscellaneous	(222		)	(1,557		)	(2,386		)	(1,808		)
Total other expense	$	(2,669	)	$	(3,186	)	$	(6,737	)	$	(4,927	)

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
NET INCOME	$ 130,111	$ 93,839	$ 129,630	$ 84,165
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of ($1,781) and $6,448 for three months ended June 30, 2012 and 2011 and $14,770 and $6,058 for six months ended June 30, 2012 and 2011, respectively	2,728	(9,875)	(22,624)	(9,277)
Reclassification of net realized loss, net of tax benefit of $9,090 and $9,988 for three months ended June 30, 2012 and 2011 and $14,818 and $15,852 for six months ended June 30, 2012 and 2011, respectively	13,925	15,299	22,697	24,281
Pension and other postretirement benefits activity, net of tax expense of $526 and $797 for three months ended June 30, 2012 and 2011 and $1,157 and $1,363 for six months ended June 30, 2012 and 2011, respectively	806	1,222	1,772	2,088
Total other comprehensive income	17,459	6,646	1,845	17,092
COMPREHENSIVE INCOME	147,570	100,485	131,475	101,257
Less: Comprehensive income attributable to noncontrolling interests	7,766	7,154	15,542	12,615
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$ 139,804	$ 93,331	$ 115,933	$ 88,642

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Business Segments

6 Months Ended

Jun. 30, 2012

Business Segments

Business Segments

5.Business Segments

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.

Financial data for the three and six months ended June 30, 2012 and 2011 and at June 30, 2012 and December 31, 2011 is provided as follows (dollars in millions):

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Operating revenues:
Regulated electricity segment	$	878		$	799	$	1,498		$	1,447
All other	1			1		1			2
Total	$	879		$	800	$	1,499		$	1,449
Net income attributable to common shareholders:
Regulated electricity segment	$	123		$	86	$	117		$	71
All other (a)	(1		)	1		(3		)	1
Total	$	122		$	87	$	114		$	72

	As of June 30, 2012		As of December 31, 2011
Assets:
Regulated electricity segment	$	13,178	$	13,068
All other (a)	36		43
Total	$	13,214	$	13,111

(a)All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.  See Note 13 for discussion of discontinued operations.

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Retirement Plans and Other Benefits

6 Months Ended

Jun. 30, 2012

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 are 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 and $3 million for the three months ended June 30, 2012 and 2011, respectively, and approximately $14 million and $6 million for the six months ended June 30, 2012 and 2011, respectively.  The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged 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,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost - benefits earned during the period	$	15		$	13		$	32		$	29		$	6		$	5		$	14		$	11
Interest cost on benefit obligation	30			31			60			62			11			12			23			23
Expected return on plan assets	(35		)	(33		)	(71		)	(67		)	(11		)	(11		)	(23		)	(21		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	12			7			22			13			4			4			10			8
Net periodic benefit cost	$	22		$	18		$	44		$	38		$	10		$	10		$	24		$	21
Portion of cost charged to expense	$	8		$	7		$	13		$	15		$	3		$	4		$	6		$	8

Contributions

We expect to contribute to our pension plan approximately $65 million in 2012 (of which $15 million was contributed in July 2012), approximately $150 million in 2013 and approximately $160 million in 2014.  The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year.

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New Accounting Standards

6 Months Ended

Jun. 30, 2012

New Accounting Standards

New Accounting Standards

16.New Accounting Standards

During the first quarter of 2012, we adopted amended guidance intended to converge fair value measurement and disclosure requirements for GAAP and international financial reporting standards (“IFRS”).  The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures.  The adoption of this new guidance resulted in additional fair value disclosures (see Note 14), but did not impact our financial statement results.

During the first quarter of 2012, we also adopted amended guidance on the presentation of comprehensive income.  As a result of the amended guidance, we have changed our format for presenting comprehensive income.  Previously, components of comprehensive income were presented within changes of equity.  Due to the amended guidance, we now present comprehensive income in a new financial statement titled “Condensed Consolidated Statements of Comprehensive Income”.  The adoption of this guidance changed our format for presenting comprehensive income, but did not impact our financial statement results.

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Earnings Per Share

6 Months Ended

Jun. 30, 2012

Earnings Per Share

Earnings Per Share

12.Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	1.12		$	0.79	$	1.06		$	0.64
Income (loss) from discontinued operations	—			0.01		(0.02		)	0.02
Earnings per share — basic	$	1.12		$	0.80	$	1.04		$	0.66
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	1.12		$	0.78	$	1.05		$	0.64
Income (loss) from discontinued operations	(0.01		)	0.01		(0.01		)	0.01
Earnings per share — diluted	$	1.11		$	0.79	$	1.04		$	0.65

Dilutive stock options and performance shares (which are contingently issuable) increased average diluted common shares outstanding by approximately 868,000 shares and 674,000 shares for the three months ended June 30, 2012 and 2011, respectively, and by approximately 788,000 shares and 601,000 shares for the six months ended June 30, 2012 and 2011, respectively.

For the three-month and six-month periods ended June 30, 2012 and 2011, 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, 2012

Derivative Accounting

Derivative Accounting

8.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 that the forecasted transaction is no longer probable of occurring.  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 14 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

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

Prior to the recent 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 recent 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, 2012, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	9,914	gigawatt hours
Gas	178	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 during the three and six months ended June 30, 2012 and 2011 (dollars in thousands).  As cash flow hedge accounting treatment was discontinued for the significant majority of our contracts on June 1, 2012, the table below reflects activity occurring prior to that date:

		Three Months Ended						Six Months Ended
	Financial Statement	June 30,						June 30,
Commodity Contracts	Location	2012			2011			2012			2011
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive income (loss) - derivative instruments	$	4,509		$	(16,323	)	$	(37,394	)	$	(15,335	)
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized) (a)	Fuel and purchased power	(23,015		)	(25,287		)	(37,515		)	(40,133		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power	32			(176		)	117			(164		)

(a)During the three and six months ended June 30, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges.

During the next twelve months, we estimate that a net loss of $77 million before income taxes will be reclassified from accumulated other comprehensive income 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, 2012 and 2011 (dollars in thousands):

		Three Months Ended					Six Months Ended
	Financial Statement	June 30,					June 30,
Commodity Contracts	Location	2012		2011			2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues	$	87	$	(503	)	$	(239	)	$	1,004
Net Gain (Loss) Recognized in Income	Fuel and purchased power	26,042		(2,892		)	990			(11,919		)
Total		$	26,129	$	(3,395	)	$	751		$	(10,915	)

Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

The following table provides information about the fair value of our risk management activities reported on a gross basis.  Transactions with counterparties that have master netting arrangements are reported net on the Condensed Consolidated Balance Sheets.  These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.  Amounts are as of June 30, 2012 (dollars in thousands):

Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties			Other (b)			Total
Current Assets	$	—		$	66,712		$	390	$	—		$	(37,111	)	$	29,991
Investments and Other Assets	—			51,690			—		—			(8,164		)	43,526
Total Assets	—			118,402			390		—			(45,275		)	73,517
Current Liabilities	(1,185		)	(173,495		)	83,234		(11,145		)(a)	38,149			(64,442		)
Deferred Credits and Other	(4,594		)	(133,720		)	20,086		—			9,674			(108,554		)
Total Liabilities	(5,779		)	(307,215		)	103,320		(11,145		)	47,823			(172,996		)
Total	$	(5,779	)	$	(188,813	)	$	103,710	$	(11,145	)	$	2,548		$	(99,479	)

(a)Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)Other represents derivative instrument netting, options, and other risk management contracts.

The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2011 (dollars in thousands):

Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties			Other (b)			Total
Current Assets	$	7,287		$	76,162		$	1,630	$	—		$	(54,815	)	$	30,264
Investments and Other Assets	3,804			58,273			—		—			(12,755		)	49,322
Total Assets	11,091			134,435			1,630		—			(67,570		)	79,586
Current Liabilities	(82,195		)	(124,028		)	107,228		(11,145		)(a)	56,172			(53,968		)
Deferred Credits and Other	(68,137		)	(92,880		)	65,768		—			12,754			(82,495		)
Total Liabilities	(150,332		)	(216,908		)	172,996		(11,145		)	68,926			(136,463		)
Total Derivative Instruments	$	(139,241	)	$	(82,473	)	$	174,626	$	(11,145	)	$	1,356		$	(56,877	)

(a)Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b)Other represents derivative instrument netting, options, and other risk management contracts.

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 83% of Pinnacle West’s $74 million of risk management assets as of June 30, 2012.  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 subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2012 (dollars in millions):

	June 30, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	306
Cash Collateral Posted	96
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	136

(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 $184 million if our debt credit ratings were to fall below investment grade.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
OPERATING EXPENSES
Fuel and purchased power	$ 264,723	$ 244,049	$ 481,032	$ 456,056
Operations and maintenance	216,236	210,590	426,899	465,619
Depreciation and amortization	100,606	106,617	200,715	213,200
Taxes other than income taxes	41,289	40,155	83,764	77,779
Total	624,087	602,807	1,196,711	1,215,870
OPERATING INCOME	254,489	196,992	302,496	232,776
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,175	5,924	9,931	11,319
Other income (Note S-2)	177	557	937	2,247
Other expense (Note S-2)	(2,669)	(3,186)	(6,737)	(4,927)
Total	2,683	3,295	4,131	8,639
INTEREST EXPENSE
Allowance for borrowed funds used during construction	(3,447)	(3,856)	(6,598)	(7,432)
Total	49,553	56,284	103,369	113,785
NET INCOME	130,111	93,839	129,630	84,165
Less: Net income attributable to noncontrolling interests (Note 7)	7,766	7,154	15,542	12,615
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	122,345	86,685	114,088	71,550
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	877,587	798,686	1,497,835	1,446,680
OPERATING EXPENSES
Fuel and purchased power	264,723	244,048	481,032	456,056
Operations and maintenance	213,746	208,597	422,193	461,203
Depreciation and amortization	100,583	106,594	200,668	213,152
Income taxes	80,696	54,259	79,882	48,255
Taxes other than income taxes	41,018	39,788	83,244	77,038
Total	700,766	653,286	1,267,019	1,255,704
OPERATING INCOME	176,821	145,400	230,816	190,976
OTHER INCOME (DEDUCTIONS)
Income taxes	2,030	1,565	3,736	225
Allowance for equity funds used during construction	5,175	5,924	9,931	11,319
Other income (Note S-2)	1,018	1,233	1,528	3,211
Other expense (Note S-2)	(3,993)	(4,651)	(8,617)	(8,243)
Total	4,230	4,071	6,578	6,512
INTEREST EXPENSE
Interest on long-term debt	48,838	54,754	101,575	109,491
Interest on short-term borrowings	1,914	2,521	3,949	4,829
Debt discount, premium and expense	1,052	1,164	2,112	2,321
Allowance for borrowed funds used during construction	(3,447)	(3,857)	(6,598)	(7,432)
Total	48,357	54,582	101,038	109,209
NET INCOME	132,694	94,889	136,356	88,279
Less: Net income attributable to noncontrolling interests (Note 7)	7,766	7,184	15,533	12,654
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 124,928	$ 87,705	$ 120,823	$ 75,625

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Income Taxes

6 Months Ended

Jun. 30, 2012

Income Taxes

Income Taxes

6.Income Taxes

The $70 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.  This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt.  Further clarification of the timing is expected from the IRS within the next twelve months.

Net Income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 7).  As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.

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.  At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made.  However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.

As of June 30, 2012, 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 2007.

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Palo Verde Sale Leaseback Variable Interest Entities

6 Months Ended

Jun. 30, 2012

Palo Verde Sale Leaseback Variable Interest Entities

Palo Verde Sale Leaseback Variable Interest Entities

7.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 2012 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.

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, 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, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

	June 30, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	131	$	133
Current maturities of long-term debt	26		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	57		66
Equity — Noncontrolling interests	121		108

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, 2012, APS would have been required to pay the noncontrolling equity participants approximately $142 million and assume $83 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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Changes in Equity

6 Months Ended

Jun. 30, 2012

Changes in Equity

Changes in Equity

9.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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, April 1	$	3,744,917		$	116,512		$	3,861,429		$	3,631,411		$	97,360		$	3,728,771
Net income	122,345			7,766			130,111			86,685			7,154			93,839
Other comprehensive income	17,459			—			17,459			6,646			—			6,646
Total comprehensive income	139,804			7,766			147,570			93,331			7,154			100,485
Issuance of capital stock	2,525			—			2,525			3,505			—			3,505
Reissuance of treasury stock - net	5,113			—			5,113			—			—			—
Other (primarily stock compensation)	631			—			631			(33		)	—			(33		)
Dividends on common stock	(114,955		)	—			(114,955		)	(114,509		)	—			(114,509		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total
Beginning balance, January 1	$	3,821,850		$	108,736		$	3,930,586		$	3,683,327		$	91,899		$	3,775,226
Net income	114,088			15,542			129,630			71,550			12,615			84,165
Other comprehensive income	1,845			—			1,845			17,092			—			17,092
Total comprehensive income	115,933			15,542			131,475			88,642			12,615			101,257
Issuance of capital stock	5,225			—			5,225			17,065			—			17,065
Reissuance (purchase) of treasury stock - net	3,359			—			3,359			(3,530		)	—			(3,530		)
Other (primarily stock compensation)	3,981			—			3,981			(181		)	—			(181		)
Dividends on common stock	(172,313		)	—			(172,313		)	(171,618		)	—			(171,618		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(2,609		)	(2,609		)
Ending balance, June 30	$	3,778,035		$	121,302		$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (APSC) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 129,630	$ 84,165
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	239,743	245,700
Deferred fuel and purchased power	82,261	64,679
Deferred fuel and purchased power amortization	(54,388)	(68,762)
Allowance for equity funds used during construction	(9,931)	(11,319)
Deferred income taxes	66,142	11,945
Change in derivative instruments fair value	(2,618)	(279)
Changes in current assets and liabilities:
Customer and other receivables	(21,424)	43,271
Accrued unbilled revenues	(43,211)	(60,390)
Materials, supplies and fossil fuel	(21,012)	(18,226)
Other current assets	(9,407)	(37,053)
Accounts payable	9,199	37,817
Accrued taxes	19,775	29,530
Other current liabilities	807	3,967
Change in margin and collateral accounts - assets	124	21,185
Change in margin and collateral accounts - liabilities	69,602	39,567
Change in other long-term assets	(1,692)	(26,225)
Change in other long-term liabilities	5,035	57,748
Net cash flow provided by operating activities	458,635	436,279
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(424,775)	(387,272)
Contributions in aid of construction	25,800	21,905
Allowance for borrowed funds used during construction	(6,598)	(7,432)
Proceeds from sale of life insurance policies		55,444
Proceeds from nuclear decommissioning trust sales	211,138	299,600
Investment in nuclear decommissioning trust	(219,762)	(308,222)
Other	(525)	(2,352)
Net cash flow used for investing activities	(414,722)	(328,329)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081	175,000
Short-term borrowing and payments - net	109,000	(9,300)
Repayment of long-term debt	(421,451)	(187,962)
Dividends paid on common stock	(111,297)	(112,537)
Noncontrolling interests	(2,630)	(2,610)
Net cash flow used for financing activities	(66,268)	(125,864)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(22,355)	(17,914)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	33,583	110,188
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11,228	92,274
Cash paid during the period for:
Income taxes, net of (refunds)	(649)
Interest, net of amounts capitalized	94,680	110,659
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	136,356	88,279
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	239,696	245,617
Deferred fuel and purchased power	82,261	64,679
Deferred fuel and purchased power amortization	(54,388)	(68,762)
Allowance for equity funds used during construction	(9,931)	(11,319)
Deferred income taxes	69,672	11,488
Change in derivative instruments fair value	(2,618)	(279)
Changes in current assets and liabilities:
Customer and other receivables	(23,015)	11,104
Accrued unbilled revenues	(43,211)	(60,390)
Materials, supplies and fossil fuel	(21,012)	(18,226)
Other current assets	(6,928)	(9,458)
Accounts payable	9,406	49,939
Accrued taxes	20,890	35,852
Other current liabilities	(3,095)	(3,531)
Change in margin and collateral accounts - assets	124	21,185
Change in margin and collateral accounts - liabilities	69,602	39,567
Change in other long-term assets	(2,456)	(25,004)
Change in other long-term liabilities	5,180	85,262
Net cash flow provided by operating activities	466,533	456,003
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(424,775)	(387,932)
Contributions in aid of construction	25,800	21,905
Allowance for borrowed funds used during construction	(6,598)	(7,432)
Proceeds from sale of life insurance policies		44,183
Proceeds from nuclear decommissioning trust sales	211,138	299,600
Investment in nuclear decommissioning trust	(219,762)	(308,222)
Other	(525)	(2,352)
Net cash flow used for investing activities	(414,722)	(340,250)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081
Short-term borrowing and payments - net	109,000
Repayment of long-term debt	(421,451)	(12,962)
Dividends paid on common stock	(104,900)	(114,300)
Noncontrolling interests	(2,630)	(2,610)
Net cash flow used for financing activities	(68,900)	(129,872)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(17,089)	(14,119)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	19,873	99,937
CASH AND CASH EQUIVALENTS AT END OF PERIOD	2,784	85,818
Cash paid during the period for:
Interest, net of amounts capitalized	$ 92,473	$ 106,546

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Other Income and Other Expense (APSC)

6 Months Ended

Jun. 30, 2012

Other Income and Other Expense

11.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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	107		$	543		$	712		$	935
Investment gains — net	—			12			—			1,307
Miscellaneous	70			2			225			5
Total other income	$	177		$	557		$	937		$	2,247
Other expense:
Non-operating costs	$	(2,389	)	$	(1,629	)	$	(4,239	)	$	(3,119	)
Investment losses — net	(58		)	—			(112		)	—
Miscellaneous	(222		)	(1,557		)	(2,386		)	(1,808		)
Total other expense	$	(2,669	)	$	(3,186	)	$	(6,737	)	$	(4,927	)

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, 2012 and 2011 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Other income:
Interest income	$	77		$	89		$	184		$	219
Investment gains — net	—			268			—			1,418
Miscellaneous	941			876			1,344			1,574
Total other income	$	1,018		$	1,233		$	1,528		$	3,211
Other expense:
Non-operating costs (a)	$	(2,941	)	$	(2,400	)	$	(4,682	)	$	(4,214	)
Asset dispositions	(195		)	—			(418		)	(823		)
Miscellaneous	(857		)	(2,251		)	(3,517		)	(3,206		)
Total other expense	$	(3,993	)	$	(4,651	)	$	(8,617	)	$	(8,243	)

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (APSC) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$ 14,048,957	$ 13,753,971
Accumulated depreciation and amortization	(4,843,868)	(4,709,991)
Net	9,205,089	9,043,980
Construction work in progress	458,441	496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	130,929	132,864
Intangible assets, net of accumulated amortization	163,727	170,571
Nuclear fuel, net of accumulated amortization	159,493	118,098
Total property, plant and equipment	10,117,679	9,962,258
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)	544,933	513,733
Assets from risk management activities (Note 8)	43,526	49,322
Other assets	64,800	64,588
Total investments and other assets	653,259	627,643
CURRENT ASSETS
Cash and cash equivalents	11,228	33,583
Customer and other receivables	316,722	284,183
Accrued unbilled revenues	168,450	125,239
Allowance for doubtful accounts	(3,302)	(3,748)
Materials and supplies (at average cost)	217,222	204,387
Fossil fuel (at average cost)	30,177	22,000
Deferred fuel and purchased power regulatory asset (Note 3)		27,549
Other regulatory assets (Note 3)	54,857	69,072
Deferred income taxes	87,690	130,571
Income tax receivable	885	6,466
Assets from risk management activities (Note 8)	29,991	30,264
Other current assets	33,496	26,904
Total current assets	947,416	956,470
DEFERRED DEBITS
Regulatory assets (Note 3)	1,283,322	1,352,079
Income tax receivable (Note 6)	69,508	68,633
Other	143,223	143,935
Total deferred debits	1,496,053	1,564,647
TOTAL ASSETS	13,214,407	13,111,018
CAPITALIZATION
Common stock	2,452,094	2,439,530
Retained earnings	1,476,259	1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(63,675)	(65,447)
Derivative instruments	(86,643)	(86,716)
Total shareholder equity	3,778,035	3,821,850
Noncontrolling interests (Note 7)	121,302	108,736
Total equity	3,899,337	3,930,586
Long-term debt less current maturities	3,313,992	2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	57,420	65,547
CURRENT LIABILITIES
Short-term borrowings	109,000
Current maturities of long-term debt	57,962	477,435
Accounts payable	316,329	326,987
Accrued taxes (Note 6)	133,766	120,289
Accrued interest	61,451	54,872
Common dividends payable	57,479
Customer deposits	74,575	72,176
Liabilities from risk management activities (Note 8)	64,442	53,968
Deferred fuel and purchased power regulatory liability (Note 3)	325
Other regulatory liabilities (Note 3)	89,433	88,362
Other current liabilities	139,561	148,616
Total current liabilities	1,104,323	1,342,705
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,946,540	1,925,388
Regulatory liabilities (Note 3)	738,693	737,332
Liability for asset retirements	289,641	279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,243,256	1,268,910
Liabilities from risk management activities (Note 8)	108,554	82,495
Customer advances	111,655	116,805
Coal mine reclamation	118,374	117,896
Unrecognized tax benefits (Note 6)	72,977	72,270
Other	209,645	217,934
Total deferred credits and other	4,839,335	4,818,673
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	13,214,407	13,111,018
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,045,091	13,750,105
Accumulated depreciation and amortization	(4,840,292)	(4,706,462)
Net	9,204,799	9,043,643
Construction work in progress	458,441	496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	130,929	132,864
Intangible assets, net of accumulated amortization	163,572	170,416
Nuclear fuel, net of accumulated amortization	159,493	118,098
Total property, plant and equipment	10,117,234	9,961,766
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)	544,933	513,733
Assets from risk management activities (Note 8)	43,526	49,322
Other assets	31,076	30,551
Total investments and other assets	619,535	593,606
CURRENT ASSETS
Cash and cash equivalents	2,784	19,873
Customer and other receivables	314,230	280,100
Accrued unbilled revenues	168,450	125,239
Allowance for doubtful accounts	(3,302)	(3,748)
Materials and supplies (at average cost)	217,222	204,387
Fossil fuel (at average cost)	30,177	22,000
Deferred fuel and purchased power regulatory asset (Note 3)		27,549
Other regulatory assets (Note 3)	54,857	69,072
Deferred income taxes	68,622	111,503
Income tax receivable		2,869
Assets from risk management activities (Note 8)	29,991	30,264
Other current assets	33,468	26,486
Total current assets	916,499	915,594
DEFERRED DEBITS
Regulatory assets (Note 3)	1,283,322	1,352,079
Income tax receivable (Note 6)	69,903	69,028
Unamortized debt issue costs	23,611	21,181
Other	116,293	118,983
Total deferred debits	1,493,129	1,561,271
TOTAL ASSETS	13,146,397	13,032,237
CAPITALIZATION
Common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,469,162	1,510,740
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(37,597)	(38,886)
Derivative instruments	(86,632)	(86,705)
Total shareholder equity	3,902,791	3,943,007
Noncontrolling interests (Note 7)	121,302	108,399
Total equity	4,024,093	4,051,406
Long-term debt less current maturities	3,188,992	2,828,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	57,420	65,547
Total capitalization	7,270,505	6,945,460
CURRENT LIABILITIES
Short-term borrowings	109,000
Current maturities of long-term debt	57,962	477,435
Accounts payable	311,596	322,047
Accrued taxes (Note 6)	134,103	113,930
Accrued interest	61,065	54,611
Common dividends payable	57,500
Customer deposits	74,575	72,176
Liabilities from risk management activities (Note 8)	64,442	53,968
Deferred fuel and purchased power regulatory liability (Note 3)	325
Other regulatory liabilities (Note 3)	89,433	88,362
Other current liabilities	127,352	140,185
Total current liabilities	1,087,353	1,322,714
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,976,973	1,952,608
Regulatory liabilities (Note 3)	738,693	737,332
Liability for asset retirements	289,641	279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,198,943	1,222,542
Liabilities from risk management activities (Note 8)	108,554	82,495
Customer advances	111,655	116,805
Coal mine reclamation	118,374	117,896
Unrecognized tax benefits (Note 6)	72,777	72,073
Other	172,929	182,669
Total deferred credits and other	4,788,539	4,764,063
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$ 13,146,397	$ 13,032,237

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2012

Earnings Per Share

Schedule of earnings per weighted average common share outstanding

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	1.12		$	0.79	$	1.06		$	0.64
Income (loss) from discontinued operations	—			0.01		(0.02		)	0.02
Earnings per share — basic	$	1.12		$	0.80	$	1.04		$	0.66
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	1.12		$	0.78	$	1.05		$	0.64
Income (loss) from discontinued operations	(0.01		)	0.01		(0.01		)	0.01
Earnings per share — diluted	$	1.11		$	0.79	$	1.04		$	0.65

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Commitments and Contingencies (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	6 Months Ended
	Jun. 30, 2012 item D
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	47,000,000
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 assessment per incident of APS	103,000,000
Annual payment limitation with respect to maximum potential 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
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 (in days)	20

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Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Fair Value Measurements

Fair Value Measurements

14.Fair Value Measurements

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.  This category includes exchange-traded equities, exchange-traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.

Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves).  This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities.  This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on the funds’ net asset values (“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 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 2011 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 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 NAV, which is primarily derived from the quoted active market prices of the underlying equity securities.  We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2.  The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 index.  Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

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

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies including mortgage-backed instruments are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield and interest rate 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 assess these valuations and verify that pricing can be supported by actual recent market transactions.  Additionally, we obtain and review independent audit reports on the trustee’s operating controls and valuation processes.  See Note 15 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at June 30, 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 June 30, 2012
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	192		$	—		$	—		$	192
Fixed income securities:
U.S. Treasury	84		—			—			—			84
Cash and cash equivalent funds	—		15			—			(6		)(b)	9
Corporate debt	—		69			—			—			69
Mortgage-backed securities	—		84			—			—			84
Municipality bonds	—		94			—			—			94
Other	—		13			—			—			13
Subtotal nuclear decommissioning trust	84		467			—			(6		)	545
Cash equivalents	2		—			—			—			2
Risk management activities — derivative instruments:
Commodity contracts	—		50			69			(45		)(c)	74
Total	$	86	$	517		$	69		$	(51	)	$	621
Liabilities:
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(199	)	$	(114	)	$	140	(c)	$	(173	)

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

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

(c)Primarily represents counterparty netting, margin and collateral (see Note 8).

The following table presents the fair value at December 31, 2011 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, 2011
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	175		$	—		$	—		$	175
Fixed income securities:
U.S. Treasury	69		—			—			—			69
Cash and cash equivalent funds	—		9			—			(1		)(b)	8
Corporate debt	—		73			—			—			73
Mortgage-backed securities	—		78			—			—			78
Municipality bonds	—		90			—			—			90
Other	—		21			—			—			21
Subtotal nuclear decommissioning trust	69		446			—			(1		)	514
Risk management activities — derivative instruments:
Commodity contracts	—		70			74			(64		)(c)	80
Total	$	69	$	516		$	74		$	(65	)	$	594
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(c)	$	(137	)

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

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

(c)Represents counterparty netting, margin and collateral (see Note 8).

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 generally if the price of the underlying commodity increases we would expect the net fair value of contracts related to that commodity to increase, and 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 fair value of these options to increase, and if these valuation inputs decrease we would expect the fair value of these options to decrease. If natural gas prices and natural gas price implied volatilities increase we would expect the fair value of these options to decrease, and if these inputs decrease we would expect the fair value of the options to increase. The commodity prices and 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 table provides information regarding our significant unobservable inputs used to value our Level 3 instruments.

Risk Management Activities — Derivative Instruments:  Commodity Contracts

	June 30, 2012
	Fair Value (millions)				Valuation	Significant
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range
Electricity:
Forward Contracts (a)	$	67	$	88	Discounted cash flows	Electricity forward price (per MWh)(b)	$20.67 - $67.18
Option Contracts	—		25		Option Model	Electricity forward price (per MWh)(b)	$29.13 - $99.27
						Natural gas forward price (per mmbtu)(c)	$2.69 - $4.11
						Implied electricity price volatilities	15% - 151%
						Implied natural gas price volatilities	18% - 56%
Natural Gas:
Forward Contracts (a)	2		1		Discounted cash flows	Natural gas forward price (per mmbtu)(c)	$2.60 - $4.18
Total	$	69	$	114

(a)Includes swaps and physical and financial contracts.

(b)MWh means megawatt-hour, one million watts per hour.

(c)mmbtu means one million British Thermal Units.

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, 2012 and 2011 (dollars in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2012			2011			2012			2011
Net derivative balance at beginning of period	$	(58	)	$	(48	)	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	1			—			2			1
Included in OCI	3			(3		)	(2		)	(1		)
Deferred as a regulatory asset or liability	12			1			7			(6		)
Settlements	(1		)	4			—			4
Transfers into Level 3 from Level 2	—			1			2			(4		)
Transfers from Level 3 into Level 2	(2		)	(2		)	(3		)	(3		)
Net derivative balance at end of period	$	(45	)	$	(47	)	$	(45	)	$	(47	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	1

Amounts included in earnings are recorded in either regulated electricity segment revenue or regulated electricity segment fuel and purchased power depending on the nature of the underlying contract.

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no transfers in or out of Level 1 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.

Nonrecurring Fair Value Measurements

For the periods ended June 30, 2012 and 2011, we had no assets or liabilities measured at fair value on a nonrecurring basis.

Financial Instruments Not Carried at Fair Value

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

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Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2012

Regulatory Matters

Changes in the deferred fuel and purchased power regulatory asset (liability)

	Six Months Ended June 30,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(82		)	(65		)
Amounts refunded through revenues	54			69
Ending balance	$	—		$	(54	)

Detail of regulatory assets

	June 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	954	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		85		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	18		35		43		34
Transmission vegetation management	9		27		9		32
Coal reclamation	8		28		2		35
Palo Verde VIEs (Note 7)	—		37		—		35
Deferred compensation	—		34		—		33
Deferred fuel and purchased power (a)	—		—		28		—
Tax expense of Medicare subsidy	2		18		2		18
Loss on reacquired debt	1		19		1		19
Income taxes — investment tax credit basis adjustment	1		16		—		15
Pension and other postretirement benefits deferral	8		17		—		12
Demand side management (a)	4		—		7		1
Other	1		13		2		14
Total regulatory assets (b)	$	55	$	1,283	$	97	$	1,352

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

(b)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

	June 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	25	$	340	$	22	$	349
Asset retirement obligations	—		240		—		225
Renewable energy standard (b)	46		—		54		—
Income taxes — change in rates	—		60		—		59
Spent nuclear fuel	9		38		5		44
Deferred gains on utility property	3		13		2		14
Income taxes- deferred investment tax credit	1		33		1		30
Other	6		15		4		16
Total regulatory liabilities	$	90	$	739	$	88	$	737

(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 $)	Jun. 30, 2012	Dec. 31, 2011
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total Assets	$ 73,517,000	$ 79,586,000
Total Liabilities	(172,996,000)	(136,463,000)
Current assets	29,991,000	30,264,000
Investments and Other Assets	43,526,000	49,322,000
Current Liabilities	(64,442,000)	(53,968,000)
Deferred Credits and Other	(108,554,000)	(82,495,000)
Total Derivative Instruments	(99,479,000)	(56,877,000)
Credit Risk and Credit-Related Contingent Features
Risk management assets	73,517,000	79,586,000
Commodity Contracts
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total Assets	74,000,000
Margin and Collateral Provided to Counterparties	103,710,000	174,626,000
Collateral provided from counterparties	(11,145,000)	(11,145,000)
Other	2,548,000	1,356,000
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	83.00%
Risk management assets	74,000,000
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	306,000,000
Cash Collateral Posted	96,000,000
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	136,000,000
Additional collateral to counterparties for energy related non-derivative instrument contracts	184,000,000
Commodity Contracts | Current Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Margin and Collateral Provided to Counterparties	390,000	1,630,000
Other	(37,111,000)	(54,815,000)
Current assets	29,991,000	30,264,000
Commodity Contracts | Investments and Other Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Other	(8,164,000)	(12,755,000)
Investments and Other Assets	43,526,000	49,322,000
Commodity Contracts | Total Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Margin and Collateral Provided to Counterparties	390,000	1,630,000
Other	(45,275,000)	(67,570,000)
Commodity Contracts | Current Liabilities
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Margin and Collateral Provided to Counterparties	83,234,000	107,228,000
Collateral provided from counterparties	(11,145,000)	(11,145,000)
Other	38,149,000	56,172,000
Current Liabilities	(64,442,000)	(53,968,000)
Commodity Contracts | Deferred Credits and Other
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Margin and Collateral Provided to Counterparties	20,086,000	65,768,000
Other	9,674,000	12,754,000
Deferred Credits and Other	(108,554,000)	(82,495,000)
Commodity Contracts | Total Liabilities
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Margin and Collateral Provided to Counterparties	103,320,000	172,996,000
Collateral provided from counterparties	(11,145,000)	(11,145,000)
Other	47,823,000	68,926,000
Commodity Contracts | Designated as Hedging Instruments
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	(5,779,000)	(139,241,000)
Commodity Contracts | Designated as Hedging Instruments | Current Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives		7,287,000
Commodity Contracts | Designated as Hedging Instruments | Investments and Other Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives		3,804,000
Commodity Contracts | Designated as Hedging Instruments | Total Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives		11,091,000
Commodity Contracts | Designated as Hedging Instruments | Current Liabilities
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	(1,185,000)	(82,195,000)
Commodity Contracts | Designated as Hedging Instruments | Deferred Credits and Other
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	(4,594,000)	(68,137,000)
Commodity Contracts | Designated as Hedging Instruments | Total Liabilities
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	(5,779,000)	(150,332,000)
Commodity Contracts | Not Designated as Hedging Instruments
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	(188,813,000)	(82,473,000)
Commodity Contracts | Not Designated as Hedging Instruments | Current Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	66,712,000	76,162,000
Commodity Contracts | Not Designated as Hedging Instruments | Investments and Other Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	51,690,000	58,273,000
Commodity Contracts | Not Designated as Hedging Instruments | Total Assets
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	118,402,000	134,435,000
Commodity Contracts | Not Designated as Hedging Instruments | Current Liabilities
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	(173,495,000)	(124,028,000)
Commodity Contracts | Not Designated as Hedging Instruments | Deferred Credits and Other
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	(133,720,000)	(92,880,000)
Commodity Contracts | Not Designated as Hedging Instruments | Total Liabilities
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Total derivatives	$ (307,215,000)	$ (216,908,000)

XML

Regulatory Matters (Details 2) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Detail of regulatory assets
Regulatory assets, current	$ 55,000,000	$ 97,000,000
Regulatory assets, non-current	1,283,322,000	1,352,079,000
Pension and other postretirement benefits
Detail of regulatory assets
Regulatory assets, non-current	954,000,000	1,023,000,000
Income taxes allowance for funds used during construction (AFUDC) equity
Detail of regulatory assets
Regulatory assets, current	3,000,000	3,000,000
Regulatory assets, non-current	85,000,000	81,000,000
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	18,000,000	43,000,000
Regulatory assets, non-current	35,000,000	34,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	27,000,000	32,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	8,000,000	2,000,000
Regulatory assets, non-current	28,000,000	35,000,000
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, non-current	37,000,000	35,000,000
Deferred compensation
Detail of regulatory assets
Regulatory assets, non-current	34,000,000	33,000,000
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current		28,000,000
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	18,000,000	18,000,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	19,000,000	19,000,000
Income taxes - investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,000,000
Regulatory assets, non-current	16,000,000	15,000,000
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	8,000,000
Regulatory assets, non-current	17,000,000	12,000,000
Demand side management
Detail of regulatory assets
Regulatory assets, current	4,000,000	7,000,000
Regulatory assets, non-current		1,000,000
Other.
Detail of regulatory assets
Regulatory assets, current	1,000,000	2,000,000
Regulatory assets, non-current	$ 13,000,000	$ 14,000,000

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net unrealized gains (loss), tax benefit (expense)	$ (1,781)	$ 6,448	$ 14,770	$ 6,058
Reclassification of net realized loss, tax benefit	9,090	9,988	14,818	15,852
Pension and other postretirement benefits activity, tax expense	$ 526	$ 797	$ 1,157	$ 1,363

XML

Regulatory Matters

6 Months Ended

Jun. 30, 2012

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 APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have 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 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 current 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 currently exists in the PSA 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 July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million.  On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million.  Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 megawatts (“MW”) under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015.  In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications.  Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $92.8 million to $102.4 million.  The budget range stems from options related to distributed energy; if the ACC decides to promote more distributed energy by selecting the higher budget, APS requested that the 2013 incentives for photovoltaic distributed energy begin at $0.20 and step down gradually based upon market participation.  APS’s filing also proposed a system of establishing compliance with distributed energy requirements that depends upon tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  Further, APS described its Community Solar program, a utility-owned 25 MW program that will be split into 3 to 7 separate projects throughout communities in APS’s service territory (this is the 25 MW program described in clause (iv) of the preceding paragraph).  APS expects a decision from the ACC around year end.

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.  In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand side management programs over the current year.  Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis.  The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives.

The ACC previously approved recovery of all 2009 program costs plus incentives.  The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2008 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery.  As requested by APS, 2009 program cost recovery is to be amortized over a three-year period, which ends in 2012.

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 over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates.

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later this year, APS intends to file a supplement to its plan that will include a proposed budget for 2013.

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2012 and 2011 (dollars in millions):

	Six Months Ended June 30,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(82		)	(65		)
Amounts refunded through revenues	54			69
Ending balance	$	—		$	(54	)

The PSA rate for the PSA year beginning February 1, 2012 is negative $0.0042 per kWh as compared to negative $0.0057 per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

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-collected amounts.

Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula.  Approximately $38 million of this revenue increase relates to Retail Transmission Charges.  The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

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.  Because of higher relative system demand by APS’s retail customers, the approximately $16 million increase roughly reflects a $2 million decrease for wholesale customers and an $18 million increase for APS retail customers.

On May 14, 2012, APS filed an application with the ACC to implement the FERC-approved transmission rates for retail customers.  On July 18, 2012, the ACC approved the application authorizing the implementation of the FERC-approved transmission rates for retail customers to be effective beginning in August 2012.

Regulatory Assets and Liabilities

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

	June 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	954	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		85		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	18		35		43		34
Transmission vegetation management	9		27		9		32
Coal reclamation	8		28		2		35
Palo Verde VIEs (Note 7)	—		37		—		35
Deferred compensation	—		34		—		33
Deferred fuel and purchased power (a)	—		—		28		—
Tax expense of Medicare subsidy	2		18		2		18
Loss on reacquired debt	1		19		1		19
Income taxes — investment tax credit basis adjustment	1		16		—		15
Pension and other postretirement benefits deferral	8		17		—		12
Demand side management (a)	4		—		7		1
Other	1		13		2		14
Total regulatory assets (b)	$	55	$	1,283	$	97	$	1,352

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

(b)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):

	June 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	25	$	340	$	22	$	349
Asset retirement obligations	—		240		—		225
Renewable energy standard (b)	46		—		54		—
Income taxes — change in rates	—		60		—		59
Spent nuclear fuel	9		38		5		44
Deferred gains on utility property	3		13		2		14
Income taxes- deferred investment tax credit	1		33		1		30
Other	6		15		4		16
Total regulatory liabilities	$	90	$	739	$	88	$	737

(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.

XML

Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012 item
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	114
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	88
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)	20.67
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)	67.18
Option Contracts | Option Model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	25
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)	29.13
Natural gas forward price (per mmbtu)	2.69
Implied electricity price volatilities (as a percent)	15.00%
Implied natural gas price volatilities (as a percent)	18.00%
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)	99.27
Natural gas forward price (per mmbtu)	4.11
Implied electricity price volatilities (as a percent)	151.00%
Implied natural gas price volatilities (as a percent)	56.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	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)	2.60
Natural gas forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per mmbtu)	4.18

XML

Changes in Equity (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Changes in equity
Balance at beginning of period	$ 3,861,429	$ 3,728,771	$ 3,930,586	$ 3,775,226
Net income	130,111	93,839	129,630	84,165
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	17,459	6,646	1,845	17,092
COMPREHENSIVE INCOME	147,570	100,485	131,475	101,257
Dividends on common stock	(114,955)	(114,509)	(172,313)	(171,618)
Net capital activities by noncontrolling interests	(2,976)	(2,609)	(2,976)	(2,609)
Other	631	(33)	3,981	(181)
Balance at end of period	3,899,337	3,715,610	3,899,337	3,715,610
Shareholder equity
Changes in equity
Balance at beginning of period	3,744,917	3,631,411	3,821,850	3,683,327
Net income	122,345	86,685	114,088	71,550
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	17,459	6,646	1,845	17,092
COMPREHENSIVE INCOME	139,804	93,331	115,933	88,642
Dividends on common stock	(114,955)	(114,509)	(172,313)	(171,618)
Other	631	(33)	3,981	(181)
Balance at end of period	3,778,035	3,613,705	3,778,035	3,613,705
NONCONTROLLING INTERESTS
Changes in equity
Balance at beginning of period	116,512	97,360	108,736	91,899
Net income	7,766	7,154	15,542	12,615
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME	7,766	7,154	15,542	12,615
Net capital activities by noncontrolling interests	(2,976)	(2,609)	(2,976)	(2,609)
Balance at end of period	121,302	101,905	121,302	101,905
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Balance at beginning of period	3,981,914	3,862,685	4,051,406	3,916,037
Net income	132,694	94,889	136,356	88,279
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	17,117	6,730	1,362	17,088
COMPREHENSIVE INCOME	149,811	101,619	137,718	105,367
Dividends on common stock	(105,000)	(114,500)	(162,400)	(171,600)
Net capital activities by noncontrolling interests	(2,630)	(2,610)	(2,630)	(2,610)
Other	(2)	1	(1)	1
Balance at end of period	4,024,093	3,847,195	4,024,093	3,847,195
ARIZONA PUBLIC SERVICE COMPANY | Shareholder equity
Changes in equity
Balance at beginning of period	3,865,748	3,766,131	3,943,007	3,824,953
Net income	124,928	87,705	120,823	75,625
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	17,117	6,730	1,362	17,088
COMPREHENSIVE INCOME	142,045	94,435	122,185	92,713
Dividends on common stock	(105,000)	(114,500)	(162,400)	(171,600)
Other	(2)	1	(1)	1
Balance at end of period	3,902,791	3,746,067	3,902,791	3,746,067
ARIZONA PUBLIC SERVICE COMPANY | NONCONTROLLING INTERESTS
Changes in equity
Balance at beginning of period	116,166	96,554	108,399	91,084
Net income	7,766	7,184	15,533	12,654
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME	7,766	7,184	15,533	12,654
Net capital activities by noncontrolling interests	(2,630)	(2,610)	(2,630)	(2,610)
Balance at end of period	121,302	101,128	121,302	101,128
PINNACLE WEST CAPITAL CORPORATION | Shareholder equity
Changes in equity
Balance at beginning of period	3,744,917	3,631,411	3,821,850	3,683,327
Net income	122,345	86,685	114,088	71,550
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	17,459	6,646	1,845	17,092
COMPREHENSIVE INCOME	139,804	93,331	115,933	88,642
Dividends on common stock	(114,955)	(114,509)	(172,313)	(171,618)
Other	631	(33)	3,981	(181)
Balance at end of period	3,778,035	3,613,705	3,778,035	3,613,705
PINNACLE WEST CAPITAL CORPORATION | NONCONTROLLING INTERESTS
Changes in equity
Balance at beginning of period	116,512	97,360	108,736	91,899
Net income	7,766	7,154	15,542	12,615
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME	7,766	7,154	15,542	12,615
Net capital activities by noncontrolling interests	(2,976)	(2,609)	(2,976)	(2,609)
Balance at end of period	$ 121,302	$ 101,905	$ 121,302	$ 101,905

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Retirement Plans and Other Benefits (Tables)

6 Months Ended

Jun. 30, 2012

Retirement Plans and Other Benefits

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

	Pension Benefits												Other Benefits
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost - benefits earned during the period	$	15		$	13		$	32		$	29		$	6		$	5		$	14		$	11
Interest cost on benefit obligation	30			31			60			62			11			12			23			23
Expected return on plan assets	(35		)	(33		)	(71		)	(67		)	(11		)	(11		)	(23		)	(21		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	12			7			22			13			4			4			10			8
Net periodic benefit cost	$	22		$	18		$	44		$	38		$	10		$	10		$	24		$	21
Portion of cost charged to expense	$	8		$	7		$	13		$	15		$	3		$	4		$	6		$	8

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Consolidation and Nature of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating Revenues
OPERATING REVENUES	$ 878,576	$ 799,799	$ 1,499,207	$ 1,448,646
Cash Flows from Operating Activities
Change in other long-term assets			(1,692)	(26,225)
As previously reported
Operating Revenues
Regulated electricity segment		798,669		1,446,643
Other revenues		1,130		2,003
Cash Flows from Operating Activities
Expenditures for real estate investments				(40)
Change in other long-term assets				(26,185)
Reclassifications to conform to current year presentation
Operating Revenues
Regulated electricity segment		(798,669)		(1,446,643)
Other revenues		(1,130)		(2,003)
OPERATING REVENUES		799,799		1,448,646
Cash Flows from Operating Activities
Expenditures for real estate investments				40
Change in other long-term assets				(40)
Amount reported after reclassification to conform to current year presentation
Operating Revenues
OPERATING REVENUES		799,799		1,448,646
Cash Flows from Operating Activities
Change in other long-term assets				$ (26,225)

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Discontinued Operations

6 Months Ended

Jun. 30, 2012

Discontinued Operations

Discontinued Operations

13.Discontinued Operations

SunCor — In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations, or cash flows.  All activity for the income statement for the three and six months ended June 30, 2012 and prior comparative period income statement amounts are included in discontinued operations.

APSES — In 2011, Pinnacle West sold its investment in APSES.  Prior-period income statement amounts related to the sale of APSES and the associated revenues and costs are reflected in discontinued operations.

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2012 and 2011 (dollars in millions):

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Revenue:
SunCor	$	—		$	2	$	—		$	3
APSES	—			15		—			26
Total revenue	$	—		$	17	$	—		$	29
Income (loss) before taxes	$	(1	)	$	1	$	(3	)	$	2
Income (loss) after taxes	$	(1	)	$	1	$	(1	)	$	1