10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

OR

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

For the transition period from              to            

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

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

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION

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

ARIZONA PUBLIC SERVICE COMPANY

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

Indicate by check mark whether each registrant is a shell company (as defined in 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 April 27, 2012: 109,477,427
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of April 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	39
	Item 2.	Management’s Discussion and Analysis of Financial Condition
		and Results of Operations	46
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62
	Item 4.	Controls and Procedures	62
Part II			64
	Item 1.	Legal Proceedings	64
	Item 1A.	Risk Factors	64
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
	Item 5.	Other Information	65
	Item 6.	Exhibits	66
Signatures			69

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

·our ability to manage capital expenditures and other 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;

·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 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 March 31,
	2012			2011
OPERATING REVENUES	$	620,631		$	648,847
OPERATING EXPENSES
Fuel and purchased power	216,309			212,007
Operations and maintenance	210,663			255,029
Depreciation and amortization	100,109			106,583
Taxes other than income taxes	42,475			37,624
Other expenses	3,068			1,820
Total	572,624			613,063
OPERATING INCOME	48,007			35,784
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	4,756			5,395
Other income (Note 11)	760			1,690
Other expense (Note 11)	(4,068		)	(1,741		)
Total	1,448			5,344
INTEREST EXPENSE
Interest charges	56,967			61,077
Allowance for borrowed funds used during construction	(3,151		)	(3,576		)
Total	53,816			57,501
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(4,361		)	(16,373		)
INCOME TAXES	(4,645		)	(6,005		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	284			(10,368		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(505) and $330 (Note 13)	(765		)	694
NET LOSS	(481		)	(9,674		)
Less: Net income attributable to noncontrolling interests (Note 7)	7,776			5,461
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(8,257	)	$	(15,135	)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,299			108,832
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	109,299			108,832
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Loss from continuing operations attributable to common shareholders — basic	$	(0.07	)	$	(0.15	)
Net loss attributable to common shareholders — basic	(0.08		)	(0.14		)
Loss from continuing operations attributable to common shareholders — diluted	(0.07		)	(0.15		)
Net loss attributable to common shareholders — diluted	(0.08		)	(0.14		)
DIVIDENDS DECLARED PER SHARE	$	0.525		$	0.525
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Loss from continuing operations, net of tax	$	(7,483	)	$	(15,838	)
Discontinued operations, net of tax	(774		)	703
Net loss attributable to common shareholders	$	(8,257	)	$	(15,135	)

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 March 31,
	2012			2011
NET LOSS	$	(481	)	$	(9,674	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $16,551 and $(390)	(25,352		)	598
Reclassification of net realized loss, net of tax benefit of $5,728 and $5,865	8,772			8,982
Pension and other postretirement benefits activity, net of tax expense of $631 and $566	966			866
Total other comprehensive income (loss)	(15,614		)	10,446
COMPREHENSIVE INCOME (LOSS)	(16,095		)	772
Less: Comprehensive income attributable to noncontrolling interests	7,776			5,461
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(23,871	)	$	(4,689	)

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

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	20,710		$	33,583
Customer and other receivables	238,387			284,183
Accrued unbilled revenues	104,728			125,239
Allowance for doubtful accounts	(2,886		)	(3,748		)
Materials and supplies (at average cost)	213,290			204,387
Fossil fuel (at average cost)	26,850			22,000
Deferred income taxes	141,224			130,571
Income tax receivable (Note 6)	8,894			6,466
Assets from risk management activities (Note 8)	34,617			30,264
Deferred fuel and purchased power regulatory asset (Note 3)	5,310			27,549
Other regulatory assets (Note 3)	81,457			69,072
Other current assets	32,219			26,904
Total current assets	904,800			956,470
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)	53,124			49,322
Nuclear decommissioning trust (Note 15)	541,989			513,733
Other assets	64,415			64,588
Total investments and other assets	659,528			627,643
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	13,928,709			13,753,971
Accumulated depreciation and amortization	(4,775,904		)	(4,709,991		)
Net	9,152,805			9,043,980
Construction work in progress	462,425			496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	131,897			132,864
Intangible assets, net of accumulated amortization	170,198			170,571
Nuclear fuel, net of accumulated amortization	141,882			118,098
Total property, plant and equipment	10,059,207			9,962,258
DEFERRED DEBITS
Regulatory assets (Note 3)	1,344,523			1,352,079
Income tax receivable (Note 6)	69,069			68,633
Other	146,787			143,935
Total deferred debits	1,560,379			1,564,647
TOTAL ASSETS	$	13,183,914		$	13,111,018

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

5

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2012			December 31, 2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	265,975		$	326,987
Accrued taxes (Note 6)	160,136			120,289
Accrued interest	44,736			54,872
Short-term borrowings	216,600			—
Current maturities of long-term debt	101,708			477,435
Customer deposits	74,297			72,176
Liabilities from risk management activities (Note 8)	89,207			53,968
Regulatory liabilities (Note 3)	89,622			88,362
Other current liabilities	115,618			148,616
Total current liabilities	1,157,899			1,342,705
LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities	3,275,651			2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	65,547			65,547
Total long-term debt less current maturities	3,341,198			3,019,054
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,918,995			1,925,388
Regulatory liabilities (Note 3)	754,210			737,332
Liability for asset retirements	284,839			279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,277,227			1,268,910
Liabilities from risk management activities (Note 8)	64,168			82,495
Customer advances	113,514			116,805
Coal mine reclamation	118,113			117,896
Unrecognized tax benefits (Note 6)	72,622			72,270
Other	219,700			217,934
Total deferred credits and other	4,823,388			4,818,673
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 9)
Common stock, no par value	2,450,296			2,444,247
Treasury stock	(6,471		)	(4,717		)
Total common stock	2,443,825			2,439,530
Retained earnings	1,468,869			1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(64,481		)	(65,447		)
Derivative instruments	(103,296		)	(86,716		)
Total accumulated other comprehensive loss	(167,777		)	(152,163		)
Total shareholders’ equity	3,744,917			3,821,850
Noncontrolling interests (Note 7)	116,512			108,736
Total equity	3,861,429			3,930,586
TOTAL LIABILITIES AND EQUITY	$	13,183,914		$	13,111,018

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

6

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(481	)	$	(9,674	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	118,487			123,298
Deferred fuel and purchased power	46,754			49,947
Deferred fuel and purchased power amortization	(24,514		)	(31,238		)
Allowance for equity funds used during construction	(4,756		)	(5,395		)
Deferred income taxes	(1,989		)	(41,005		)
Change in mark-to-market valuations	1,985			(284		)
Changes in current assets and liabilities:
Customer and other receivables	52,264			75,528
Accrued unbilled revenues	20,511			9,633
Materials, supplies and fossil fuel	(13,753		)	21,421
Other current assets	(3,502		)	(636		)
Accounts payable	(39,355		)	(24,543		)
Accrued taxes and income tax receivable — net	37,398			52,944
Other current liabilities	(39,804		)	(37,406		)
Change in unrecognized tax benefits	—			18,959
Change in margin and collateral accounts — assets	(1,853		)	4,220
Change in margin and collateral accounts — liabilities	(32,950		)	35,478
Change in other long-term assets	(21,469		)	(33,169		)
Change in other long-term liabilities	22,362			35,418
Net cash flow provided by operating activities	115,335			243,496
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(240,973		)	(191,553		)
Contributions in aid of construction	13,871			9,136
Allowance for borrowed funds used during construction	(3,151		)	(3,576		)
Proceeds from nuclear decommissioning trust sales	92,047			189,318
Investment in nuclear decommissioning trust	(96,360		)	(194,241		)
Other	(533		)	(1,879		)
Net cash flow used for investing activities	(235,099		)	(192,795		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	319,081			175,000
Repayment of long-term debt	(375,727		)	(175,170		)
Short-term borrowings and payments — net	216,600			700
Dividends paid on common stock	(55,595		)	(55,300		)
Common stock equity issuance	4,289			11,727
Other	(1,757		)	(3,653		)
Net cash flow provided by (used for) financing activities	106,891			(46,696		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(12,873		)	4,005
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	33,583			110,188
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	20,710		$	114,193
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	(650	)	$	—
Interest, net of amounts capitalized	$	62,892		$	55,997

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

7

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, SunCor Development Company (“SunCor”), El Dorado Investment Company (“El Dorado”) and formerly 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 in accordance with accounting requirements for reporting discontinued operations (see Note 13) and to conform to current year presentation, and on our 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):

8

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Statement of Income for the Three Months Ended March 31, 2011	As previously reported			Reclassifications for discontinued operations and to conform to current year presentation			Amount reported after reclassification for discontinued operations and to conform to current year presentation
Operating Revenues
Regulated electricity segment revenues	$	647,974		$	(647,974	)	$	—
Other revenues	11,601			(11,601		)	—
Operating revenues	—			648,847			648,847
Operating Expenses
Operations and maintenance	256,486			(1,457		)	255,029
Depreciation and amortization	106,601			(18		)	106,583
Other expenses	9,716			(7,896		)	1,820
Other
Other expense	(1,699		)	(42		)	(1,741		)
Income Taxes	(5,649		)	(356		)	(6,005		)
Income From Continuing Operations	(9,325		)	(1,043		)	(10,368		)
Income From Discontinued Operations	(349		)	1,043			694

Statement of Cash Flows for the Three Months Ended March 31, 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		$	—
Gains and other changes in real estate assets	(3		)	3			—
Change in other long-term assets	(33,129		)	(40		)	(33,169		)
Change in other long-term liabilities	35,421			(3		)	35,418

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 March 31, 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 March 31, 2012, Pinnacle West had no

9

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

At March 31, 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 March 31, 2012, APS had commercial paper borrowings of $217 million, and no borrowings or letters of credit outstanding under either of these credit facilities.

On May 1, 2012, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011.

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

10

PINNACLE WEST CAPITAL CORPORATION

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 March 31, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	123	$	125	$	123
APS	3,318		3,748		3,371		3,803
Total	$	3,443	$	3,871	$	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 March 31, 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 the 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.

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 increase the average retail customer bill approximately 6.6%.  The filing is based on a test year ended December 31, 2010, adjusted as described below.  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.  The Settlement Agreement requires the approval of the ACC.  Evidentiary hearings on the matter were completed on February 3, 2012 and briefs from the parties were filed on February 29, 2012.  See below for details regarding the Settlement Agreement.

The key financial provisions of APS’s original request included:

·An increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through APS’s renewable energy surcharge (which will increase base rates) and $143.5

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million of lower fuel and purchased power costs currently addressed through the Power Supply Adjustor (“PSA”) (which will decrease base rates);

·A rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;

·The following proposed capital structure and costs of capital:

	Capital Structure		Cost of Capital
Long-term debt	46.1	%	6.38	%
Common stock equity	53.9	%	11.00	%
Weighted-average cost of capital			8.87	%

·A base rate for fuel and purchased power costs (“Base Fuel Rate”) of $0.03242 per kilowatt-hour (“kWh”) based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

APS proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision.  In addition, APS proposed a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.

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 from $0.03757 to $0.03207 per 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;

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·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 approximately $5 million annually;

·Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

·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.

If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012.  As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.

2008 General Retail Rate Case 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 included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel

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and purchased power revenues from the then-existing PSA to base rates.  The new rates were effective January 1, 2010.  The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

·Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

·An authorized return on common equity of 11%;

·A capital structure comprised of 46.2% debt and 53.8% common equity;

·A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);

·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 and its use of renewable energy, 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

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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.

Demand-Side Management Adjustor Charge (“DSMAC”).  The settlement agreement resulting from the 2008 retail rate case requires APS to submit an annual 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.

On June 1, 2010, APS filed its 2011 Demand-Side Management Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million.  On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed in the previous paragraph less the $10 million already being recovered in general retail base rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.

On June 1, 2011, APS filed its 2012 Demand-Side Management Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% 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 (1.5% of total energy resources). 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.

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):

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	Three Months Ended March 31,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(47		)	(50		)
Amounts refunded through revenues	24			31
Ending balance	$	5		$	(77	)

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 must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  If the Settlement Agreement (discussed above) is approved, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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

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Regulatory Assets and Liabilities

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

	March 31, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	1,007	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		81		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	58		34		43		34
Transmission vegetation management	9		30		9		32
Coal reclamation	2		34		2		35
Palo Verde VIEs (Note 7)	—		36		—		35
Deferred compensation	—		34		—		33
Deferred fuel and purchased power (a)	5		—		28		—
Tax expense of Medicare subsidy	2		19		2		18
Loss on reacquired debt	1		19		1		19
Income taxes — investment tax credit basis adjustment	—		15		—		15
Pension and other postretirement benefits deferral	—		21		—		12
Demand-side management (a)	5		—		7		1
Other	2		15		2		14
Total regulatory assets (b)	$	87	$	1,345	$	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):

	March 31, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	24	$	344	$	22	$	349
Asset retirement obligations	—		249		—		225
Renewable energy standard (b)	50		—		54		—
Income taxes — change in rates	—		59		—		59
Spent nuclear fuel	7		41		5		44
Deferred gains on utility property	2		14		2		14
Income taxes- deferred investment tax credit	1		32		1		30
Other	6		15		4		16
Total regulatory liabilities	$	90	$	754	$	88	$	737

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(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 $9 million for the three months ended March 31, 2012 and $3 million for the three months ended March 31, 2011.  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 March 31,						Three Months Ended March 31,
	2012			2011			2012			2011
Service cost - benefits earned during the period	$	16		$	16		$	7		$	6
Interest cost on benefit obligation	30			31			12			12
Expected return on plan assets	(35		)	(33		)	(11		)	(10		)
Amortization of net actuarial loss	11			6			6			3
Net periodic benefit cost	$	22		$	20		$	14		$	11
Portion of cost charged to expense	$	6		$	8		$	3		$	4

Contributions

The required minimum contribution to our pension plan is approximately $65 million in 2012, approximately $160 million in 2013 and approximately $175 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 reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Three Months Ended March 31,
	2012			2011
Operating revenues:
Regulated electricity segment	$	620		$	648
All other (a)	1			1
Total	$	621		$	649
Net loss attributable to common shareholders:
Regulated electricity segment	$	(6	)	$	(15	)
All other (a)	(2		)	—
Total	$	(8	)	$	(15	)

	As of March 31, 2012		As of December 31, 2011
Assets:
Regulated electricity segment	$	13,142	$	13,068
All other (a)	42		43
Total	$	13,184	$	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 $69 million income tax receivable on the Condensed Consolidated Balance Sheets primarily 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 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 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 may give APS the ability to utilize the asset for a significant portion of the asset’s economic life.  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 months ended March 31, 2012 of $8 million and for the three months ended March 31, 2011 of $5 million, 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 March 31, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

	March 31, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	132	$	133
Current maturities of long-term debt	31		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	66		66
Equity — Noncontrolling interests	116		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 March 31, 2012, APS would have been required to pay the noncontrolling equity participants approximately $141 million and assume $97 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.

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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 are 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, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 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 purchase 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 other comprehensive income (“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 of March 31, 2012, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

For its regulated operations, APS defers 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.  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 March 31, 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	11,048	gigawatt hours
Gas	146	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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2012			2011
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive income (loss) — derivative instruments	$	(41,903	)	$	988
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized)	Fuel and purchased power	(14,500		)	(14,847		)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)	Fuel and purchased power	85			12

(a)During the three months ended March 31, 2012 and 2011, we had no amounts 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 $97 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, certain of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2012 and 2011 (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues	$	(326	)	$	1,507
Net Loss Recognized in Income from Derivative Instruments	Fuel and purchased power expense	(25,052		)	(9,026		)
Total		$	(25,378	)	$	(7,519	)

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 contractual net settlement provisions 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 March 31, 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 (a)			Other (b)			Total
Current Assets	$	6,466		$	80,364		$	3,486	$	—		$	(55,699	)	$	34,617
Investments and Other Assets	3,377			57,639			—		—			(7,892		)	53,124
Total Assets	9,843			138,003			$	3,486	$	—		(63,591		)	87,741
Current Liabilities	(103,592		)	(131,751		)	100,228		(11,145		)	57,053			(89,207		)
Deferred Credits and Other	(80,252		)	(97,503		)	105,718		—			7,869			(64,168		)
Total Liabilities	(183,844		)	(229,254		)	205,946		(11,145		)	64,922			(153,375		)
Total	$	(174,001	)	$	(91,251	)	$	209,432	$	(11,145	)	$	1,331		$	(65,634	)

(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):

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Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties (a)			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		)	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 $88 million of risk management assets as of March 31, 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 March 31, 2012 (dollars in millions):

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	March 31, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	380
Cash Collateral Posted	180
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	169

(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the footnote 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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(8,257		)	7,776		(481		)	(15,135		)	5,461		(9,674		)
OCI (loss)	(15,614		)	—		(15,614		)	10,446			—		10,446
Total comprehensive income (loss)	(23,871		)	7,776		(16,095		)	(4,689		)	5,461		772
Issuance of capital stock	2,700			—		2,700			2,689			—		2,689
Purchase of treasury stock, net of reissuances	(1,754		)	—		(1,754		)	(3,530		)	—		(3,530		)
Other (primarily stock compensation)	3,350			—		3,350			10,723			—		10,723
Dividends on common stock	(57,358		)	—		(57,358		)	(57,109		)	—		(57,109		)
Ending balance, March 31	$	3,744,917		$	116,512	$	3,861,429		$	3,631,411		$	97,360	$	3,728,771

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10.Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

APS currently estimates it will incur $122 million (in 2012 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 March 31, 2012, APS had a regulatory liability of $48 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 March 31, 2012, certain contractual obligations have increased approximately $0.3 billion from December 31, 2011 as discussed in the 2011 Form 10-K.  The updated contractual obligations are as follows (dollars in billions):

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Year	2012		2013		2014		2015		2016		Thereafter		Total
Fuel and purchased power commitments	$	0.4	$	0.4	$	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.

This hearing has been held in abeyance to provide an opportunity for the parties to engage in settlement negotiations.  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

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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.  In addition, the Western Electricity Coordinating Council (“WECC”) initiated a Detailed Disturbance Analysis process to identify and understand the cause of the events that occurred, and identify and ensure timely implementation of corrective actions.

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 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 the 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 other 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

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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.  APS and Pinnacle West filed a motion to dismiss that was granted by the Court on March 20, 2012.  The case was stayed as to SDG&E until the earlier of six months or the release of a FERC or California Public Utilities Commission (“CPUC”) report on the outage.  The Court stated that the plaintiffs may refile a complaint against APS and Pinnacle West on certain grounds following the release of either report.

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 with the court.  Earthjustice’s responses to these motions are due May 16, 2012.  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 March 31, 2012, approximately $44 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.  These letters of credit 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 March 31, 2012.  Additionally, APS has issued letters of credit to support collateral obligations under certain natural gas tolling contracts entered into with third parties.  At March 31, 2012, $30 million of such letters of credit were outstanding.  These letters of credit will expire in 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

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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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	605		$	391
Investment gains — net	—			1,293
Miscellaneous	155			6
Total other income	$	760		$	1,690
Other expense:
Non-operating costs	$	(1,850	)	$	(1,487	)
Investment losses — net	(53		)	—
Miscellaneous	(2,165		)	(254		)
Total other expense	$	(4,068	)	$	(1,741	)

12.          Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012			2011
Basic earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.07	)	$	(0.15	)
Income (loss) from discontinued operations	(0.01		)	0.01
Loss per share — basic	$	(0.08	)	$	(0.14	)
Diluted earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.07	)	$	(0.15	)
Income (loss) from discontinued operations	(0.01		)	0.01
Loss per share — diluted	$	(0.08	)	$	(0.14	)

For the three months ended March 31, 2012 and 2011, the weighted average common shares outstanding were the same for both basic and diluted shares.

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For the three months ended March 31, 2012 and 2011, options to purchase shares of common stock were outstanding but excluded from the computation of diluted earnings per share because of their antidilutive effect.  This is a result of the net loss position in both periods.

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 months ended March 31, 2012 and prior comparative period income statement amounts are included in discontinued operations.  At March 31, 2012, SunCor had approximately $8 million of assets on its balance sheet, including $7 million of intercompany receivables and $1 million of other assets.

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 months ended March 31, 2012 and 2011 (dollars in millions):

	Three Months Ended March 31,
	2012			2011
Revenue:
SunCor	$	—		$	1
APSES	—			11
Total revenue	$	—		$	12
Income (loss) before taxes:	$	(1	)	$	1
Income (loss) after taxes:	$	(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

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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 transactions, 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

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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.

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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Fair Value Tables

The following table presents the fair value at March 31, 2012 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at March 31, 2012
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	196		$	—		$	—		$	196
Fixed income securities:
U.S. Treasury	76		—			—			—			76
Cash and cash equivalent funds	—		15			—			(1		)(c)	14
Corporate debt	—		67			—			—			67
Mortgage-backed securities	—		82			—			—			82
Municipality bonds	—		88			—			—			88
Other	—		19			—			—			19
Subtotal nuclear decommissioning trust	76		467			—			(1		)	542
Cash Equivalents	12		—			—			—			12
Risk management activities — derivative instruments:
Commodity contracts	—		63			84			(59		)(b)	88
Total	$	88	$	530		$	84		$	(60	)	$	642
Liabilities:
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(271	)	$	(142	)	$	260	(b)	$	(153	)

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

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

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

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):

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	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		)(c)	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		)(b)	80
Total	$	69	$	516		$	74		$	(65	)	$	594
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(b)	$	(137	)

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

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

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

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Because our 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.  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.

35

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Risk Management Activities-Derivative Instruments: Commodity Contracts

	March 31, 2012 Fair Value (millions)
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range
Electricity:
Forward Contracts	$	79	$	106	Discounted cash flows	Electricity prices	$7.13 - $67.50 per MWh
Option Contracts	—		35		Option Model	Electricity prices	$21.15 - $94.23 per MWh
						Natural gas prices	$1.90 - $4.31 per mmbtu
						Electricity volatilities	14% - 83%
						Natural gas volatilities	17% - 50%
Natural Gas:
Forward Contracts	5		1		Discounted cash flows	Natural gas prices	$1.85 - $4.20 per mmbtu
Total	$	84	$	142

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 months ended March 31, 2012 and 2011 (dollars in millions):

	Three Months Ended March 31,
Commodity Contracts	2012			2011
Net risk management activities balance at beginning of period	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	1			1
Included in OCI	(5		)	2
Deferred as a regulatory asset or liability	(5		)	(7		)
Settlements	1			—
Transfers into Level 3 from Level 2	2			(5		)
Transfers from Level 3 into Level 2	(1		)	(1		)
Net risk management activities at end of period	$	(58	)	$	(48	)
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 significant Level 1

36

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our heat rate options and long-dated energy transactions that extend beyond available quoted periods.

Nonrecurring Fair Value Measurements

For the periods ended March 31, 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 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 March 31, 2012 and December 31, 2011 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2012
Equity securities	$	196		$	64	$	—
Fixed income securities	347			21		(1		)
Net receivables (a)	(1		)	—		—
Total	$	542		$	85	$	(1	)

(a)           Net receivables 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	)

37

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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 March 31,
	2012			2011
Realized gains	$	2		$	1
Realized losses	(1		)	(2		)
Proceeds from the sale of securities (a)	92			189

(a)           Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2012 is as follows (dollars in millions):

	Fair Value
Less than one year	$	19
1 year - 5 years	85
5 years - 10 years	107
Greater than 10 years	136
Total	$	347

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.

38

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2012			2011
ELECTRIC OPERATING REVENUES	$	620,248		$	647,994
OPERATING EXPENSES
Fuel and purchased power	216,309			212,007
Operations and maintenance	208,447			252,607
Depreciation and amortization	100,085			106,559
Income taxes	(814		)	(6,003		)
Taxes other than income taxes	42,226			37,250
Total	566,253			602,420
OPERATING INCOME	53,995			45,574
OTHER INCOME (DEDUCTIONS)
Income taxes	1,706			(1,340		)
Allowance for equity funds used during construction	4,756			5,395
Other income (Note S-2)	510			1,978
Other expense (Note S-2)	(4,624		)	(3,592		)
Total	2,348			2,441
INTEREST EXPENSE
Interest on long-term debt	52,737			54,737
Interest on short-term borrowings	2,035			2,308
Debt discount, premium and expense	1,060			1,157
Allowance for borrowed funds used during construction	(3,151		)	(3,576		)
Total	52,681			54,626
NET INCOME (LOSS)	3,662			(6,611		)
Less: Net income attributable to noncontrolling interests (Note 7)	7,767			5,470
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDER	$	(4,105	)	$	(12,081	)

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

39

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2012			2011
NET INCOME (LOSS)	$	3,662		$	(6,611	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $16,554 and $(390)	(25,348		)	598
Reclassification of net realized loss, net of tax benefit of $5,728 and $5,865	8,772			8,981
Pension and other postretirement benefits activity, net of tax expense $536 and $509	821			779
Total other comprehensive income (loss)	(15,755		)	10,358
COMPREHENSIVE INCOME (LOSS)	(12,093		)	3,747
Less: Comprehensive income attributable to noncontrolling interests	7,767			5,470
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(19,860	)	$	(1,723	)

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

40

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31,			December 31,
	2012			2011
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	13,924,843		$	13,750,105
Accumulated depreciation and amortization	(4,772,352		)	(4,706,462		)
Net	9,152,491			9,043,643
Construction work in progress	462,425			496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	131,897			132,864
Intangible assets, net of accumulated amortization	170,043			170,416
Nuclear fuel, net of accumulated amortization	141,882			118,098
Total property, plant and equipment	10,058,738			9,961,766
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)	541,989			513,733
Assets from risk management activities (Note 8)	53,124			49,322
Other assets	31,084			30,551
Total investments and other assets	626,197			593,606
CURRENT ASSETS
Cash and cash equivalents	2,081			19,873
Customer and other receivables	234,152			280,100
Accrued unbilled revenues	104,728			125,239
Allowance for doubtful accounts	(2,886		)	(3,748		)
Materials and supplies (at average cost)	213,290			204,387
Fossil fuel (at average cost)	26,850			22,000
Deferred fuel and purchased power regulatory asset (Note 3)	5,310			27,549
Other regulatory assets (Note 3)	81,457			69,072
Deferred income taxes	122,156			111,503
Income tax receivable	3,283			2,869
Assets from risk management activities (Note 8)	34,617			30,264
Other current assets	32,146			26,486
Total current assets	857,184			915,594
DEFERRED DEBITS
Regulatory assets (Note 3)	1,344,523			1,352,079
Income tax receivable (Note 6)	69,464			69,028
Unamortized debt issue costs	23,592			21,181
Other	118,907			118,983
Total deferred debits	1,556,486			1,561,271
TOTAL ASSETS	$	13,098,605		$	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.

41

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31,			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	1,449,236			1,510,740
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(38,065		)	(38,886		)
Derivative instruments	(103,281		)	(86,705		)
Total shareholder equity	3,865,748			3,943,007
Noncontrolling interests (Note 7)	116,166			108,399
Total equity	3,981,914			4,051,406
Long-term debt less current maturities	3,150,651			2,828,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	65,547			65,547
Total capitalization	7,198,112			6,945,460
CURRENT LIABILITIES
Commercial paper	216,600			—
Current maturities of long-term debt	101,708			477,435
Accounts payable	260,578			322,047
Accrued taxes (Note 6)	156,404			113,930
Accrued interest	44,531			54,611
Customer deposits	74,297			72,176
Liabilities from risk management activities (Note 8)	89,207			53,968
Regulatory liabilities (Note 3)	89,622			88,362
Other current liabilities	93,485			140,185
Total current liabilities	1,126,432			1,322,714
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,946,063			1,952,608
Regulatory liabilities (Note 3)	754,210			737,332
Liability for asset retirements	284,839			279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,231,725			1,222,542
Liabilities from risk management activities (Note 8)	64,168			82,495
Customer advances	113,514			116,805
Coal mine reclamation	118,113			117,896
Unrecognized tax benefits (Note 6)	72,424			72,073
Other	189,005			182,669
Total deferred credits and other	4,774,061			4,764,063
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	13,098,605		$	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.

42

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	3,662		$	(6,611	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	118,463			123,256
Deferred fuel and purchased power	46,754			49,947
Deferred fuel and purchased power amortization	(24,514		)	(31,238		)
Allowance for equity funds used during construction	(4,756		)	(5,395		)
Deferred income taxes	(2,044		)	(47,962		)
Change in mark-to-market valuations	1,985			(284		)
Changes in current assets and liabilities:
Customer and other receivables	52,416			61,973
Accrued unbilled revenues	20,511			9,633
Materials, supplies and fossil fuel	(13,753		)	21,421
Other current assets	(4,261		)	248
Accounts payable	(39,812		)	(18,168		)
Accrued taxes	42,453			64,473
Other current liabilities	(53,449		)	(37,601		)
Change in margin and collateral accounts — assets	(1,853		)	4,220
Change in margin and collateral accounts — liabilities	(32,950		)	35,478
Change in other long-term assets	(21,656		)	(32,129		)
Change in other long-term liabilities	27,557			63,296
Net cash flow provided by operating activities	114,753			254,557
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(240,973		)	(191,596		)
Contributions in aid of construction	13,871			9,136
Allowance for borrowed funds used during construction	(3,151		)	(3,576		)
Proceeds from nuclear decommissioning trust sales	92,047			189,318
Investment in nuclear decommissioning trust	(96,360		)	(194,241		)
Other	(533		)	(1,879		)
Net cash flow used for investing activities	(235,099		)	(192,838		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	319,081			—
Short-term borrowings — net	216,600			—
Repayment of long-term debt	(375,727		)	(170		)
Dividends paid on common stock	(57,400		)	(57,100		)
Net cash flow provided by (used for) financing activities	102,554			(57,270		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(17,792		)	4,449
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	19,873			99,937
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,081		$	104,386
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	—		$	—
Interest, net of amounts capitalized	$	61,701		$	53,636

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

43

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	—

44

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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(4,105		)	7,767		3,662			(12,081		)	5,470		(6,611		)
OCI (loss)	(15,755		)	—		(15,755		)	10,358			—		10,358
Total comprehensive income (loss)	(19,860		)	7,767		(12,093		)	(1,723		)	5,470		3,747
Dividends on common stock	(57,400		)	—		(57,400		)	(57,100		)	—		(57,100		)
Other	1			—		1			1			—		1
Ending balance, March 31	$	3,865,748		$	116,166	$	3,981,914		$	3,766,131		$	96,554	$	3,862,685

S-2.         Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	107		$	130
Investment gains — net	—			1,150
Miscellaneous	403			698
Total other income	$	510		$	1,978
Other expense:
Non-operating costs (a)	$	(1,741	)	$	(1,899	)
Asset dispositions	(223		)	(728		)
Miscellaneous	(2,660		)	(965		)
Total other expense	$	(4,624	)	$	(3,592	)

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

45

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.

In addition, 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 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

46

authorized an accounting deferral of certain costs associated with the purchase until any such cost recovery proceeding concludes.  Closing is also conditioned on the negotiation and execution of a new coal supply contract on terms reasonably acceptable to APS, expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and other typical closing conditions.

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 applying for approval to purchase Units 4 and 5, APS also requested from the ACC recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3.  The proposed Settlement Agreement in APS’s current retail rate case allows for the case to remain open to allow APS to seek a rate adjustment to reflect the Four Corners transaction should the transaction close.

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 10% of APS’s retail energy sales by year-end 2015, which is 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 July 1, 2011, APS filed its annual RES implementation plan with the ACC, 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 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.

The following table summarizes APS’s renewable energy sources in operation and under development as of May 3, 2012, which include (i) a development agreement, dated March 27, 2012, for the construction of a 35 MW solar facility located in the Yuma Foothills region that is part of the AZ Sun Program, and (ii) a mutual agreement to terminate, effective as of March 31, 2012, the development of a 14 MW solar facility at Luke Air Force Base.  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	55	54
Purchased Power Agreements:
Solar	15	295
Wind	190	99
Geothermal	10
Biomass	14
Biogas	3	3
Total Purchased Power Agreements	232	397
Total Distributed Energy: Solar	154	125
Total Renewable Portfolio	441	576

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

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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.

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 requesting, among other things, an increase in retail rates to allow APS to continue to maintain and upgrade its electric systems for enhanced reliability, approval of recovery mechanisms, including a decoupling mechanism, and approval of other programs and mechanisms aimed at energy efficiency and renewable energy.  On January 6, 2012, APS and other parties to the retail rate case entered into a Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case.  The Settlement Agreement requires the approval of the ACC.  As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.  The proposed 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 current rate case, 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.  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.  At March 31, 2012, SunCor had total remaining assets of about $8 million, including $7 million of intercompany receivables, and no 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

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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 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 three-month period ended March 31, 2012 was 0.8% 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 1.6% for 2012 through 2014 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 three-month period ended March 31, 2012 decreased 0.9% compared with the comparable prior-year period, reflecting the effects of our energy efficiency programs, 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 2014, including the effects of APS’s energy efficiency programs, but excluding the effects of weather variations.  The failure of the Arizona economy to improve in the near future 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, our hedging program for managing such costs and PSA deferrals and the related amortization.

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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 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 next general retail rate case decision becomes effective.

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 proposed in the 2012 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 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.

Operating Results — Three-month period ended March 31, 2012 compared with three-month period ended March 31, 2011

Our consolidated net loss attributable to common shareholders for the three months ended March 31, 2012 was $8 million, compared with a net loss of $15 million for the comparable prior-year

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period.  The results reflect an increase of approximately $9 million for the regulated electricity segment primarily due to decreased operations and maintenance expenses, and lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011, partially offset by lower electricity usage per customer, the effects of milder weather on usage per customer and higher property taxes due to increased property tax rates.

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

	Three Months Ended March 31,
	2012			2011			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a) (b)	$	404		$	436		$	(32	)
Operations and maintenance (a) (b)	(211		)	(255		)	44
Depreciation and amortization	(100		)	(107		)	7
Taxes other than income taxes	(43		)	(38		)	(5		)
Other income (expenses), net	(3		)	—			(3		)
Interest charges, net of allowances for funds used during construction	(49		)	(52		)	3
Income taxes (Note 6)	4			6			(2		)
Less income related to noncontrolling interests (Note 7)	(8		)	(5		)	(3		)
Regulated electricity segment net loss	(6		)	(15		)	9
All other	(1		)	(1		)	—
Loss from Continuing Operations Attributable to Common Shareholders	(7		)	(16		)	9
Income (Loss) from Discontinued Operations Attributable to Common Shareholders	(1		)	1			(2		)
Net Loss Attributable to Common Shareholders	$	(8	)	$	(15	)	$	7

(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.

(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.

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Regulated electricity segment

This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.

Operating revenues less fuel and purchased power expenses  Regulated electricity segment operating revenues less fuel and purchased power expenses were $32 million lower for the three months ended March 31, 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)
Settlement in 2011 of certain prior-period transmission right-of-way revenues	$	(28	)	$	—		$	(28	)
Lower usage per customer	(9		)	(2		)	(7		)
Effects of weather on usage per customer	(11		)	(5		)	(6		)
Lower refund of PSA deferrals	7			6			1
Higher line extension revenues	4			—			4
Higher retail transmission charges	5			—			5
Miscellaneous items, net	4			5			(1		)
Total	$	(28	)	$	4		$	(32	)

Operations and maintenance  Operations and maintenance expenses decreased $44 million for the three months ended March 31, 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 $7 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 $4 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which were largely offset in operating revenues; and

·A decrease of $5 million due to other miscellaneous factors.

Depreciation and amortization  Depreciation and amortization expenses were $7 million lower for the three months ended March 31, 2012 compared with the prior-year period primarily due to the Palo Verde operating license extensions, partially offset by increased plant in service.

Taxes other than income taxes  Taxes other than income taxes increased $5 million for the three months ended March 31, 2012 compared with the prior-year period primarily because of higher property tax rates in the current period.

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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 March 31, 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 the 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.

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 $425-475 million of cash tax benefits for APS through accelerated depreciation.  It is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a majority of the benefit realized 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 three months ended March 31, 2012 and 2011 (dollars in millions):

Pinnacle West Consolidated

	Three Months Ended March 31,						Net
	2012			2011			Change
Net cash flow provided by operating activities	$	115		$	244		$	(129	)
Net cash flow used for investing activities	(235		)	(193		)	(42		)
Net cash flow provided by (used for) financing activities	107			(47		)	154
Net increase (decrease) in cash and cash equivalents	$	(13	)	$	4		$	(17	)

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Arizona Public Service Company

	Three Months Ended March 31,						Net
	2012			2011			Change
Net cash flow provided by operating activities	$	115		$	255		$	(140	)
Net cash flow used for investing activities	(235		)	(193		)	(42		)
Net cash flow provided by (used for) financing activities	102			(57		)	159
Net increase (decrease) in cash and cash equivalents	$	(18	)	$	5		$	(23	)

Operating Cash Flows

Three-month period ended March 31, 2012 compared with three-month period ended March 31, 2011.  Pinnacle West’s consolidated net cash provided by operating activities was $115 million in 2012, compared to $244 million in 2011, a decrease of $129 million in net cash provided.  The decrease is primarily due to a net $75 million change in collateral and margin posted as a result of changes in commodity prices partially offset by expiration of prior hedge contracts, and other changes in working capital.

Other.  Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries.  The requirements of the Employee Retirement Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan.  We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount.  The minimum required funding takes into consideration the value of plan assets and our pension obligation.  Under ERISA, the qualified pension plan was 89% funded as of January 1, 2011 and is estimated to be 85% 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.  The required minimum contribution to our pension plan is approximately $65 million in 2012, approximately $160 million in 2013 and approximately $175 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.

The $69 million income tax receivable on the Condensed Consolidated Balance Sheets primarily 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

Three-month period ended March 31, 2012 compared with three-month period ended March 31, 2011.  Pinnacle West’s consolidated net cash used for investing activities was $235 million in 2012, compared to $193 million in 2011, an increase of $42 million in net cash used.  The increase in net cash used for investing activities is primarily due to an increase of approximately $45 million in capital expenditures.

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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	$	75	$	80	$	85
Renewables	199		176		193
Environmental	19		74		133
Four Corners Units 4 and 5	294		—		—
Other Generation	135		158		182
Distribution	243		268		267
Transmission	120		184		229
Other (a)	37		43		52
Total APS	$	1,122	$	983	$	1,141

(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 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.

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Financing Cash Flows and Liquidity

Three-month period ended March 31, 2012 compared with three-month period ended March 31, 2011.  Pinnacle West’s consolidated net cash provided by financing activities was $107 million in 2012, compared to $47 million of net cash used in 2011, an increase of $154 million in net cash provided.  The increase in net cash provided by financing activities is primarily due to $217 million of short-term debt borrowings at APS in 2012, a portion of which was used to repay $56 million of long-term debt repayments, net of issuances of long-term debt (see below).

Significant Financing Activities.  On April 18, 2012, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on June 1, 2012, to shareholders of record on May 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, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011.

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 March 31, 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 March 31, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

At March 31, 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 March 31, 2012, APS had commercial paper borrowings of $217 million, and no borrowings or letters of credit outstanding under either of these credit facilities.

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

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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 March 31, 2012, the ratio was approximately 49% 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.

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 April 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.

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	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	Baa3	BBB	BBB-
Commercial paper	P-3	A-2	F3
Outlook	Stable	Positive	Stable
APS
Senior unsecured	Baa2	BBB	BBB
Secured lease obligation bonds	Baa2	BBB	BBB
Corporate credit rating	Baa2	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.

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 March 31, 2012.

Contractual Obligations

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

Year	2012		2013-2014		2015-2016		Thereafter		Total
Fuel and purchased power commitments	$	0.4	$	1.0	$	1.0	$	6.8	$	9.2
Renewable energy credits	0.1		—		0.1		0.5		0.7

See Note 2 for a discussion of long-term debt and liquidity matters.

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

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“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 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 three months ended March 31, 2012 and 2011 (dollars in millions):

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	Three Months Ended March 31,
	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	(2		)	—
Decrease (increase) in regulatory asset	(14		)	—
Recognized in OCI:
Change in mark-to-market gains (losses) for future period deliveries (b)	(42		)	1
Mark-to-market losses realized during the period	15			15
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(265	)	$	(223	)

(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 March 31, 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.

Source of Fair Value	2012			2013			2014			2015			2016			Years thereafter			Total fair value
Prices provided by other external sources	$	(128	)	$	(56	)	$	(21	)	$	(2	)	$	—		$	—		$	(207	)
Prices based on models and other valuation methods	(10		)	(10		)	(10		)	(11		)	(7		)	(10		)	(58		)
Total by maturity	$	(138	)	$	(66	)	$	(31	)	$	(13	)	$	(7	)	$	(10	)	$	(265	)

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

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Mark-to-market changes	March 31, 2012 Gain (Loss)					December 31, 2011 Gain (Loss)
reported in:	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Earnings (a)
Electricity	$	1	$	(1	)	$	1	$	(1	)
Natural gas	1		(1		)	—		—
Regulatory asset (liability) or OCI (b)
Electricity	7		(7		)	5		(5		)
Natural gas	24		(24		)	27		(27		)
Total	$	33	$	(33	)	$	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.

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.

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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 March 31, 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 March 31, 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 March 31, 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 “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 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 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

The following table contains information about our purchases of our common stock during the first quarter of 2012.

Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 — January 31, 2012	—	—		—	—
February 1 — February 29, 2012	36,648	$	47.86	—	—
March 1 — March 31, 2012	—	—		—	—
Total	36,648	$	47.86	—	—

(a)  Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock.

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Item 5.                    OTHER INFORMATION

Environmental Matters

Climate Change

Regulatory Initiatives.  Pursuant to its authority under the Clean Air Act, on March 27, 2012, the EPA proposed NSPS for greenhouse gas emissions (“GHG”) from new electric generating units.  The EPA will accept comments on the proposed rule until June 12, 2012, after which time it is expected to finalize the rule.  APS does not expect the GHG NSPS for new units to have an impact on its current operations.  The EPA has indicated that this proposed rule will not apply to modified, reconstructed, or existing electric generating units.  It is unclear when, or if, the EPA will propose such standards, which could affect Four Corners, the Cholla Power Plant, and the Navajo Generating Station once promulgated.

EPA Environmental Regulation

Clean Air Act Lawsuit.  See “Clean Air Act Lawsuit” in Note 10 for a discussion of the Earthjustice lawsuit.

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 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 residue, would adversely affect several endangered species and their critical habitats.  APS was not a party to the lawsuit but monitored it to determine its potential impact on APS’s operations.  On March 14, 2012, the court entered an order dismissing the plaintiffs’ lawsuit.

Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry

On March 11, 2011, an earthquake measuring 9.0 on the Richter Scale occurred off the coast of Japan.  After the earthquake, the first of a series of seven tsunamis arrived at the Fukushima Daiichi Nuclear Power Station.  As a result, the Fukushima Daiichi station experienced considerable damage.

Following the earthquake and tsunamis, the NRC established a task force (the “Near-Term Task Force”) to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system.  On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the Near Term Task Force.  With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation.

The NRC will be issuing interim staff guidance regarding implementation of these requirements on each of August 31, 2012 and November 30, 2012.  Due to the emerging nature of these requirements, we cannot predict the financial or operational impacts on Palo Verde or APS.

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Item 6.                    EXHIBITS

(a)           Exhibits

Exhibit No.	Registrant(s)	Description
10.1	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.2	Pinnacle West	Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.3	Pinnacle West	Master Amendment to Performance Share Agreements
10.4	Pinnacle West	Master Amendment to Restricted Stock Unit Agreements
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

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Exhibit No.	Registrant(s)	Description
32.2*	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	Pinnacle West APS	XBRL Instance Document
101.SCH*	Pinnacle West APS	XBRL Taxonomy Extension Schema Document
101.CAL*	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document
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	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:	May 3, 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:	May 3, 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

PERFORMANCE SHARE AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of                      ,          (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and                                    (“Employee”).

BACKGROUND

A.The Board of Directors of the Company (the “Board of Directors”) has adopted, and the Company’s shareholders have approved, the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan (the “2007 Plan”), pursuant to which Performance Share Awards and Dividend Equivalent Awards may be granted to employees of the Company and its Subsidiaries.

B.The Board of Directors also has adopted the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “2012 Plan”), which also permits the award of Performance Shares and Dividend Equivalents.  The Company intends to submit the 2012 Plan to its shareholders for their approval at the Company’s 2012 Annual Meeting.

C.Subject to the approval of the Company’s shareholders, the Company hereby grants to Employee Performance Shares and Dividend Equivalents under the terms of the 2012 Plan.  If, and only if, the shareholders do not approve the 2012 Plan, the Company hereby grants to Employee Performance Shares and Dividend Equivalents under the terms of the 2007 Plan.  The plan pursuant to which this Award is made, as determined in accordance with the preceding provisions of this paragraph, will be referred to below as the “Plan.”

D.Pursuant to the Plan, the Company and Employee agree as follows:

AGREEMENT

1.Grant of Award.  Pursuant to action of the Committee, which was taken on the Date of Grant, the Company grants to Employee                         (        ) Performance Shares and Dividend Equivalents.  The Performance Shares granted under this Section 1 are referred to in this Award Agreement as the “Base Grant.”

2.Award Subject to Plan.  This Performance Share Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement.  In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.  If this Award is made pursuant to the 2007 Plan, as determined in accordance with paragraph C of the Background Section, above, this Agreement shall be subject to the terms of the Master Amendment to Performance Share Agreement to be entered into between Employee and the Company.

3.Performance Period.  The Performance Period for this Award begins January 1,         , and ends December 31,         .

4.Payment.

(a)Performance Shares Payable In Stock.  As soon as practicable in the fiscal year immediately following the end of the Performance Period, the Company will determine (i) the Company’s Total Shareholder Return (as defined herein) as compared to the Total Shareholder Return of the companies in the S&P 1500 Super Composite Electric Utility Index (the “Growth Index”) over the Performance Period and (ii) the Company’s Average Performance with respect to the Performance Metrics (as defined herein).  The Company then will deliver to Employee one (1) share of the Company’s Stock for each then-outstanding Performance Share under this Award Agreement, subject to adjustment pursuant to Section 5 below.  The Stock payout, if any, related to the Company’s Total

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Shareholder Return will be made on or before the March 15 immediately following the end of the Performance Period.  The Company anticipates that the Stock payout, if any, related to the Performance Metrics will be made on or about                      ,         , and in no event will such Stock payout be made later than December 31,         .

(b)Retirement.  In the case of Employee’s Retirement (as defined herein) during the Performance Period, Employee shall be deemed to have been employed by the Company through the end of the Performance Period and Employee will receive the Stock and Dividend Equivalents, if any, to which Employee is entitled at the time specified in this Section; provided, however, in the event Employee is terminated for Cause regardless of Employee’s Retirement or eligibility for Retirement, Employee shall not be deemed to have been employed through the end of the Performance Period and will forfeit the right to receive any Stock hereunder.  For purposes of this Award Agreement, (i) “Retirement” means a termination of employment which constitutes an “Early Retirement” or a “Normal Retirement” under the Pinnacle West Capital Corporation Retirement Plan, and (ii) “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its Subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the Chief Executive Officer of the Company reflects adversely on the business or reputation of the Company or any of its Subsidiaries or negatively affects any of the Company’s or any of its Subsidiaries’ employees or customers.

(c)Dividend Equivalents.  In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of Stock to Employee pursuant to Subsection 4(a) above, the Company also will deliver to Employee fully transferrable shares of stock equal in value to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Performance Shares relate from the Date of Grant to the date of the Stock payout, plus interest on such amount at the rate of      percent compounded quarterly, as determined pursuant to the Plan.  The number of shares of Stock distributed to Employee will be determined by dividing the amount due by the Fair Market Value of one share of Stock as of the date of the Stock payout.  No fractional Stock shall be issued.  If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

(d)Impact on Pension.  The value of the shares of Stock distributed upon payment for the Performance Shares and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.

5.Performance Criteria and Adjustments.  Fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(a) and fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(b).  In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Award Agreement greater than 2.0 times the Base Grant.

(a)Adjustment of Base Grant for Total Shareholder Return.  Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Total Shareholder Return” as compared to the Total Shareholder Return of the companies in the Growth Index during the Performance Period, as follows:

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If the Company’s Total Shareholder Return Over The Performance Period As Compared to the Total Shareholder Return of the Companies in the Growth Index is:	The Number of Performance Shares will be:
90th Percentile or greater	1.0 X Base Grant
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

If intermediate percentiles are achieved, the number of Performance Shares awarded will be prorated (partial shares will be rounded down to the nearest whole share when applicable).  For example, if the Company’s Total Shareholder Return during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to 0.60 (0.5 X 60/50) multiplied by the Base Grant.  In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection 5(a) greater than 1.0 times the Base Grant.

(b)Adjustment of Base Grant for Performance Metrics.  Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Average Performance” with respect to the “Performance Metrics,” as follows:

If the Company’s Average Performance is:	The Number of Performance Shares will be:
90th Percentile or greater	1.0 X Base Grant
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

If intermediate percentiles are achieved, the number of Performance Shares awarded pursuant to this Subsection 5(b) will be prorated (partial shares will be rounded down to the nearest whole share when applicable).  For example, if the Company’s Average Performance during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to .60 (0.5 X 60/50) multiplied by the Base Grant.  In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection (b) greater than 1.0 times the Base Grant.

6.Definitions.

(a)Performance Metrics.  The “Performance Metrics” for the Performance Period are: (i) the JD Power Residential National Large Segment Survey for investor-owned utilities; (ii) the System Average Interruption Frequency Index (Major Events Excluded) (“SAIFI”); (iii) Arizona Public Service Company’s customer to employee improvement ratio; (iv) the OSHA rate (All Incident Injury Rate); (v) nuclear capacity factor; and (vi) coal capacity factor.

(1)With respect to the Performance Metric described in clause (i) of this Subsection 6(a), the JD Power Residential National Large Segment Survey will provide data on an annual basis reflecting the Company’s percentile ranking, relative to other participating companies.

(2)With respect to the Performance Metric described in clause (ii) of this Subsection 6(a), the Edison Electric Institute (“EEI”) will provide data on an annual basis regarding the SAIFI result of the participating companies; the Company will

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calculate its SAIFI result for the year in question and determine its percentile ranking based on the information provided by EEI.

(3)With respect to the Performance Metric described in clause (iii) of this Subsection 6(a), SNL, an independent third party data system, will provide data on an annual basis regarding the customer and employee counts; the Company will use its customer and employee counts for the year in question and determine its percentile ranking based on the information provided by SNL.  Only those companies whose customers and employees were included in the data provided by SNL in each of the years of the Performance Period will be considered.

(4)With respect to the Performance Metric described in clause (iv) of this Subsection 6(a), EEI will provide data on an annual basis regarding the OSHA rate of the participating companies; the Company will calculate its OSHA rate for the year in question and determine its percentile ranking based on the information provided by EEI.

(5)With respect to the Performance Metric described in clause (v) of this Subsection 6(a), SNL will provide data on an annual basis regarding the nuclear capacity factors of the participating nuclear plants; the Company will calculate its nuclear capacity factor for the year in question and determine its percentile ranking based on the information provided by SNL.  Only those plants that were included in the data provided by SNL in each of the years of the Performance Period will be considered.

(6)With respect to the Performance Metric described in clause (vi) of this Subsection 6(a), SNL will provide data on an annual basis regarding the coal capacity factors of the participating coal plants; the Company will calculate its coal capacity factor for the year in question and determine its percentile ranking based on the information provided by SNL.  Only those plants that were included in the data provided by SNL in each of the years of the Performance Period will be considered.

(7)        The Company’s percentile ranking during the Performance Period for each Performance Metric will be the average of the Company’s percentile ranking for each Performance Metric during each of the three years of the Performance Period (each, an “Average Performance Metric”); provided, however, that if the third year of a Performance Metric is not calculable by December 15 of the following year, the Performance Metric shall consist of the three most recent years for which such Performance Metric is calculable.  The Company’s “Average Performance,” for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b) above will be the average of the Average Performance Metrics.  If only quartile, rather than percentile, rankings are available for a particular Performance Metric, the Average Performance Metric for any such Performance Metric shall be expressed as a percentile.  For example, if the Performance Metric was in the top quartile for two Performance Periods and in the lowest quartile in the other Performance Period, the average of these quartiles would be 3 (the average of 4, 4, and 1)  and the Average Performance Metric would be the 75th percentile (3 /4). The calculations in this Subsection 6(a)(7) will be verified by the Company’s internal auditors.

(8)If either EEI or SNL discontinues providing the data specified above, the Committee shall select a data source that, in the Committee’s judgment, will provide data most comparable to the data provided by EEI or SNL, as the case may be.  If the JD Power Residential National Large Segment Survey for investor-owned utilities (or a successor JD Power survey) is not available during each of the years of the Performance Period, the Performance Metric associated with the JD Power Residential Survey (Subsection 6(a)(1)) will be disregarded and not included in the Company’s Average Performance for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b).

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(b)Total Shareholder Return.  “Total Shareholder Return” for the Performance Period is the measure of a company’s stock price appreciation plus any dividends paid during the Performance Period.  Only those companies that were included in the Growth Index in each of the years of the Performance Period will be considered.  Total Shareholder Return for the Company and the companies in the Growth Index will be determined using the Daily Comparative Return as calculated by Bloomberg (or other independent third party data system).  If the Growth Index is discontinued, the Committee shall select the most comparable index then in use for the sector comparison.  In addition, if the sector comparison is no longer representative of the Company’s industry or business, the Committee shall replace the Growth Index with the most representative index then in use.  Once the Total Shareholder Returns of the Company and all relevant companies in the Growth Index have been determined, the member companies will be ranked from greatest to least.  Percentiles will be calculated (interpolated from 0% to 100%) based on a company’s relative ranking.  Percentiles will be carried out to one (1) decimal place.  If the Company is not in the Growth Index, then its percentile will be interpolated between the companies listed in the relative ranking.  These calculations will be verified by the Company’s internal auditors.

7.Termination of Award.  This Award Agreement will terminate and be of no further force or effect on the date that Employee is no longer employed by the Company or any of its Subsidiaries, whether due to voluntary or involuntary termination, death, retirement, disability, or otherwise, except as specifically set forth in Section 4.  Employee will, however, be entitled to receive any Stock and Dividend Equivalents payable under Section 4 of this Award Agreement if Employee’s employment terminates after the end of the Performance Period but before Employee’s receipt of such Stock and Dividend Equivalents.

8.Section 409A Compliance.  If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A.  If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception.  In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement other than the tax withholding election described in Section 9.

9.Tax Withholding.  Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award.  Employee shall pay any and all Taxes due in connection with a payout of Stock hereunder by check or by having the Company withhold shares of Stock from such payout.  Within 75 days after the Date of Grant, Employee must elect, on the election form attached hereto, how Employee will satisfy the tax obligations upon a payout.  In the absence of a timely election by Employee, Employee’s tax withholding obligation will be satisfied through the Company’s withholding of shares of Stock as set forth above.

10.Continued Employment.  Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its Subsidiaries to terminate Employee’s employment or services at any time.  In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its Subsidiaries.

11.Confidentiality.  During and after Employee’s Termination of employment, for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of

5

Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates.  Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.

Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership.  For purposes of this Section 11, the term “Confidential Information” shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.

12.Restrictive Covenants.

(a)Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability), Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is engaged in the business activity of supplying electric service in any area of Arizona for which the Company or its Affiliates is authorized to supply the same or similar service.

(b)Employee Non-Solicitation.  Employee agrees that for a period of 12 months following Employee’s termination of employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of Pinnacle West and its Affiliates with their employees.

(c)Remedies.  If Employee fails to comply with Sections 11, 12(a) or 12(b) in a material respect, the Company may (i) cause any of Employee’s unvested Performance Shares and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Performance Shares or Dividend Equivalents, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.

13.Non-Transferability.  Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.

14.Definitions:  Copy of Plan and Plan Prospectus.  To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan.  By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan Prospectus.

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15.Amendment.  Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee.  The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify as performance-based compensation within the meaning of Section 162(m) of the Code or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority.  Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan.

16.[Performance-Based Award.  This Award is intended to be a Performance-Based Award, if Employee is considered to be a Covered Employee for the tax year of the Company for which the Company claims a related tax deduction.]

IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.

PINNACLE WEST CAPITAL CORPORATION

By:

Its:

Date:

EMPLOYEE

By:

Date:

7

Pinnacle West Capital Corporation

PERFORMANCE SHARE AWARD
ELECTION FORM

(applies to Award Agreement dated     /    /    )

INFORMATION ABOUT YOU
Last	First	Middle Initial	Employee ID#
TAX WITHHOLDING ELECTION

I hereby elect to satisfy any tax withholding obligation associated with my receipt of Stock pursuant to my Performance Share Award in the following form (place an “X” in the “Check” column or in the “Stock” column):

Check (I will write a check for my taxes that are due and deliver it to the Company within one (1) day of the release of the Stock) o		Stock (The Company should withhold shares of my Stock to cover my taxes) o
To the extent permitted by law, I hereby elect Federal tax withholding of            percent (minimum may not be less than 25% and maximum may not exceed 35%)
PARTICIPANT NAME (PLEASE PRINT)
PARTICIPANT SIGNATURE	DATE

IMPORTANT NOTE: Please complete and return this Election Form to Jennifer Mellegers at Mail Station 9996 by            ,           .

8

EX-10.2

Exhibit 10.2

RESTRICTED STOCK UNIT AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of                          , 201     (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and                                          (“Employee”).

BACKGROUND

A.The Board of Directors of the Company (the “Board of Directors”) has adopted, and the shareholders of the Company have approved, the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan (the “2007 Plan”), pursuant to which Restricted Stock Units and Dividend Equivalents may be granted to employees of the Company and its Subsidiaries.

B.The Board of Directors also has adopted the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “2012 Plan”), which also authorizes the award of Restricted Stock Units and Dividend Equivalents.  The Company intends to submit the 2012 Plan to its shareholders for their approval at the Company’s 2012 Annual Meeting.

C.Subject to the approval of the Company’s shareholders, the Company hereby grants to Employee Restricted Stock Units and Dividend Equivalents under the terms of the 2012 Plan.  If, but only if, the shareholders do not approve the 2012 Plan, the Company hereby grants to Employee Restricted Stock Units and Dividend Equivalents under the terms of the 2007 Plan.  For purposes of the remaining provisions of this Agreement, the plan pursuant to which the Award evidenced by this Agreement is made, as determined in accordance with the preceding provisions of this paragraph, shall be referred to as the “Plan.”

D.Pursuant to the Plan, the Company and Employee agree as follows:

AGREEMENT

1.Grant of Award.  Pursuant to action of the Committee which was taken on the Date of Grant, the Company grants to Employee                        (x,xxx) Restricted Stock Units and Dividend Equivalents based on the dividends declared on the shares of Stock to which such Restricted Stock Units relate.

2.Award Subject to Plan.  This Restricted Stock Unit Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement.  In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.  If this Award is made pursuant to the 2007 Plan, as determined in accordance with paragraph C of the Background Section, above, this Agreement shall be subject to the terms of the Master Amendment to Restricted Stock Unit Agreements to be entered into between Employee and the Company.

3.Vesting of Restricted Stock Units.  The Restricted Stock Units granted pursuant to Section 1 will vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement on four  (4) “Vesting Dates” as follows:

(a)x,xxx Restricted Stock Units will vest on                      ,         ;

(b)x,xxx Restricted Stock Units will vest on                      ,         ;

(c)x,xxx Restricted Stock Units will vest on                      ,         ; and

(d)The remaining x,xxx Restricted Stock Units will vest on                      ,         .

In addition, the Restricted Stock Units will fully vest and (subject to Section 4(a)) no longer be subject to the restrictions of and forfeiture under this Award Agreement upon Employee’s Retirement; provided, however, all Restricted Stock Units and the related Dividend Equivalents not vested prior to the date of Employee’s Retirement (and that will vest solely as a result of this provision) will be forfeited and Employee shall not be entitled to receive any payment in connection therewith if Employee’s employment is terminated for Cause regardless of Employee’s Retirement or eligibility for Retirement.  For purposes of this Award Agreement, (i) “Retirement” means a termination of employment which constitutes an “Early Retirement” or a “Normal Retirement” under the Pinnacle West Capital Corporation Retirement Plan, and (ii) “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its Subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the Chief Executive Officer of the Company reflects adversely on the business or reputation of the Company or any of its Subsidiaries or negatively affects any of the Company’s or any of its Subsidiaries’ employees or customers.

4.Payment.

(a)Time and Form of Payment.  Subject to the provisions of this Award Agreement and the Plan, when a Restricted Stock Unit vests on one of the Vesting Dates set forth in clauses (a), (b), (c) or (d) of Section 3 above, Employee shall receive in exchange for each Restricted Stock Unit one unrestricted fully transferrable share of Stock.  Employee may elect, pursuant to Section 4(b), to receive payment for the Restricted Stock Units payable on any Vesting Date in the form of fully transferrable shares of Stock or 50% cash and 50% in unrestricted fully transferrable shares of Stock.  If a Restricted Stock Unit vests prior to the applicable Vesting Date due to Employee’s Retirement, the transfer or payment will be deferred until the applicable Vesting Date.  Any cash payment will be based on the Fair Market Value of one share of Stock determined as of the Vesting Date on which the Restricted Stock Unit vests.  The transfer or payment shall be made within 30 days of the applicable Vesting Date.

(b)Election of Form of Payment.  Within 45 days after the Date of Grant, Employee must elect to receive payment for Employee’s vested Restricted Stock Units and Dividend Equivalents in fully transferable shares of Stock or 50% in cash and 50% in fully transferrable shares of Stock by completing and returning to the Company the election form attached to this Agreement.  In the absence of a timely election by Employee, Employee will receive payment for the vested Restricted Stock Units and Dividend Equivalents in fully transferable shares of Stock.

(c)Dividend Equivalents.  In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of payment pursuant to Section 4(a), the Company also will deliver to Employee a payment equal to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Restricted Stock Units relate from the Date of Grant to the applicable Vesting Date, plus interest on such amount at the rate of      percent compounded quarterly.  Pursuant to the election filed by the Employee pursuant to Section 4(b), payment for the Dividend Equivalents and interest will be made in fully transferrable shares of Stock, or 50% in cash and 50% in fully transferrable shares of Stock.  The number of shares of Stock

2

distributed to Employee will be determined by dividing the amount of the Dividend Equivalents and interest by the Fair Market Value of one share of Stock as of the applicable Vesting Date. No fractional Stock shall be issued.  If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

(d)Impact on Pension Plans. The value of the shares of Stock distributed upon payment for the Restricted Stock Units and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.

5.Termination of Award.  Except as otherwise provided in Section 3 with respect to Employee’s Retirement, in the event of the termination of Employee’s employment with the Company or any of its Subsidiaries, whether due to voluntary or involuntary termination, death, disability or otherwise, Employee’s right to vest in any additional Restricted Stock Units or Dividend Equivalents under the Plan or this Award Agreement, if any, will terminate. Any unvested Restricted Stock Units and the related Dividend Equivalents will be forfeited effective as of the date that Employee terminates active employment with the Company or any of its Subsidiaries.

6.Section 409A Compliance.  If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A.  If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception.  In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement other than the election described in Section 4(b).

7.Tax Withholding.  Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award.  Employee shall pay any and all Taxes due prior to the payout of Stock or cash hereunder by check or other arrangement acceptable to the Company.  Employee shall pay any and all Taxes due in connection with a payout of Stock or cash hereunder by check or by having the Company withhold cash or shares of Stock from such payout.  Within 45 days after the Date of Grant, Employee must elect, on the election form described in Section 4(b), how Employee will satisfy the tax obligations upon a payout.  In the absence of a timely election by Employee, Employee’s tax withholding obligation upon a payout will be satisfied through the Company’s withholding of cash or shares of Stock as set forth above.

8.Continued Employment.  Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its Subsidiaries to terminate Employee’s employment or services at any time.  In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its Subsidiaries.

9.Confidentiality.  During and after Employee’s Termination of Employment, for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not;

3

provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates.  Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.

Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership.  For purposes of this Section 9, the term “Confidential Information” shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.

10.Restrictive Covenants.

(a)Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability), Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is engaged in the business activity of supplying electric service in any area of Arizona for which the Company or its Affiliates is authorized to supply the same or similar service

(b)Employee Non-Solicitation.  Employee agrees that for a period of 12 months following Employee’s termination of employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates , or otherwise interfere with the advantageous business relationship of the Company and its Affiliates with their employees.

(c)Remedies.  If Employee fails to comply with Sections 9, 10(a) or 10(b) in a material respect, the Company may (i) cause any of Employee’s unvested Restricted Stock Units and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Restricted Stock Units or Dividend Equivalents, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.

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11.Non-Transferability.  Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.

12.Definitions: Copy of Plan and Plan Prospectus.  To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan.  By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan Prospectus.

13.Amendment.  Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee.  The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify as performance-based compensation within the meaning of Section 162(m) of the Code or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority.  Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan.

IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.

PINNACLE WEST CAPITAL CORPORATION

By:

Its:

Date:

EMPLOYEE

By:

Date:

5

Pinnacle West Capital Corporation

RESTRICTED STOCK UNIT AWARD
ELECTION FORM

(applies to Award Agreement dated     /    /    )

INFORMATION ABOUT YOU
Last	First	Middle Initial	Employee ID#
1.  PAYMENT ELECTION

In accordance with the terms of the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan and pursuant to Section 4(b) of the Award Agreement, I hereby elect to receive payment for the Restricted Stock Units and Dividend Equivalents that vest on the dates set forth below in the following form (place an “X” in the “Stock” column or in the “50% Cash/50% Stock” column for each of the years and types of Awards set forth below):

	Restricted Stock Units and Dividend Equivalents
Vesting Date	Stock	50% Cash/ 50% Stock
/    /	o	o
/    /	o	o
/    /	o	o
/    /	o	o

2.  TAX WITHHOLDING ELECTION

I hereby elect to satisfy any tax withholding obligation associated with my receipt of Stock or Stock and cash in exchange for my Restricted Stock Units and Dividend Equivalents in the following form (place an “X” in the “Check” column or in the “Stock/Cash” column):

Check
(I will write a check for my taxes that are due and deliver it to the Company
within one (1) day of the release date of my Stock or cash payment)
o Withholding
(The Company should withhold
shares of my Stock or cash payment
to cover my taxes)
o

To the extent permitted by law, I hereby elect Federal tax withholding of            percent (minimum may not be less than 25% and maximum may not exceed 35%)
PARTICIPANT NAME (PLEASE PRINT)
PARTICIPANT SIGNATURE	DATE

IMPORTANT NOTE: Please complete and return this Election Form to Jennifer Mellegers at Mail Station 9996 by           ,           .

6

EX-10.3

Exhibit 10.3

MASTER AMENDMENT
TO
PERFORMANCE SHARE AGREEMENTS

This Master Amendment is entered into by and between Pinnacle West Capital Corporation (the “Company”) and                      (“Employee”) as of this      day of             , 2012 (the “Effective Date”).

BACKGROUND

A.Employee has previously received annual Awards of Performance Shares and Dividend Equivalents pursuant to the terms and provisions of the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan.

B.Each of the annual Awards is evidenced by a Performance Share Agreement (the “Award Agreement”).

C.Pursuant to the Award Agreements, the calculation and vesting of the Awards is not accelerated upon the occurrence of a Change of Control.

D.The Company’s Board of Directors has approved the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “2012 Plan”) that will be submitted to the Company’s shareholders for approval at the Company’s 2012 Annual Meeting. The 2012 Plan provides for the acceleration of the vesting and calculation of awards in certain circumstances following a Change of Control (as that term is defined in the 2012 Plan).

E.In order to conform, to the extent possible and advisable, the Change of Control provisions of the Award Agreements to the provisions of the 2012 Plan, by the execution of this Master Amendment, the Company and Employee agree to amend each of the outstanding Award Agreements as set forth below.

AMENDMENT

1.Section 4 of each of the Award Agreements is hereby amended by the addition of the following new Subsection 4(d) for all Awards other than the 2012 Award and new Subsection 4(e) for the 2012 Award:

Change of Control.  The calculation and vesting of the Performance Shares, but not the payment for the Performance Shares, may be accelerated upon the occurrence of a Change of Control to the extent provided in Addendum A.

2.Each of the Award Agreements is hereby amended by the addition of the attached Addendum A.

[SIGNATURES ON PAGE 2]

To signify their adoption of this Master Amendment, Employee and an authorized representative of the Company have signed this Master Amendment as of the Effective Date noted above.

PINNACLE WEST CAPITAL CORPORATION

By:

Its:

Date:

EMPLOYEE

(Name — Please Print)

(Signature)

(Date)

2

ADDENDUM A
TO
PERFORMANCE SHARE AGREEMENTS

Pursuant to the authority conferred upon the Committee under Section 12.8 of the Plan, the Committee has decided that upon the closing, or in anticipation of but contingent upon the closing, of a transaction that will result in a Change of Control, the following provisions shall become applicable.

1.Calculation and Vesting.

(a)Each Performance Share Award shall be converted to either (i) a Restricted Stock Unit Award or (ii) cash, at the election of the Employee.  The Employee’s election shall be made in accordance with such procedures as may be adopted by the Company.  Both the Restricted Stock Unit Award and the cash equivalent shall become vested on the closing of the transaction that results in the Change of Control.

(1)If the Employee elects to convert the Performance Share Award to a Restricted Stock Unit Award, the conversion will be accomplished in two steps.

In the first step, the Performance Share Award will be converted to a Restricted Stock Unit Award expressed in terms of Company Stock.  In this first step, the Employee shall receive the number of Restricted Stock Units equal to the number of shares of Stock that would have been earned at the target level of performance; provided, however, if, in the judgment of the Committee, the attained level of performance as of the last day of the month that is at least 30 days prior to the closing of the transaction that results in the Change of Control is reasonably ascertainable and such performance exceeds the target level of performance, the Employee shall receive the number of Restricted Stock Units equal to the number of shares of Stock that would have been earned at such attained level of performance rather than the target level of performance.  Whether the attained level of performance exceeds the target level will be determined on a goal-by-goal basis.  For example, if four equally weighted goals are established in connection with a particular Award, and the attained level of performance exceeds the target level for one of such goals, 25% of the Award will be earned at the attained level and the remaining 75% will be earned at the target level.

In the second step, the Restricted Stock Unit Award calculated in the first step shall be converted into an Award relating to the publicly traded stock of the surviving entity or its parent company.  The value of the shares of stock subject to the converted award shall equal the value of the consideration received in connection with the transaction that results in the Change of Control by a shareholder of the Company holding the same number of shares of Stock as the number of Restricted Stock Units calculated in the first step as described above.  If the only consideration

A-1

received by the shareholders of the Company in connection with the transaction that results in the Change of Control is the publicly traded common or preferred stock of the acquiring entity or its parent company, this requirement will be deemed to be satisfied if the number of shares of stock to which the converted Award relates is at least equal to the number of shares of Stock subject to the original Award multiplied or divided by the conversion ratio applicable to the transaction that results in the Change of Control.

(2)If the Employee elects to convert the Performance Share Award to cash, the Employee shall receive a cash payment equal to the Fair Market Value as of the date of closing of the specified number of shares of Stock equal to the number of shares of Stock that would have been earned at the target level of performance; provided, however, if, in the judgment of the Committee, the attained level of performance as of the last day of the month that is at least 30 days prior to the closing of the transaction that results in the Change of Control is reasonably ascertainable and such performance exceeds the target level of performance, the Employee shall receive a cash payment equal the Fair Market Value as of the date of closing of the specified number of shares of Stock equal to the number of shares of Stock that would have been earned at such attained level of performance rather than the target level of performance.  Whether the attained level of performance exceeds the target level will be determined on a goal-by-goal basis as further described in paragraph (a).

2.Payment.  Performance Share Awards shall be calculated and shall vest in accordance with the provisions of Section 1 of this Addendum A.  If the Company concludes, in the exercise of its discretion, that all or a portion of this Award is subject to Section 409A, the payment for the portion of the Award that is determined to be subject to Section 409A shall be made at the time specified in the Award Agreement.  If the Company concludes, in the exercise of its discretion, that all or a portion of the Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the payment for the portion of the Award that is determined not to be subject to Section 409A shall be made immediately prior to or coincident with the closing of the transaction that results in the Change of Control.  No interest will be payable.

3.Board Override.  Notwithstanding the foregoing provisions of this Addendum A, the Board, prior to a Change of Control, may determine that no Change of Control shall be deemed to have occurred or that some or all of the enhancements to the rights of Participants under all or a portion of the outstanding Awards upon a Change of Control, as provided in this Addendum A and the Award Agreement, shall not apply to specified Awards.  The Board may exercise such override authority only if, before or immediately upon the occurrence of the specified event that would otherwise constitute a Change of Control, the Board, as constituted prior to the Change of Control, reasonably concludes, in good faith, that: (i) Participants holding Awards affected by action of the Board under this Section 3 shall be protected by legally binding obligations of the Company or the surviving entity or the parent thereof because such Awards (A) shall remain outstanding following consummation of all transactions involved in or contemplated by such Change

A-2

of Control or (B) shall be assumed and adjusted by the surviving entity resulting from such transactions or the parent thereof, or (C) shall be exchanged for new awards issued by the surviving entity resulting from such transaction or the parent thereof; and (ii) changes in the terms of the Award resulting from such transactions will not materially impair the value of the Awards to the Participants or their opportunity for future appreciation in respect of such Awards.  The Board may exercise such override authority with respect to an Award which the Company concludes is subject to (and not excepted from) the requirements of Section 409A of the Code only in a manner and to the extent permissible under Section 409A.

4.Addendum Controls.  The provisions of this Addendum A shall control over any conflicting provisions of any Award Agreement in the event of a conflict.  The provisions of the Plan shall control in the event of any conflict between the provisions of the Plan and the provisions of this Addendum A.

A-3

EX-10.4

Exhibit 10.4

MASTER AMENDMENT
TO
RESTRICTED STOCK UNIT AGREEMENTS

This Master Amendment is entered into by and between Pinnacle West Capital Corporation (the “Company”) and                      (“Employee”) as of this      day of             , 2012 (the “Effective Date”).

BACKGROUND

A.Employee has previously received annual Awards of Restricted Stock Units and Dividend Equivalents pursuant to the terms and provisions of the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan.

B.Each of the annual Awards is evidenced by a Restricted Stock Unit Agreement (the “Award Agreement”) that provides, generally, for the vesting of the Awards over a period of four years.

C.[In 2011, Employee also received an additional Award of Restricted Stock Units and Dividend Equivalents.  This additional Award vests in three installments in 2013, 2014 and 2015 and is referred to below as the “2011 Supplemental Award.”  The 2011 Supplemental Award is evidenced by a separate Award Agreement which is referred to below as the “Supplemental Award Agreement.”]

D.Neither the Award Agreements nor the Supplemental Award Agreement currently provide that the vesting of the Restricted Stock Units is accelerated upon the occurrence of a Change of Control.

E.The Company’s Board of Directors has approved the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “2012 Plan”) that will be submitted to the Company’s shareholders for approval at the Company’s 2012 Annual Meeting. The 2012 Plan provides for the acceleration of the vesting of outstanding awards in certain circumstances following a Change of Control (as that term is defined in the 2012 Plan).

F.In order to conform, to the extent possible and advisable, the Change of Control provisions of the Award Agreements [and the Supplemental Award Agreement] to the provisions of the 2012 Plan, by the execution of this Master Amendment, the Company and Employee agree to amend each of the outstanding Award Agreements [and the Supplemental Award Agreement] as set forth below.

AMENDMENT

1.Section 3 of each of the Award Agreements [and Section 4(a) of the Supplemental Award Agreement] [is] [are] hereby amended by deleting the sentence that reads “For avoidance of doubt, no acceleration of the vesting of the Restricted Stock Units will occur on a Change of Control of the Company.”  Section 3 of each of the Award Agreements [and Section 4(a) of the Supplemental Award Agreement] also are hereby amended by adding the following language to the end thereof:

The Restricted Stock Units shall become fully vested and non-forfeitable upon the occurrence of a Change of Control to the extent provided in Addendum A.

2.Section 4(a) of the Award Agreement is hereby amended by the addition of the following language to the end thereof:

The payment for Restricted Stock Units may be accelerated in the event of a Change of Control, but only in accordance with the provisions of Addendum A and only if the Company, in the exercise of its discretion, concludes that such acceleration is permitted by Section 409A of the Code.

3.Section 6(a) of each Award Agreement [and Section 8(a) of the Supplemental Award Agreement] [is] [are] hereby amended by changing Section 6(a) to read as follows:

Purpose of this Provision.  If the Company concludes, in the exercise of its discretion, that this Award of Restricted Stock Units is subject to Section 409A, the provisions of this Section shall apply to such Award.  If the Company concludes, in the exercise of its discretion, that this Award of Restricted Stock Units is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the remaining provisions of this Section shall not apply to such Award.  This Award then shall be administered and interpreted, to the extent possible, to qualify for the short-term deferral exception to the requirements of Section 409A.

4.Each of the Award Agreements [and the Supplemental Award Agreement] [is] [are] hereby amended by the addition of the attached Addendum A.

[SIGNATURES ON PAGE 3]

2

To signify their adoption of this Master Amendment, Employee and an authorized representative of the Company have signed this Master Amendment as of the Effective Date noted above.

PINNACLE WEST CAPITAL CORPORATION

By:

Its:

Date:

EMPLOYEE

(Name — Please Print)

(Signature)

(Date)

3

ADDENDUM A
TO
RESTRICTED STOCK UNIT AGREEMENTS

Pursuant to the authority conferred upon the Committee by Section 12.8 of the Plan, the Committee has decided that upon the closing, or in anticipation of but contingent upon the closing, of a transaction that will result in a Change of Control, the following provisions shall become applicable.

1.Vesting.  Any restrictions on Restricted Stock Units shall lapse and such Restricted Stock Units shall become immediately vested and non-forfeitable.

2.Payment.

(a)Awards Exempt from the Requirements of Section 409A.  If the Company concludes, in the exercise of its discretion, that the Award is not subject to the requirements of Section 409A of the Code, all Restricted Stock Units subject to the Award shall become immediately payable and shall be paid in Stock or cash, in accordance with the terms of the applicable Award Agreement, immediately before the closing of the transaction that will result in the Change of Control.  All necessary steps shall be taken to allow any Stock issued in payment for the Restricted Stock Units to participate in the transaction that results in the Change of Control.  If pursuant to the terms of the Award Agreement, a Restricted Stock Unit is to be paid in cash, the Restricted Stock Unit will be settled in cash as of the closing of the transaction that results in the Change of Control.  The cash payment then will be made within 10 days following the closing of the transaction that results in the Change of Control.

(b)Awards Subject to Section 409A.  If the Company concludes, in the exercise of its discretion, that the Award is subject to the requirements of Section 409A, the Restricted Stock Unit Award will be converted into either (i) a Restricted Stock Unit Award relating to (and expressed in terms of) the publicly traded stock of the surviving entity or its parent company or (ii) cash, as elected by the employee in accordance with procedures adopted by the Company.  Payment for the Restricted Stock Units then will be made at the time or times otherwise specified in the Award Agreement.  Any election previously made by the Employee to receive payments in Stock or cash shall be disregarded.

(1)If the Employee elects to convert the Award into an Award relating to the publicly traded stock of the surviving entity or its parent company, the value of the shares of stock subject to the converted Award shall equal the value of the consideration received in connection with the transaction that results in the Change of Control by a shareholder of the Company holding the same number of shares of Stock that are subject to the Award.  If the only consideration received by the shareholders of the Company in connection with the transaction that results in the Change of Control is the publicly traded common or preferred stock of the acquiring entity or its

A-1

parent company, this requirement will be deemed to be satisfied if the number of shares of the stock to which the converted Award relates is at least equal to the number of shares of Stock subject to the original Award multiplied or divided by the conversion ratio applicable to the transaction that results in the Change of Control.

(2)If the Employee elects to convert the Awards into cash, the amount of cash payable will be equal to the value of the consideration received in connection with the transaction that results in the Change of Control by a shareholder of the Company holding the same number of shares of Stock that are subject to the Award. No interest will be payable.

(c)Determination by Company.  Within 180 days following the date on which this Addendum A becomes applicable to a particular Award, the Company will notify the Employee if the Company concludes that the requirements of Section 409A are not applicable to the Award.  In the absence of the issuance of a statement indicating that the Company, in the exercise of its discretion, has concluded that an Award is not subject to Section 409A, the provisions applicable to an Award that is subject to the requirements of Section 409A shall apply.

3.Board Override.  Notwithstanding the foregoing provisions of this Addendum A, the Board, prior to a Change of Control, may determine that no Change of Control shall be deemed to have occurred or that some or all of the enhancements to the rights of Participants under all or a portion of the outstanding Awards upon a Change of Control, as provided in this Addendum A and the Award Agreement, shall not apply to specified Awards.  The Board may exercise such override authority only if, before or immediately upon the occurrence of the specified event that would otherwise constitute a Change of Control, the Board, as constituted prior to the Change of Control, reasonably concludes, in good faith, that: (i) Participants holding Awards affected by action of the Board under this Section 3 shall be protected by legally binding obligations of the Company or the surviving entity or the parent thereof because such Awards (A) shall remain outstanding following consummation of all transactions involved in or contemplated by such Change of Control or (B) shall be assumed and adjusted by the surviving entity resulting from such transactions or the parent thereof, or (C) shall be exchanged for new awards issued by the surviving entity resulting from such transaction or the parent thereof; and (ii) changes in the terms of the Award resulting from such transactions will not materially impair the value of the Awards to the Participants or their opportunity for future appreciation in respect of such Awards.  The Board may exercise such override authority with respect to an Award which the Company concludes is subject to (and not excepted from) the requirements of Section 409A of the Code only in a manner and to the extent permissible under Section 409A.

4.Addendum Controls.  The provisions of this Addendum A shall control over any conflicting provisions of any Award Agreement [or the Supplemental Award Agreement] in the event of a conflict.  The provisions of the Plan shall control in the event of any conflict between the provisions of the Plan and the provisions of this Addendum A.

A-2

EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Three Months Ended March 31,			Twelve Months Ended December 31,
	2012			2011		2010		2009		2008		2007
Earnings:
Income (loss) from continuing operations attributable to common shareholders	$	(7,483	)	$	328,110	$	324,688	$	236,839	$	259,871	$	286,512
Income taxes	(4,645		)	183,604		160,869		138,551		95,231		144,673
Fixed charges	58,228			246,462		248,664		241,807		224,760		213,801
Total earnings	$	46,100		$	758,176	$	734,221	$	617,197	$	579,862	$	644,986
Fixed Charges:
Interest expense	$	56,967		$	241,995	$	244,174	$	237,766	$	220,223	$	209,624
Estimated interest portion of annual rents	1,261			4,467		4,490		4,041		4,537		4,177
Total fixed charges	$	58,228		$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Ratio of Earnings to Fixed Charges (rounded down)	0.79			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)

	Three Months Ended March 31,			Twelve Months Ended December 31,
	2012			2011		2010		2009		2008		2007
Earnings:
Income (loss) from continuing operations attributable to common shareholders	$	(4,105	)	$	336,249	$	335,663	$	251,225	$	262,344	$	283,940
Income taxes	(2,520		)	192,542		170,465		152,574		107,261		151,157
Fixed charges	57,005			238,286		234,184		227,274		206,896		195,144
Total earnings	$	50,380		$	767,077	$	740,312	$	631,073	$	576,501	$	630,241
Fixed Charges:
Interest charges	$	54,772		$	229,326	$	225,269	$	218,969	$	197,964	$	186,702
Amortization of debt discount	1,060			4,616		4,559		4,675		4,702		4,639
Estimated interest portion of annual rents	1,173			4,344		4,356		3,630		4,230		3,803
Total fixed charges	$	57,005		$	238,286	$	234,184	$	227,274	$	206,896	$	195,144
Ratio of Earnings to Fixed Charges (rounded down)	0.88			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)

	Three Months Ended March 31,			Twelve Months Ended December 31,
	2012			2011		2010		2009		2008		2007
Earnings:
Income (loss) from continuing operations attributable to common shareholders	$	(7,483	)	$	328,110	$	324,688	$	236,839	$	259,871	$	286,512
Income taxes	(4,645		)	183,604		160,869		138,551		95,231		144,673
Fixed charges	58,228			246,462		248,664		241,807		224,760		213,801
Total earnings	$	46,100		$	758,176	$	734,221	$	617,197	$	579,862	$	644,986
Fixed Charges:
Interest expense	$	56,967		$	241,995	$	244,174	$	237,766	$	220,223	$	209,624
Estimated interest portion of annual rents	1,261			4,467		4,490		4,041		4,537		4,177
Total fixed charges	$	58,228		$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Preferred Stock Dividend Requirements:
Income (loss) before income taxes attributable to common shareholders	$	(12,128	)	$	511,714	$	485,557	$	375,390	$	355,102	$	431,185
Net income (loss) from continuing operations attributable to common shareholders	(7,483		)	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	$	58,228		$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Preferred stock dividend requirements	—			—		—		—		—		—
Total	$	58,228		$	246,462	$	248,664	$	241,807	$	224,760	$	213,801
Ratio of Earnings to Fixed Charges (rounded down)	0.79			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:      May 3, 2012.

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

2

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:      May 3, 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:      May 3, 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:       May 3, 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 March 31, 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:      May 3, 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 March 31, 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:      May 3, 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 March 31, 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:      May 3, 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 March 31, 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:      May 3, 2012.

/s/ James R. Hatfield

James R. Hatfield

Senior Vice President and

Chief Financial Officer

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Long-Term Debt and Liquidity Matters (Details) (USD $)														3 Months Ended	1 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Pinnacle West	Dec. 31, 2011 Pinnacle West	Mar. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC	Mar. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC Minimum	Mar. 31, 2012 Long term debt ARIZONA PUBLIC SERVICE COMPANY loc	Mar. 31, 2012 Revolving credit facility maturing in 2015 ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 2012 Revolving credit facility maturing in 2016 Pinnacle West	Mar. 31, 2012 Revolving credit facility maturing in 2016 ARIZONA PUBLIC SERVICE COMPANY	May 01, 2012 Pollution Control Revenue Refunding Bonds ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 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	$ 3,443,000,000	$ 3,496,000,000	$ 125,000,000	$ 125,000,000	$ 3,318,000,000	$ 3,371,000,000
Interest rate (as a percent)														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									217,000,000
Maximum commercial paper support available under credit facility									250,000,000		200,000,000
Current maturities of long-term debt	101,708,000	477,435,000			101,708,000	477,435,000							32,000,000
Estimated fair value of long-term debt, including current maturities
Fair Value	3,871,000,000	3,926,000,000	123,000,000	123,000,000	3,748,000,000	3,803,000,000
Debt Provisions
Total shareholder equity	3,744,917,000	3,821,850,000			3,865,748,000	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
	Mar. 31, 2012	Mar. 31, 2011
Basic earnings per share:
Loss from continuing operations attributable to common shareholders (in dollars per share)	$ (0.07)	$ (0.15)
Income (loss) from discontinued operations (in dollars per share)	$ (0.01)	$ 0.01
Loss per share - basic (in dollars per share)	$ (0.08)	$ (0.14)
Diluted earnings per share:
Loss from continuing operations attributable to common shareholders (in dollars per share)	$ (0.07)	$ (0.15)
Income (loss) from discontinued operations (in dollars per share)	$ (0.01)	$ 0.01
Loss per share - diluted (in dollars per share)	$ (0.08)	$ (0.14)

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Derivative Accounting (Details 2) (Commodity Contracts, USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	$ (41,903,000)	$ 988,000
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized)	(14,500,000)	(14,847,000)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	85,000	12,000
Estimated net loss before income taxes to be reclassified from accumulated other comprehensive income	97,000,000
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	(25,378,000)	(7,519,000)
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	(326,000)	1,507,000
Not Designated as Hedging Instruments | Fuel and purchased power expense
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	$ (25,052,000)	$ (9,026,000)

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Other Income and Other Expense (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Other income:
Interest income	$ 605	$ 391
Investment gains - net		1,293
Miscellaneous	155	6
Total other income	760	1,690
Other expense:
Non-operating costs	(1,850)	(1,487)
Miscellaneous	(2,165)	(254)
Total other expense	(4,068)	(1,741)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	107	130
Investment gains - net		1,150
Miscellaneous	403	698
Total other income	510	1,978
Other expense:
Non-operating costs	(1,741)	(1,899)
Asset dispositions	(223)	(728)
Miscellaneous	(2,660)	(965)
Total other expense	$ (4,624)	$ (3,592)

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Discontinued Operations (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Discontinued Operations
Revenue		$ 12,000,000
Income (loss) before taxes	(1,000,000)	1,000,000
Income (loss) after taxes	(774,000)	703,000
SunCor
Discontinued Operations
Revenue		1,000,000
Assets	8,000,000
Inter-company receivables	7,000,000
Other assets	1,000,000
APSES
Discontinued Operations
Revenue		$ 11,000,000

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Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 7,776,000	$ 5,461,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	131,897,000		132,864,000
Current maturities of long-term debt	101,708,000		477,435,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	65,547,000		65,547,000
Equity-Noncontrolling interests	116,512,000		108,736,000
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts	3
Annual lease payments	49,000,000
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	7,767,000	5,470,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	131,897,000		132,864,000
Current maturities of long-term debt	101,708,000		477,435,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	65,547,000		65,547,000
Equity-Noncontrolling interests	116,166,000		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	5,000,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	132,000,000		133,000,000
Current maturities of long-term debt	31,000,000		31,000,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	66,000,000		66,000,000
Equity-Noncontrolling interests	116,000,000		108,000,000
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events	141,000,000
VIE debt to be assumed upon the occurrence of certain unlikely events	$ 97,000,000

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Other Income and Other Expense (Tables)

3 Months Ended

Mar. 31, 2012

Other Income and Other Expense

Detail of other income and other expense

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	605		$	391
Investment gains — net	—			1,293
Miscellaneous	155			6
Total other income	$	760		$	1,690
Other expense:
Non-operating costs	$	(1,850	)	$	(1,487	)
Investment losses — net	(53		)	—
Miscellaneous	(2,165		)	(254		)
Total other expense	$	(4,068	)	$	(1,741	)

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Fair Value Measurements (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 84,000	$ 74,000
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	79,000
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 5,000

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Long-Term Debt and Liquidity Matters (Tables)

3 Months Ended

Mar. 31, 2012

Long-Term Debt and Liquidity Matters

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

	As of March 31, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	123	$	125	$	123
APS	3,318		3,748		3,371		3,803
Total	$	3,443	$	3,871	$	3,496	$	3,926

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Changes in Equity (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Changes in equity
Balance at beginning of period	$ 3,930,586	$ 3,775,226
NET INCOME (LOSS)	(481)	(9,674)
OCI (loss)	(15,614)	10,446
COMPREHENSIVE INCOME (LOSS)	(16,095)	772
Issuance of capital stock	2,700	2,689
Purchase of treasury stock, net of reissuances	(1,754)	(3,530)
Other (primarily stock compensation)	3,350	10,723
Dividends on common stock	(57,358)	(57,109)
Balance at end of period	3,861,429	3,728,771
Common Shareholders
Changes in equity
Balance at beginning of period	3,821,850	3,683,327
NET INCOME (LOSS)	(8,257)	(15,135)
OCI (loss)	(15,614)	10,446
COMPREHENSIVE INCOME (LOSS)	(23,871)	(4,689)
Issuance of capital stock	2,700	2,689
Purchase of treasury stock, net of reissuances	(1,754)	(3,530)
Other (primarily stock compensation)	3,350	10,723
Dividends on common stock	(57,358)	(57,109)
Balance at end of period	3,744,917	3,631,411
Noncontrolling Interests
Changes in equity
Balance at beginning of period	108,736	91,899
NET INCOME (LOSS)	7,776	5,461
COMPREHENSIVE INCOME (LOSS)	7,776	5,461
Balance at end of period	$ 116,512	$ 97,360

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Regulatory Matters (Details 3) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Detail of regulatory liabilities
Regulatory liabilities, current	$ 90,000,000	$ 88,000,000
Regulatory liabilities, non-current	754,210,000	737,332,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	24,000,000	22,000,000
Regulatory liabilities, non-current	344,000,000	349,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, non-current	249,000,000	225,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	50,000,000	54,000,000
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, non-current	59,000,000	59,000,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	7,000,000	5,000,000
Regulatory liabilities, non-current	41,000,000	44,000,000
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,000,000	2,000,000
Regulatory liabilities, non-current	14,000,000	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	32,000,000	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)

3 Months Ended

Mar. 31, 2012

Nuclear Decommissioning Trust

Fair value of APS's nuclear decommissioning trust fund assets

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2012
Equity securities	$	196		$	64	$	—
Fixed income securities	347			21		(1		)
Net receivables (a)	(1		)	—		—
Total	$	542		$	85	$	(1	)

(a)           Net receivables 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 March 31,
	2012			2011
Realized gains	$	2		$	1
Realized losses	(1		)	(2		)
Proceeds from the sale of securities (a)	92			189

(a)           Proceeds are reinvested in the trust.

Fair value of fixed income securities, summarized by contractual maturities

	Fair Value
Less than one year	$	19
1 year - 5 years	85
5 years - 10 years	107
Greater than 10 years	136
Total	$	347

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Commitments and Contingencies (Details 2) (USD $)	3 Months Ended	1 Months Ended
	Mar. 31, 2012	Jan. 31, 2012 Lawsuit complaint	Sep. 30, 2011 Lawsuit complaint	Feb. 29, 2008 Climate Change Lawsuit company	Sep. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY minute kV MW customer	Mar. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Sep. 08, 2011 ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 2012 Fuel and purchased power commitments	Mar. 31, 2012 Renewable energy credits
Contractual Obligations
Contractual obligations increase	$ 270,000,000
2012								400,000,000	100,000,000
2013								400,000,000
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						44,000,000
Letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions						44,000,000
Outstanding letters of credit to support natural gas tolling contract obligations						$ 30,000,000

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Changes in Equity (APSC) (Tables)

3 Months Ended

Mar. 31, 2012

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

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(8,257		)	7,776		(481		)	(15,135		)	5,461		(9,674		)
OCI (loss)	(15,614		)	—		(15,614		)	10,446			—		10,446
Total comprehensive income (loss)	(23,871		)	7,776		(16,095		)	(4,689		)	5,461		772
Issuance of capital stock	2,700			—		2,700			2,689			—		2,689
Purchase of treasury stock, net of reissuances	(1,754		)	—		(1,754		)	(3,530		)	—		(3,530		)
Other (primarily stock compensation)	3,350			—		3,350			10,723			—		10,723
Dividends on common stock	(57,358		)	—		(57,358		)	(57,109		)	—		(57,109		)
Ending balance, March 31	$	3,744,917		$	116,512	$	3,861,429		$	3,631,411		$	97,360	$	3,728,771

ARIZONA PUBLIC SERVICE COMPANY

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

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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(4,105		)	7,767		3,662			(12,081		)	5,470		(6,611		)
OCI (loss)	(15,755		)	—		(15,755		)	10,358			—		10,358
Total comprehensive income (loss)	(19,860		)	7,767		(12,093		)	(1,723		)	5,470		3,747
Dividends on common stock	(57,400		)	—		(57,400		)	(57,100		)	—		(57,100		)
Other	1			—		1			1			—		1
Ending balance, March 31	$	3,865,748		$	116,166	$	3,981,914		$	3,766,131		$	96,554	$	3,862,685

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
NET INCOME (LOSS)	$ (481)	$ (9,674)
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $16,554 and $(390)	(25,352)	598
Reclassification of net realized loss, net of tax benefit of $5,728 and $5,865	8,772	8,982
Pension and other postretirement benefits activity, net of tax expense $536 and $509	966	866
Total other comprehensive income (loss)	(15,614)	10,446
COMPREHENSIVE INCOME (LOSS)	(16,095)	772
Less: Comprehensive income attributable to noncontrolling interests	7,776	5,461
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(23,871)	(4,689)
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME (LOSS)	3,662	(6,611)
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $16,554 and $(390)	(25,348)	598
Reclassification of net realized loss, net of tax benefit of $5,728 and $5,865	8,772	8,981
Pension and other postretirement benefits activity, net of tax expense $536 and $509	821	779
Total other comprehensive income (loss)	(15,755)	10,358
COMPREHENSIVE INCOME (LOSS)	(12,093)	3,747
Less: Comprehensive income attributable to noncontrolling interests	7,767	5,470
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (19,860)	$ (1,723)

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Derivative Accounting (Details)	3 Months Ended
	Mar. 31, 2012 GWh bcfs
Derivative Accounting
Maximum hedge period of majority of certain exposures (in months)	39
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	11,048
British thermal units equivalent to one MMBCF	146
ARIZONA PUBLIC SERVICE COMPANY
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	90.00%

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Long-Term Debt and Liquidity Matters

3 Months Ended

Mar. 31, 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 March 31, 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 March 31, 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.

At March 31, 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 March 31, 2012, APS had commercial paper borrowings of $217 million, and no borrowings or letters of credit outstanding under either of these credit facilities.

On May 1, 2012, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011.

See “Financial Assurances” in Note 10 for discussion of APS’s 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 March 31, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	123	$	125	$	123
APS	3,318		3,748		3,371		3,803
Total	$	3,443	$	3,871	$	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 March 31, 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 the 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.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net unrealized gains (loss), tax benefit (expense)	$ 16,551	$ (390)
Reclassification of net realized loss, tax benefit	5,728	5,865
Pension and other postretirement benefits activity, tax expense	631	566
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized gains (loss), tax benefit (expense)	16,554	(390)
Reclassification of net realized loss, tax benefit	5,728	5,865
Pension and other postretirement benefits activity, tax expense	$ 536	$ 509

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Retirement Plans and Other Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Defined Pension and Other Postretirement Benefit Costs
Amount of pension and other postretirement benefit costs deferred	$ 9	$ 3
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	16	16
Interest cost on benefit obligation	30	31
Expected return on plan assets	(35)	(33)
Amortization of net actuarial loss	11	6
Net periodic benefit cost	22	20
Portion of cost charged to expense	6	8
Contributions
Expected contributions in 2012	65
Expected contributions in 2013	160
Expected contributions in 2014	175
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period	7	6
Interest cost on benefit obligation	12	12
Expected return on plan assets	(11)	(10)
Amortization of net actuarial loss	6	3
Net periodic benefit cost	14	11
Portion of cost charged to expense	3	4
Contributions
Expected contributions in 2012	20
Expected contributions in 2013	20
Expected contributions in 2014	$ 20

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2012

Palo Verde Sale Leaseback Variable Interest Entities

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

	March 31, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	132	$	133
Current maturities of long-term debt	31		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	66		66
Equity — Noncontrolling interests	116		108

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Business Segments (Tables)

3 Months Ended

Mar. 31, 2012

Business Segments

Financial data by business segment

	Three Months Ended March 31,
	2012			2011
Operating revenues:
Regulated electricity segment	$	620		$	648
All other (a)	1			1
Total	$	621		$	649
Net loss attributable to common shareholders:
Regulated electricity segment	$	(6	)	$	(15	)
All other (a)	(2		)	—
Total	$	(8	)	$	(15	)

	As of March 31, 2012		As of December 31, 2011
Assets:
Regulated electricity segment	$	13,142	$	13,068
All other (a)	42		43
Total	$	13,184	$	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
	Mar. 31, 2012 M	Mar. 31, 2011	Dec. 31, 2011
Assets
Nuclear decommissioning trust	$ 541,989,000		$ 513,733,000
Risk management activities: commodity contracts	87,741,000		79,586,000
Total assets	84,000,000		74,000,000
Liabilities
Risk management activities: commodity contracts	(153,375,000)		(136,463,000)
Cash equivalents maximum maturity period (in months)	3
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs
Net risk management activities at beginning of period	(51,000,000)	(38,000,000)
Total net gains (losses) realized/unrealized:
Included in earnings	1,000,000	1,000,000
Included in OCI	(5,000,000)	2,000,000
Deferred as a regulatory asset or liability	(5,000,000)	(7,000,000)
Settlements	1,000,000
Transfers into Level 3 from Level 2	2,000,000	(5,000,000)
Transfers from Level 3 into Level 2	(1,000,000)	(1,000,000)
Net risk management activities at end of period	(58,000,000)	(48,000,000)
Net unrealized gains (losses) 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	76,000,000		69,000,000
Cash equivalents	12,000,000
Total assets	88,000,000		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	76,000,000		69,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Nuclear decommissioning trust	467,000,000		446,000,000
Risk management activities: commodity contracts	63,000,000		70,000,000
Total assets	530,000,000		516,000,000
Liabilities
Risk management activities: commodity contracts	(271,000,000)		(241,000,000)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Nuclear decommissioning trust	196,000,000		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		9,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	67,000,000		73,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	82,000,000		78,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Nuclear decommissioning trust	88,000,000		90,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Nuclear decommissioning trust	19,000,000		21,000,000
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Risk management activities: commodity contracts	84,000,000		74,000,000
Total assets	84,000,000		74,000,000
Liabilities
Risk management activities: commodity contracts	(142,000,000)		(125,000,000)
Fair value measurement on a recurring basis | Other
Assets
Nuclear decommissioning trust	(1,000,000)		(1,000,000)
Risk management activities: commodity contracts	(59,000,000)		(64,000,000)
Total assets	(60,000,000)		(65,000,000)
Liabilities
Risk management activities: commodity contracts	260,000,000		229,000,000
Fair value measurement on a recurring basis | Other | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	(1,000,000)		(1,000,000)
Fair value measurement on a recurring basis | Fair Value
Assets
Nuclear decommissioning trust	542,000,000		514,000,000
Cash equivalents	12,000,000
Risk management activities: commodity contracts	88,000,000		80,000,000
Total assets	642,000,000		594,000,000
Liabilities
Risk management activities: commodity contracts	(153,000,000)		(137,000,000)
Fair value measurement on a recurring basis | Fair Value | US commingled equity funds
Assets
Nuclear decommissioning trust	196,000,000		175,000,000
Fair value measurement on a recurring basis | Fair Value | U.S. Treasury
Assets
Nuclear decommissioning trust	76,000,000		69,000,000
Fair value measurement on a recurring basis | Fair Value | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	14,000,000		8,000,000
Fair value measurement on a recurring basis | Fair Value | Corporate debt
Assets
Nuclear decommissioning trust	67,000,000		73,000,000
Fair value measurement on a recurring basis | Fair Value | Mortgage-backed securities
Assets
Nuclear decommissioning trust	82,000,000		78,000,000
Fair value measurement on a recurring basis | Fair Value | Municipality bonds
Assets
Nuclear decommissioning trust	88,000,000		90,000,000
Fair value measurement on a recurring basis | Fair Value | Other
Assets
Nuclear decommissioning trust	$ 19,000,000		$ 21,000,000

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Business Segments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Financial data by business segment
Operating revenues	$ 620,631	$ 648,847
Net income (loss) attributable to common shareholders	(8,257)	(15,135)
Assets	13,183,914		13,111,018
Regulated electricity segment
Financial data by business segment
Operating revenues	620,000	648,000
Net income (loss) attributable to common shareholders	(6,000)	(15,000)
Assets	13,142,000		13,068,000
All other
Financial data by business segment
Operating revenues	1,000	1,000
Net income (loss) attributable to common shareholders	(2,000)
Assets	$ 42,000		$ 43,000

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Derivative Accounting (Tables)

3 Months Ended

Mar. 31, 2012

Derivative Accounting

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

Commodity	Quantity
Power	11,048	gigawatt hours
Gas	146	Bcfs (a)

(a)“Bcf” is Billion Cubic Feet.

Gains and losses from derivative instruments in designated accounting hedges relationships

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2012			2011
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive income (loss) — derivative instruments	$	(41,903	)	$	988
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized)	Fuel and purchased power	(14,500		)	(14,847		)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)	Fuel and purchased power	85			12

(a)During the three months ended March 31, 2012 and 2011, we had no amounts 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

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues	$	(326	)	$	1,507
Net Loss Recognized in Income from Derivative Instruments	Fuel and purchased power expense	(25,052		)	(9,026		)
Total		$	(25,378	)	$	(7,519	)

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

Amounts are as of March 31, 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 (a)			Other (b)			Total
Current Assets	$	6,466		$	80,364		$	3,486	$	—		$	(55,699	)	$	34,617
Investments and Other Assets	3,377			57,639			—		—			(7,892		)	53,124
Total Assets	9,843			138,003			$	3,486	$	—		(63,591		)	87,741
Current Liabilities	(103,592		)	(131,751		)	100,228		(11,145		)	57,053			(89,207		)
Deferred Credits and Other	(80,252		)	(97,503		)	105,718		—			7,869			(64,168		)
Total Liabilities	(183,844		)	(229,254		)	205,946		(11,145		)	64,922			(153,375		)
Total	$	(174,001	)	$	(91,251	)	$	209,432	$	(11,145	)	$	1,331		$	(65,634	)

(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 (a)			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		)	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

	March 31, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	380
Cash Collateral Posted	180
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	169

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

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Changes in Equity (Tables)

3 Months Ended

Mar. 31, 2012

Changes in Equity

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

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(8,257		)	7,776		(481		)	(15,135		)	5,461		(9,674		)
OCI (loss)	(15,614		)	—		(15,614		)	10,446			—		10,446
Total comprehensive income (loss)	(23,871		)	7,776		(16,095		)	(4,689		)	5,461		772
Issuance of capital stock	2,700			—		2,700			2,689			—		2,689
Purchase of treasury stock, net of reissuances	(1,754		)	—		(1,754		)	(3,530		)	—		(3,530		)
Other (primarily stock compensation)	3,350			—		3,350			10,723			—		10,723
Dividends on common stock	(57,358		)	—		(57,358		)	(57,109		)	—		(57,109		)
Ending balance, March 31	$	3,744,917		$	116,512	$	3,861,429		$	3,631,411		$	97,360	$	3,728,771

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Consolidation and Nature of Operations

3 Months Ended

Mar. 31, 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, SunCor Development Company (“SunCor”), El Dorado Investment Company (“El Dorado”) and formerly 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 in accordance with accounting requirements for reporting discontinued operations (see Note 13) and to conform to current year presentation, and on our 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 March 31, 2011	As previously reported			Reclassifications for discontinued operations and to conform to current year presentation			Amount reported after reclassification for discontinued operations and to conform to current year presentation
Operating Revenues
Regulated electricity segment revenues	$	647,974		$	(647,974	)	$	—
Other revenues	11,601			(11,601		)	—
Operating revenues	—			648,847			648,847
Operating Expenses
Operations and maintenance	256,486			(1,457		)	255,029
Depreciation and amortization	106,601			(18		)	106,583
Other expenses	9,716			(7,896		)	1,820
Other
Other expense	(1,699		)	(42		)	(1,741		)
Income Taxes	(5,649		)	(356		)	(6,005		)
Income From Continuing Operations	(9,325		)	(1,043		)	(10,368		)
Income From Discontinued Operations	(349		)	1,043			694

Statement of Cash Flows for the Three Months Ended March 31, 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		$	—
Gains and other changes in real estate assets	(3		)	3			—
Change in other long-term assets	(33,129		)	(40		)	(33,169		)
Change in other long-term liabilities	35,421			(3		)	35,418

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Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies

Schedule of updated contractual obligations

Year	2012		2013		2014		2015		2016		Thereafter		Total
Fuel and purchased power commitments	$	0.4	$	0.4	$	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 $)	3 Months Ended				1 Months Ended						3 Months Ended	1 Months Ended	12 Months Ended			1 Months Ended			1 Months Ended	3 Months Ended		1 Months Ended				1 Months Ended		6 Months Ended		1 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 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	Feb. 28, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 DSMAC Cost Recovery Mechanisms	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 DSMAC Cost Recovery Mechanisms	Feb. 17, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 DSMAC Cost Recovery Mechanisms	Jun. 02, 2010 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 DSMAC Cost Recovery Mechanisms	Jun. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Apr. 30, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Jun. 02, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2012 DSMAC Cost Recovery Mechanisms	Feb. 28, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms USDPerkWh	Mar. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms	Mar. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC Power Supply Adjustor (PSA) Cost Recovery Mechanisms	Jan. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission	Jun. 30, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission	Jan. 06, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission	Jun. 02, 2011 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Filing with the Arizona Corporation Commission	Jan. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY ACC 2011 General retail rate case Current	Dec. 31, 2009 ARIZONA PUBLIC SERVICE COMPANY ACC 2008 General retail rate case	Jun. 30, 2010 ARIZONA PUBLIC SERVICE COMPANY ACC 2008 General retail rate case	Dec. 30, 2009 ARIZONA PUBLIC SERVICE COMPANY ACC 2008 General retail rate case party	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%
Non-fuel base rate increase																							194,100,000
Reclassification of revenues to base rates																							44,900,000
Base rate decrease																							143,500,000
Rate base																							5,700,000,000
Proposed capital structure and costs of capital
Percentage of long-term debt in capital structure																									46.10%
Percentage of common stock equity in capital structure																									53.90%
Cost of capital, long-term debt (as a percent)																									6.38%
Cost of capital, common stock equity (as a percent)																									11.00%
Weighted-average cost of capital (as a percent)																									8.87%
Proposed base fuel rate (in dollars per kWh)																							0.03242
Current base fuel rate (in dollars per kWh)																							0.03757			0.03757
Current sharing provision of fuel and purchased power costs																							90/10
Settlement Agreement
Net change in base rates																						0
Non-fuel base rate increase																						116,300,000
Fuel-related base rate decrease																						153,100,000
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%					11.00%
Percentage of debt in capital structure																								46.10%					46.20%
Percentage of common equity in capital structure																								53.90%					53.80%
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																						90/10
Approved Order
Number of other parties to the settlement agreement																													21
Net retail rate increase																											207,500,000
Base rate increase																											344,700,000
Reclassification of fuel and purchased power revenues from the then-existing PSA to base rates																											137,200,000
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					79,000,000
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
Period covered by cost recovery program (in years)											2
Period over which program costs will be amortized (in years)											3
Percentage of energy savings for prior year																		1.75%
Percentage of annual energy savings to meet energy efficiency goal for 2011															1.25%			1.50%
Amount of approved budget														80,000,000
Costs already being recovered in general rates												10,000,000				10,000,000
Demand-side management adjustor charge (DSMAC)												75,000,000					72,000,000
Increase in annual wholesale transmission rates																														44,000,000
Revenue increase related to transmission services used for APS's retail customers																														38,000,000
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	46,754,000	49,947,000	46,754,000	49,947,000																(47,000,000)	(50,000,000)
Amounts refunded through revenues	(24,514,000)	(31,238,000)	(24,514,000)	(31,238,000)																24,000,000	31,000,000
Ending balance																				$ (5,000,000)	$ (77,000,000)
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
	Mar. 31, 2012	Mar. 31, 2011
Other income:
Interest income	$ 605	$ 391
Investment gains - net		1,293
Miscellaneous	155	6
Total other income	760	1,690
Other expense:
Non-operating costs	(1,850)	(1,487)
Investment losses - net	(53)
Miscellaneous	(2,165)	(254)
Total other expense	$ (4,068)	$ (1,741)

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
OPERATING REVENUES	$ 620,631	$ 648,847
OPERATING EXPENSES
Fuel and purchased power	216,309	212,007
Operations and maintenance	210,663	255,029
Depreciation and amortization	100,109	106,583
Taxes other than income taxes	42,475	37,624
Other expenses	3,068	1,820
Total	572,624	613,063
OPERATING INCOME	48,007	35,784
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	4,756	5,395
Other income (Note 11)	760	1,690
Other expense (Note 11)	(4,068)	(1,741)
Total	1,448	5,344
INTEREST EXPENSE
Interest charges	56,967	61,077
Allowance for borrowed funds used during construction	(3,151)	(3,576)
Total	53,816	57,501
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(4,361)	(16,373)
INCOME TAXES	(4,645)	(6,005)
INCOME (LOSS) FROM CONTINUING OPERATIONS	284	(10,368)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(505) and $330 (Note 13)	(765)	694
NET INCOME (LOSS)	(481)	(9,674)
Less: Net income attributable to noncontrolling interests (Note 7)	7,776	5,461
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(8,257)	(15,135)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	109,299	108,832
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	109,299	108,832
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Loss from continuing operations attributable to common shareholders - basic (in dollars per share)	$ (0.07)	$ (0.15)
Net loss attributable to common shareholders - basic (in dollars per share)	$ (0.08)	$ (0.14)
Loss from continuing operations attributable to common shareholders - diluted (in dollars per share)	$ (0.07)	$ (0.15)
Net loss attributable to common shareholders - diluted (in dollars per share)	$ (0.08)	$ (0.14)
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 0.525	$ 0.525
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Loss from continuing operations, net of tax	(7,483)	(15,838)
Discontinued operations, net of tax	(774)	703
Net loss attributable to common shareholders	$ (8,257)	$ (15,135)

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Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended			3 Months Ended
	Feb. 28, 2011 Y	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY M	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Income tax receivables		$ 69,069	$ 68,633	$ 69,464	$ 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	Mar. 31, 2012	Dec. 31, 2011
CURRENT ASSETS
Cash and cash equivalents	$ 20,710	$ 33,583
Customer and other receivables	238,387	284,183
Accrued unbilled revenues	104,728	125,239
Allowance for doubtful accounts	(2,886)	(3,748)
Materials and supplies (at average cost)	213,290	204,387
Fossil fuel (at average cost)	26,850	22,000
Deferred income taxes	141,224	130,571
Income tax receivable (Note 6)	8,894	6,466
Assets from risk management activities (Note 8)	34,617	30,264
Deferred fuel and purchased power regulatory asset (Note 3)	5,310	27,549
Other regulatory assets (Note 3)	81,457	69,072
Other current assets	32,219	26,904
Total current assets	904,800	956,470
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)	53,124	49,322
Nuclear decommissioning trust (Note 15)	541,989	513,733
Other assets	64,415	64,588
Total investments and other assets	659,528	627,643
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	13,928,709	13,753,971
Accumulated depreciation and amortization	(4,775,904)	(4,709,991)
Net	9,152,805	9,043,980
Construction work in progress	462,425	496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	131,897	132,864
Intangible assets, net of accumulated amortization	170,198	170,571
Nuclear fuel, net of accumulated amortization	141,882	118,098
Total property, plant and equipment	10,059,207	9,962,258
DEFERRED DEBITS
Regulatory assets (Note 3)	1,344,523	1,352,079
Income tax receivable (Note 6)	69,069	68,633
Other	146,787	143,935
Total deferred debits	1,560,379	1,564,647
TOTAL ASSETS	13,183,914	13,111,018
CURRENT LIABILITIES
Accounts payable	265,975	326,987
Accrued taxes (Note 6)	160,136	120,289
Accrued interest	44,736	54,872
Short-term borrowings	216,600
Current maturities of long-term debt	101,708	477,435
Customer deposits	74,297	72,176
Liabilities from risk management activities (Note 8)	89,207	53,968
Regulatory liabilities (Note 3)	89,622	88,362
Other current liabilities	115,618	148,616
Total current liabilities	1,157,899	1,342,705
LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities	3,275,651	2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	65,547	65,547
Total long-term debt less current maturities	3,341,198	3,019,054
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,918,995	1,925,388
Regulatory liabilities (Note 3)	754,210	737,332
Liability for asset retirements	284,839	279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,277,227	1,268,910
Liabilities from risk management activities (Note 8)	64,168	82,495
Customer advances	113,514	116,805
Coal mine reclamation	118,113	117,896
Unrecognized tax benefits (Note 6)	72,622	72,270
Other	219,700	217,934
Total deferred credits and other	4,823,388	4,818,673
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 9)
Common stock, no par value	2,450,296	2,444,247
Treasury stock	(6,471)	(4,717)
Total common stock	2,443,825	2,439,530
Retained earnings	1,468,869	1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(64,481)	(65,447)
Derivative instruments	(103,296)	(86,716)
Total accumulated other comprehensive loss	(167,777)	(152,163)
Total shareholders' equity	3,744,917	3,821,850
Noncontrolling interests (Note 7)	116,512	108,736
Total equity	3,861,429	3,930,586
TOTAL LIABILITIES AND EQUITY	$ 13,183,914	$ 13,111,018

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Nuclear Decommissioning Trust (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Nuclear decommissioning trust fund assets
Fair Value	$ 541,989,000		$ 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	92,047,000	189,318,000
Fair value of fixed income securities, summarized by contractual maturities
Total	541,989,000		513,733,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	541,989,000		513,733,000
Unrealized Gains	85,000,000		67,000,000
Unrealized Losses	(1,000,000)		(2,000,000)
Net receivables from securities sales	(1,000,000)
Net payables for securities purchases			(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	1,000,000
Realized losses	(1,000,000)	(2,000,000)
Proceeds from the sale of securities	92,047,000	189,318,000
Fair value of fixed income securities, summarized by contractual maturities
Total	541,989,000		513,733,000
ARIZONA PUBLIC SERVICE COMPANY | Equity securities
Nuclear decommissioning trust fund assets
Fair Value	196,000,000		175,000,000
Unrealized Gains	64,000,000		44,000,000
Unrealized Losses			(1,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Total	196,000,000		175,000,000
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	347,000,000		340,000,000
Unrealized Gains	21,000,000		23,000,000
Unrealized Losses	(1,000,000)		(1,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	19,000,000
1 year - 5 years	85,000,000
5 years - 10 years	107,000,000
Greater than 10 years	136,000,000
Total	$ 347,000,000		$ 340,000,000

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Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2012

Discontinued Operations

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

	Three Months Ended March 31,
	2012			2011
Revenue:
SunCor	$	—		$	1
APSES	—			11
Total revenue	$	—		$	12
Income (loss) before taxes:	$	(1	)	$	1
Income (loss) after taxes:	$	(1	)	$	1

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Changes in Equity (APSC)

3 Months Ended

Mar. 31, 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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(8,257		)	7,776		(481		)	(15,135		)	5,461		(9,674		)
OCI (loss)	(15,614		)	—		(15,614		)	10,446			—		10,446
Total comprehensive income (loss)	(23,871		)	7,776		(16,095		)	(4,689		)	5,461		772
Issuance of capital stock	2,700			—		2,700			2,689			—		2,689
Purchase of treasury stock, net of reissuances	(1,754		)	—		(1,754		)	(3,530		)	—		(3,530		)
Other (primarily stock compensation)	3,350			—		3,350			10,723			—		10,723
Dividends on common stock	(57,358		)	—		(57,358		)	(57,109		)	—		(57,109		)
Ending balance, March 31	$	3,744,917		$	116,512	$	3,861,429		$	3,631,411		$	97,360	$	3,728,771

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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(4,105		)	7,767		3,662			(12,081		)	5,470		(6,611		)
OCI (loss)	(15,755		)	—		(15,755		)	10,358			—		10,358
Total comprehensive income (loss)	(19,860		)	7,767		(12,093		)	(1,723		)	5,470		3,747
Dividends on common stock	(57,400		)	—		(57,400		)	(57,100		)	—		(57,100		)
Other	1			—		1			1			—		1
Ending balance, March 31	$	3,865,748		$	116,166	$	3,981,914		$	3,766,131		$	96,554	$	3,862,685

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Nuclear Decommissioning Trust

3 Months Ended

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2012
Equity securities	$	196		$	64	$	—
Fixed income securities	347			21		(1		)
Net receivables (a)	(1		)	—		—
Total	$	542		$	85	$	(1	)

(a)           Net receivables 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 March 31,
	2012			2011
Realized gains	$	2		$	1
Realized losses	(1		)	(2		)
Proceeds from the sale of securities (a)	92			189

(a)           Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2012 is as follows (dollars in millions):

	Fair Value
Less than one year	$	19
1 year - 5 years	85
5 years - 10 years	107
Greater than 10 years	136
Total	$	347

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2012 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at March 31, 2012
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	196		$	—		$	—		$	196
Fixed income securities:
U.S. Treasury	76		—			—			—			76
Cash and cash equivalent funds	—		15			—			(1		)(c)	14
Corporate debt	—		67			—			—			67
Mortgage-backed securities	—		82			—			—			82
Municipality bonds	—		88			—			—			88
Other	—		19			—			—			19
Subtotal nuclear decommissioning trust	76		467			—			(1		)	542
Cash Equivalents	12		—			—			—			12
Risk management activities — derivative instruments:
Commodity contracts	—		63			84			(59		)(b)	88
Total	$	88	$	530		$	84		$	(60	)	$	642
Liabilities:
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(271	)	$	(142	)	$	260	(b)	$	(153	)

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

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

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

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		)(c)	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		)(b)	80
Total	$	69	$	516		$	74		$	(65	)	$	594
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(b)	$	(137	)

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

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

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

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

	March 31, 2012 Fair Value (millions)
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range
Electricity:
Forward Contracts	$	79	$	106	Discounted cash flows	Electricity prices	$7.13 - $67.50 per MWh
Option Contracts	—		35		Option Model	Electricity prices	$21.15 - $94.23 per MWh
						Natural gas prices	$1.90 - $4.31 per mmbtu
						Electricity volatilities	14% - 83%
						Natural gas volatilities	17% - 50%
Natural Gas:
Forward Contracts	5		1		Discounted cash flows	Natural gas prices	$1.85 - $4.20 per mmbtu
Total	$	84	$	142

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 March 31,
Commodity Contracts	2012			2011
Net risk management activities balance at beginning of period	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	1			1
Included in OCI	(5		)	2
Deferred as a regulatory asset or liability	(5		)	(7		)
Settlements	1			—
Transfers into Level 3 from Level 2	2			(5		)
Transfers from Level 3 into Level 2	(1		)	(1		)
Net risk management activities at end of period	$	(58	)	$	(48	)
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)

3 Months Ended

Mar. 31, 2012

Consolidation and Nature of Operations

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

Statement of Income for the Three Months Ended March 31, 2011	As previously reported			Reclassifications for discontinued operations and to conform to current year presentation			Amount reported after reclassification for discontinued operations and to conform to current year presentation
Operating Revenues
Regulated electricity segment revenues	$	647,974		$	(647,974	)	$	—
Other revenues	11,601			(11,601		)	—
Operating revenues	—			648,847			648,847
Operating Expenses
Operations and maintenance	256,486			(1,457		)	255,029
Depreciation and amortization	106,601			(18		)	106,583
Other expenses	9,716			(7,896		)	1,820
Other
Other expense	(1,699		)	(42		)	(1,741		)
Income Taxes	(5,649		)	(356		)	(6,005		)
Income From Continuing Operations	(9,325		)	(1,043		)	(10,368		)
Income From Discontinued Operations	(349		)	1,043			694

Statement of Cash Flows for the Three Months Ended March 31, 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		$	—
Gains and other changes in real estate assets	(3		)	3			—
Change in other long-term assets	(33,129		)	(40		)	(33,169		)
Change in other long-term liabilities	35,421			(3		)	35,418

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Other Income and Other Expense (APSC) (Tables)

3 Months Ended

Mar. 31, 2012

Detail of other income and other expense

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	605		$	391
Investment gains — net	—			1,293
Miscellaneous	155			6
Total other income	$	760		$	1,690
Other expense:
Non-operating costs	$	(1,850	)	$	(1,487	)
Investment losses — net	(53		)	—
Miscellaneous	(2,165		)	(254		)
Total other expense	$	(4,068	)	$	(1,741	)

ARIZONA PUBLIC SERVICE COMPANY

Detail of 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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	107		$	130
Investment gains — net	—			1,150
Miscellaneous	403			698
Total other income	$	510		$	1,978
Other expense:
Non-operating costs (a)	$	(1,741	)	$	(1,899	)
Asset dispositions	(223		)	(728		)
Miscellaneous	(2,660		)	(965		)
Total other expense	$	(4,624	)	$	(3,592	)

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME (LOSS)	$ (481)	$ (9,674)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	118,487	123,298
Deferred fuel and purchased power	46,754	49,947
Deferred fuel and purchased power amortization	(24,514)	(31,238)
Allowance for equity funds used during construction	(4,756)	(5,395)
Deferred income taxes	(1,989)	(41,005)
Change in mark-to-market valuations	1,985	(284)
Changes in current assets and liabilities:
Customer and other receivables	52,264	75,528
Accrued unbilled revenues	20,511	9,633
Materials, supplies and fossil fuel	(13,753)	21,421
Other current assets	(3,502)	(636)
Accounts payable	(39,355)	(24,543)
Accrued taxes and income tax receivable - net	37,398	52,944
Other current liabilities	(39,804)	(37,406)
Change in unrecognized tax benefits		18,959
Change in margin and collateral accounts - assets	(1,853)	4,220
Change in margin and collateral accounts - liabilities	(32,950)	35,478
Change in other long-term assets	(21,469)	(33,169)
Change in other long-term liabilities	22,362	35,418
Net cash flow provided by operating activities	115,335	243,496
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(240,973)	(191,553)
Contributions in aid of construction	13,871	9,136
Allowance for borrowed funds used during construction	(3,151)	(3,576)
Proceeds from nuclear decommissioning trust sales	92,047	189,318
Investment in nuclear decommissioning trust	(96,360)	(194,241)
Other	(533)	(1,879)
Net cash flow used for investing activities	(235,099)	(192,795)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	319,081	175,000
Repayment of long-term debt	(375,727)	(175,170)
Short-term borrowings and payments - net	216,600	700
Dividends paid on common stock	(55,595)	(55,300)
Common stock equity issuance	4,289	11,727
Other	(1,757)	(3,653)
Net cash flow provided by (used for) financing activities	106,891	(46,696)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(12,873)	4,005
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	33,583	110,188
CASH AND CASH EQUIVALENTS AT END OF PERIOD	20,710	114,193
Cash paid during the period for:
Income taxes, net of (refunds)	(650)
Interest, net of amounts capitalized	$ 62,892	$ 55,997

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Income tax expense (benefit) on discontinued operations	$ (505)	$ 330

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Commitments and Contingencies

3 Months Ended

Mar. 31, 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 2012 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 March 31, 2012, APS had a regulatory liability of $48 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 March 31, 2012, certain contractual obligations have increased approximately $0.3 billion from December 31, 2011 as discussed in the 2011 Form 10-K.  The updated contractual obligations are as follows (dollars in billions):

Year	2012		2013		2014		2015		2016		Thereafter		Total
Fuel and purchased power commitments	$	0.4	$	0.4	$	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.

This hearing has been held in abeyance to provide an opportunity for the parties to engage in settlement negotiations.  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.  In addition, the Western Electricity Coordinating Council (“WECC”) initiated a Detailed Disturbance Analysis process to identify and understand the cause of the events that occurred, and identify and ensure timely implementation of corrective actions.

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 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 the 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 other 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.  APS and Pinnacle West filed a motion to dismiss that was granted by the Court on March 20, 2012.  The case was stayed as to SDG&E until the earlier of six months or the release of a FERC or California Public Utilities Commission (“CPUC”) report on the outage.  The Court stated that the plaintiffs may refile a complaint against APS and Pinnacle West on certain grounds following the release of either report.

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 with the court.  Earthjustice’s responses to these motions are due May 16, 2012.  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 March 31, 2012, approximately $44 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.  These letters of credit 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 March 31, 2012.  Additionally, APS has issued letters of credit to support collateral obligations under certain natural gas tolling contracts entered into with third parties.  At March 31, 2012, $30 million of such letters of credit were outstanding.  These letters of credit will expire in 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.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 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	Mar. 31, 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		109,477,427
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1

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Other Income and Other Expense

3 Months Ended

Mar. 31, 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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	605		$	391
Investment gains — net	—			1,293
Miscellaneous	155			6
Total other income	$	760		$	1,690
Other expense:
Non-operating costs	$	(1,850	)	$	(1,487	)
Investment losses — net	(53		)	—
Miscellaneous	(2,165		)	(254		)
Total other expense	$	(4,068	)	$	(1,741	)

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
NET INCOME (LOSS)	$ (481)	$ (9,674)
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $16,551 and $(390)	(25,352)	598
Reclassification of net realized loss, net of tax benefit of $5,728 and $5,865	8,772	8,982
Pension and other postretirement benefits activity, net of tax expense of $631 and $566	966	866
Total other comprehensive income (loss)	(15,614)	10,446
COMPREHENSIVE INCOME (LOSS)	(16,095)	772
Less: Comprehensive income attributable to noncontrolling interests	7,776	5,461
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (23,871)	$ (4,689)

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Business Segments

3 Months Ended

Mar. 31, 2012

Business Segments

Business Segments

5.Business Segments

Pinnacle West’s 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 months ended March 31, 2012 and 2011 and at March 31, 2012 and December 31, 2011 is provided as follows (dollars in millions):

	Three Months Ended March 31,
	2012			2011
Operating revenues:
Regulated electricity segment	$	620		$	648
All other (a)	1			1
Total	$	621		$	649
Net loss attributable to common shareholders:
Regulated electricity segment	$	(6	)	$	(15	)
All other (a)	(2		)	—
Total	$	(8	)	$	(15	)

	As of March 31, 2012		As of December 31, 2011
Assets:
Regulated electricity segment	$	13,142	$	13,068
All other (a)	42		43
Total	$	13,184	$	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

3 Months Ended

Mar. 31, 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 $9 million for the three months ended March 31, 2012 and $3 million for the three months ended March 31, 2011.  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 March 31,						Three Months Ended March 31,
	2012			2011			2012			2011
Service cost - benefits earned during the period	$	16		$	16		$	7		$	6
Interest cost on benefit obligation	30			31			12			12
Expected return on plan assets	(35		)	(33		)	(11		)	(10		)
Amortization of net actuarial loss	11			6			6			3
Net periodic benefit cost	$	22		$	20		$	14		$	11
Portion of cost charged to expense	$	6		$	8		$	3		$	4

Contributions

The required minimum contribution to our pension plan is approximately $65 million in 2012, approximately $160 million in 2013 and approximately $175 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

3 Months Ended

Mar. 31, 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

3 Months Ended

Mar. 31, 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 months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012			2011
Basic earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.07	)	$	(0.15	)
Income (loss) from discontinued operations	(0.01		)	0.01
Loss per share — basic	$	(0.08	)	$	(0.14	)
Diluted earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.07	)	$	(0.15	)
Income (loss) from discontinued operations	(0.01		)	0.01
Loss per share — diluted	$	(0.08	)	$	(0.14	)

For the three months ended March 31, 2012 and 2011, the weighted average common shares outstanding were the same for both basic and diluted shares.

For the three months ended March 31, 2012 and 2011, options to purchase shares of common stock were outstanding but excluded from the computation of diluted earnings per share because of their antidilutive effect.  This is a result of the net loss position in both periods.

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Derivative Accounting

3 Months Ended

Mar. 31, 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 are 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, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 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 purchase 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 other comprehensive income (“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 of March 31, 2012, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

For its regulated operations, APS defers 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.  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 March 31, 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	11,048	gigawatt hours
Gas	146	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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2012			2011
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive income (loss) — derivative instruments	$	(41,903	)	$	988
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized)	Fuel and purchased power	(14,500		)	(14,847		)
Gain Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)	Fuel and purchased power	85			12

(a)During the three months ended March 31, 2012 and 2011, we had no amounts 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 $97 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, certain of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2012 and 2011 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues	$	(326	)	$	1,507
Net Loss Recognized in Income from Derivative Instruments	Fuel and purchased power expense	(25,052		)	(9,026		)
Total		$	(25,378	)	$	(7,519	)

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 contractual net settlement provisions 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 March 31, 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 (a)			Other (b)			Total
Current Assets	$	6,466		$	80,364		$	3,486	$	—		$	(55,699	)	$	34,617
Investments and Other Assets	3,377			57,639			—		—			(7,892		)	53,124
Total Assets	9,843			138,003			$	3,486	$	—		(63,591		)	87,741
Current Liabilities	(103,592		)	(131,751		)	100,228		(11,145		)	57,053			(89,207		)
Deferred Credits and Other	(80,252		)	(97,503		)	105,718		—			7,869			(64,168		)
Total Liabilities	(183,844		)	(229,254		)	205,946		(11,145		)	64,922			(153,375		)
Total	$	(174,001	)	$	(91,251	)	$	209,432	$	(11,145	)	$	1,331		$	(65,634	)

(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 (a)			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		)	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 $88 million of risk management assets as of March 31, 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 March 31, 2012 (dollars in millions):

	March 31, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	380
Cash Collateral Posted	180
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	169

(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the footnote 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
	Mar. 31, 2012	Mar. 31, 2011
OPERATING EXPENSES
Fuel and purchased power	$ 216,309	$ 212,007
Operations and maintenance	210,663	255,029
Depreciation and amortization	100,109	106,583
Taxes other than income taxes	42,475	37,624
Total	572,624	613,063
OPERATING INCOME	48,007	35,784
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	4,756	5,395
Other income (Note S-2)	760	1,690
Other expense (Note S-2)	(4,068)	(1,741)
Total	1,448	5,344
INTEREST EXPENSE
Allowance for borrowed funds used during construction	(3,151)	(3,576)
Total	53,816	57,501
NET INCOME (LOSS)	(481)	(9,674)
Less: Net income attributable to noncontrolling interests (Note 7)	7,776	5,461
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(8,257)	(15,135)
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	620,248	647,994
OPERATING EXPENSES
Fuel and purchased power	216,309	212,007
Operations and maintenance	208,447	252,607
Depreciation and amortization	100,085	106,559
Income taxes	(814)	(6,003)
Taxes other than income taxes	42,226	37,250
Total	566,253	602,420
OPERATING INCOME	53,995	45,574
OTHER INCOME (DEDUCTIONS)
Income taxes	1,706	(1,340)
Allowance for equity funds used during construction	4,756	5,395
Other income (Note S-2)	510	1,978
Other expense (Note S-2)	(4,624)	(3,592)
Total	2,348	2,441
INTEREST EXPENSE
Interest on long-term debt	52,737	54,737
Interest on short-term borrowings	2,035	2,308
Debt discount, premium and expense	1,060	1,157
Allowance for borrowed funds used during construction	(3,151)	(3,576)
Total	52,681	54,626
NET INCOME (LOSS)	3,662	(6,611)
Less: Net income attributable to noncontrolling interests (Note 7)	7,767	5,470
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (4,105)	$ (12,081)

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Income Taxes

3 Months Ended

Mar. 31, 2012

Income Taxes

Income Taxes

6.Income Taxes

The $69 million income tax receivable on the Condensed Consolidated Balance Sheets primarily 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 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 March 31, 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

3 Months Ended

Mar. 31, 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 may give APS the ability to utilize the asset for a significant portion of the asset’s economic life.  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 months ended March 31, 2012 of $8 million and for the three months ended March 31, 2011 of $5 million, 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 March 31, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

	March 31, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	132	$	133
Current maturities of long-term debt	31		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	66		66
Equity — Noncontrolling interests	116		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 March 31, 2012, APS would have been required to pay the noncontrolling equity participants approximately $141 million and assume $97 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

3 Months Ended

Mar. 31, 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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31, 2012								Three Months Ended March 31, 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 (loss)	(8,257		)	7,776		(481		)	(15,135		)	5,461		(9,674		)
OCI (loss)	(15,614		)	—		(15,614		)	10,446			—		10,446
Total comprehensive income (loss)	(23,871		)	7,776		(16,095		)	(4,689		)	5,461		772
Issuance of capital stock	2,700			—		2,700			2,689			—		2,689
Purchase of treasury stock, net of reissuances	(1,754		)	—		(1,754		)	(3,530		)	—		(3,530		)
Other (primarily stock compensation)	3,350			—		3,350			10,723			—		10,723
Dividends on common stock	(57,358		)	—		(57,358		)	(57,109		)	—		(57,109		)
Ending balance, March 31	$	3,744,917		$	116,512	$	3,861,429		$	3,631,411		$	97,360	$	3,728,771

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME (LOSS)	$ (481)	$ (9,674)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	118,487	123,298
Deferred fuel and purchased power	46,754	49,947
Deferred fuel and purchased power amortization	(24,514)	(31,238)
Allowance for equity funds used during construction	(4,756)	(5,395)
Deferred income taxes	(1,989)	(41,005)
Change in mark-to-market valuations	1,985	(284)
Changes in current assets and liabilities:
Customer and other receivables	52,264	75,528
Accrued unbilled revenues	20,511	9,633
Materials, supplies and fossil fuel	(13,753)	21,421
Other current assets	(3,502)	(636)
Accounts payable	(39,355)	(24,543)
Accrued taxes	37,398	52,944
Other current liabilities	(39,804)	(37,406)
Change in margin and collateral accounts - assets	(1,853)	4,220
Change in margin and collateral accounts - liabilities	(32,950)	35,478
Change in other long-term assets	(21,469)	(33,169)
Change in other long-term liabilities	22,362	35,418
Change in unrecognized tax benefits		18,959
Net cash flow provided by operating activities	115,335	243,496
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(240,973)	(191,553)
Contributions in aid of construction	13,871	9,136
Allowance for borrowed funds used during construction	(3,151)	(3,576)
Proceeds from nuclear decommissioning trust sales	92,047	189,318
Investment in nuclear decommissioning trust	(96,360)	(194,241)
Other	(533)	(1,879)
Net cash flow used for investing activities	(235,099)	(192,795)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	319,081	175,000
Short-term borrowings - net	216,600	700
Repayment of long-term debt	(375,727)	(175,170)
Dividends paid on common stock	(55,595)	(55,300)
Net cash flow provided by (used for) financing activities	106,891	(46,696)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(12,873)	4,005
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	33,583	110,188
CASH AND CASH EQUIVALENTS AT END OF PERIOD	20,710	114,193
Cash paid during the period for:
Income taxes, net of (refunds)	(650)
Interest, net of amounts capitalized	62,892	55,997
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME (LOSS)	3,662	(6,611)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	118,463	123,256
Deferred fuel and purchased power	46,754	49,947
Deferred fuel and purchased power amortization	(24,514)	(31,238)
Allowance for equity funds used during construction	(4,756)	(5,395)
Deferred income taxes	(2,044)	(47,962)
Change in mark-to-market valuations	1,985	(284)
Changes in current assets and liabilities:
Customer and other receivables	52,416	61,973
Accrued unbilled revenues	20,511	9,633
Materials, supplies and fossil fuel	(13,753)	21,421
Other current assets	(4,261)	248
Accounts payable	(39,812)	(18,168)
Accrued taxes	42,453	64,473
Other current liabilities	(53,449)	(37,601)
Change in margin and collateral accounts - assets	(1,853)	4,220
Change in margin and collateral accounts - liabilities	(32,950)	35,478
Change in other long-term assets	(21,656)	(32,129)
Change in other long-term liabilities	27,557	63,296
Net cash flow provided by operating activities	114,753	254,557
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(240,973)	(191,596)
Contributions in aid of construction	13,871	9,136
Allowance for borrowed funds used during construction	(3,151)	(3,576)
Proceeds from nuclear decommissioning trust sales	92,047	189,318
Investment in nuclear decommissioning trust	(96,360)	(194,241)
Other	(533)	(1,879)
Net cash flow used for investing activities	(235,099)	(192,838)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	319,081
Short-term borrowings - net	216,600
Repayment of long-term debt	(375,727)	(170)
Dividends paid on common stock	(57,400)	(57,100)
Net cash flow provided by (used for) financing activities	102,554	(57,270)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(17,792)	4,449
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	19,873	99,937
CASH AND CASH EQUIVALENTS AT END OF PERIOD	2,081	104,386
Cash paid during the period for:
Income taxes, net of (refunds)	0
Interest, net of amounts capitalized	$ 61,701	$ 53,636

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Other Income and Other Expense (APSC)

3 Months Ended

Mar. 31, 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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	605		$	391
Investment gains — net	—			1,293
Miscellaneous	155			6
Total other income	$	760		$	1,690
Other expense:
Non-operating costs	$	(1,850	)	$	(1,487	)
Investment losses — net	(53		)	—
Miscellaneous	(2,165		)	(254		)
Total other expense	$	(4,068	)	$	(1,741	)

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 months ended March 31, 2012 and 2011 (dollars in thousands):

	Three Months Ended March 31,
	2012			2011
Other income:
Interest income	$	107		$	130
Investment gains — net	—			1,150
Miscellaneous	403			698
Total other income	$	510		$	1,978
Other expense:
Non-operating costs (a)	$	(1,741	)	$	(1,899	)
Asset dispositions	(223		)	(728		)
Miscellaneous	(2,660		)	(965		)
Total other expense	$	(4,624	)	$	(3,592	)

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (APSC) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$ 13,928,709	$ 13,753,971
Accumulated depreciation and amortization	(4,775,904)	(4,709,991)
Net	9,152,805	9,043,980
Construction work in progress	462,425	496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	131,897	132,864
Intangible assets, net of accumulated amortization	170,198	170,571
Nuclear fuel, net of accumulated amortization	141,882	118,098
Total property, plant and equipment	10,059,207	9,962,258
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)	541,989	513,733
Assets from risk management activities (Note 8)	53,124	49,322
Other assets	64,415	64,588
Total investments and other assets	659,528	627,643
CURRENT ASSETS
Cash and cash equivalents	20,710	33,583
Customer and other receivables	238,387	284,183
Accrued unbilled revenues	104,728	125,239
Allowance for doubtful accounts	(2,886)	(3,748)
Materials and supplies (at average cost)	213,290	204,387
Fossil fuel (at average cost)	26,850	22,000
Deferred fuel and purchased power regulatory asset (Note 3)	5,310	27,549
Other regulatory assets (Note 3)	81,457	69,072
Deferred income taxes	141,224	130,571
Income tax receivable	8,894	6,466
Assets from risk management activities (Note 8)	34,617	30,264
Other current assets	32,219	26,904
Total current assets	904,800	956,470
DEFERRED DEBITS
Regulatory assets (Note 3)	1,344,523	1,352,079
Income tax receivable (Note 6)	69,069	68,633
Other	146,787	143,935
Total deferred debits	1,560,379	1,564,647
TOTAL ASSETS	13,183,914	13,111,018
CAPITALIZATION
Common stock	2,443,825	2,439,530
Retained earnings	1,468,869	1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(64,481)	(65,447)
Derivative instruments	(103,296)	(86,716)
Total shareholder equity	3,744,917	3,821,850
Noncontrolling interests (Note 7)	116,512	108,736
Total equity	3,861,429	3,930,586
Long-term debt less current maturities	3,275,651	2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	65,547	65,547
CURRENT LIABILITIES
Current maturities of long-term debt	101,708	477,435
Accounts payable	265,975	326,987
Accrued taxes (Note 6)	160,136	120,289
Accrued interest	44,736	54,872
Customer deposits	74,297	72,176
Liabilities from risk management activities (Note 8)	89,207	53,968
Regulatory liabilities (Note 3)	89,622	88,362
Other current liabilities	115,618	148,616
Total current liabilities	1,157,899	1,342,705
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,918,995	1,925,388
Regulatory liabilities (Note 3)	754,210	737,332
Liability for asset retirements	284,839	279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,277,227	1,268,910
Liabilities from risk management activities (Note 8)	64,168	82,495
Customer advances	113,514	116,805
Coal mine reclamation	118,113	117,896
Unrecognized tax benefits (Note 6)	72,622	72,270
Other	219,700	217,934
Total deferred credits and other	4,823,388	4,818,673
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	13,183,914	13,111,018
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	13,924,843	13,750,105
Accumulated depreciation and amortization	(4,772,352)	(4,706,462)
Net	9,152,491	9,043,643
Construction work in progress	462,425	496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	131,897	132,864
Intangible assets, net of accumulated amortization	170,043	170,416
Nuclear fuel, net of accumulated amortization	141,882	118,098
Total property, plant and equipment	10,058,738	9,961,766
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)	541,989	513,733
Assets from risk management activities (Note 8)	53,124	49,322
Other assets	31,084	30,551
Total investments and other assets	626,197	593,606
CURRENT ASSETS
Cash and cash equivalents	2,081	19,873
Customer and other receivables	234,152	280,100
Accrued unbilled revenues	104,728	125,239
Allowance for doubtful accounts	(2,886)	(3,748)
Materials and supplies (at average cost)	213,290	204,387
Fossil fuel (at average cost)	26,850	22,000
Deferred fuel and purchased power regulatory asset (Note 3)	5,310	27,549
Other regulatory assets (Note 3)	81,457	69,072
Deferred income taxes	122,156	111,503
Income tax receivable	3,283	2,869
Assets from risk management activities (Note 8)	34,617	30,264
Other current assets	32,146	26,486
Total current assets	857,184	915,594
DEFERRED DEBITS
Regulatory assets (Note 3)	1,344,523	1,352,079
Income tax receivable (Note 6)	69,464	69,028
Unamortized debt issue costs	23,592	21,181
Other	118,907	118,983
Total deferred debits	1,556,486	1,561,271
TOTAL ASSETS	13,098,605	13,032,237
CAPITALIZATION
Common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,449,236	1,510,740
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(38,065)	(38,886)
Derivative instruments	(103,281)	(86,705)
Total shareholder equity	3,865,748	3,943,007
Noncontrolling interests (Note 7)	116,166	108,399
Total equity	3,981,914	4,051,406
Long-term debt less current maturities	3,150,651	2,828,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	65,547	65,547
Total capitalization	7,198,112	6,945,460
CURRENT LIABILITIES
Commercial paper	216,600
Current maturities of long-term debt	101,708	477,435
Accounts payable	260,578	322,047
Accrued taxes (Note 6)	156,404	113,930
Accrued interest	44,531	54,611
Customer deposits	74,297	72,176
Liabilities from risk management activities (Note 8)	89,207	53,968
Regulatory liabilities (Note 3)	89,622	88,362
Other current liabilities	93,485	140,185
Total current liabilities	1,126,432	1,322,714
DEFERRED CREDITS AND OTHER
Deferred income taxes	1,946,063	1,952,608
Regulatory liabilities (Note 3)	754,210	737,332
Liability for asset retirements	284,839	279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,231,725	1,222,542
Liabilities from risk management activities (Note 8)	64,168	82,495
Customer advances	113,514	116,805
Coal mine reclamation	118,113	117,896
Unrecognized tax benefits (Note 6)	72,424	72,073
Other	189,005	182,669
Total deferred credits and other	4,774,061	4,764,063
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$ 13,098,605	$ 13,032,237

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share

Schedule of earnings per weighted average common share outstanding

	Three Months Ended March 31,
	2012			2011
Basic earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.07	)	$	(0.15	)
Income (loss) from discontinued operations	(0.01		)	0.01
Loss per share — basic	$	(0.08	)	$	(0.14	)
Diluted earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.07	)	$	(0.15	)
Income (loss) from discontinued operations	(0.01		)	0.01
Loss per share — diluted	$	(0.08	)	$	(0.14	)

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Commitments and Contingencies (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	3 Months Ended
	Mar. 31, 2012 trust 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	48,000,000
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

3 Months Ended

Mar. 31, 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 transactions, 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.

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 March 31, 2012 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at March 31, 2012
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	196		$	—		$	—		$	196
Fixed income securities:
U.S. Treasury	76		—			—			—			76
Cash and cash equivalent funds	—		15			—			(1		)(c)	14
Corporate debt	—		67			—			—			67
Mortgage-backed securities	—		82			—			—			82
Municipality bonds	—		88			—			—			88
Other	—		19			—			—			19
Subtotal nuclear decommissioning trust	76		467			—			(1		)	542
Cash Equivalents	12		—			—			—			12
Risk management activities — derivative instruments:
Commodity contracts	—		63			84			(59		)(b)	88
Total	$	88	$	530		$	84		$	(60	)	$	642
Liabilities:
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(271	)	$	(142	)	$	260	(b)	$	(153	)

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

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

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

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		)(c)	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		)(b)	80
Total	$	69	$	516		$	74		$	(65	)	$	594
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(b)	$	(137	)

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

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

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

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Because our 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.  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

	March 31, 2012 Fair Value (millions)
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range
Electricity:
Forward Contracts	$	79	$	106	Discounted cash flows	Electricity prices	$7.13 - $67.50 per MWh
Option Contracts	—		35		Option Model	Electricity prices	$21.15 - $94.23 per MWh
						Natural gas prices	$1.90 - $4.31 per mmbtu
						Electricity volatilities	14% - 83%
						Natural gas volatilities	17% - 50%
Natural Gas:
Forward Contracts	5		1		Discounted cash flows	Natural gas prices	$1.85 - $4.20 per mmbtu
Total	$	84	$	142

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 months ended March 31, 2012 and 2011 (dollars in millions):

	Three Months Ended March 31,
Commodity Contracts	2012			2011
Net risk management activities balance at beginning of period	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	1			1
Included in OCI	(5		)	2
Deferred as a regulatory asset or liability	(5		)	(7		)
Settlements	1			—
Transfers into Level 3 from Level 2	2			(5		)
Transfers from Level 3 into Level 2	(1		)	(1		)
Net risk management activities at end of period	$	(58	)	$	(48	)
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 significant Level 1 transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our heat rate options and long-dated energy transactions that extend beyond available quoted periods.

Nonrecurring Fair Value Measurements

For the periods ended March 31, 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)

3 Months Ended

Mar. 31, 2012

Regulatory Matters

Schedule of proposed capital structure and costs of capital

	Capital Structure		Cost of Capital
Long-term debt	46.1	%	6.38	%
Common stock equity	53.9	%	11.00	%
Weighted-average cost of capital			8.87	%

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

	Three Months Ended March 31,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(47		)	(50		)
Amounts refunded through revenues	24			31
Ending balance	$	5		$	(77	)

Detail of regulatory assets

	March 31, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	1,007	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		81		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	58		34		43		34
Transmission vegetation management	9		30		9		32
Coal reclamation	2		34		2		35
Palo Verde VIEs (Note 7)	—		36		—		35
Deferred compensation	—		34		—		33
Deferred fuel and purchased power (a)	5		—		28		—
Tax expense of Medicare subsidy	2		19		2		18
Loss on reacquired debt	1		19		1		19
Income taxes — investment tax credit basis adjustment	—		15		—		15
Pension and other postretirement benefits deferral	—		21		—		12
Demand-side management (a)	5		—		7		1
Other	2		15		2		14
Total regulatory assets (b)	$	87	$	1,345	$	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

	March 31, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	24	$	344	$	22	$	349
Asset retirement obligations	—		249		—		225
Renewable energy standard (b)	50		—		54		—
Income taxes — change in rates	—		59		—		59
Spent nuclear fuel	7		41		5		44
Deferred gains on utility property	2		14		2		14
Income taxes- deferred investment tax credit	1		32		1		30
Other	6		15		4		16
Total regulatory liabilities	$	90	$	754	$	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 $)	Mar. 31, 2012	Dec. 31, 2011
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Assets	$ 87,741,000	$ 79,586,000
Liabilities	(153,375,000)	(136,463,000)
Current assets	34,617,000	30,264,000
Investments and Other Assets	53,124,000	49,322,000
Current Liabilities	(89,207,000)	(53,968,000)
Deferred Credits and Other	(64,168,000)	(82,495,000)
Derivative Instruments	(65,634,000)	(56,877,000)
Credit Risk and Credit-Related Contingent Features
Risk management assets	87,741,000	79,586,000
Commodity Contracts
Fair value of derivative instruments, margin account and cash collateral reported on a gross basis
Assets	88,000,000
Margin and Collateral Provided to Counterparties	209,432,000	174,626,000
Collateral provided from counterparties	(11,145,000)	(11,145,000)
Other	1,331,000	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	88,000,000
Aggregate Fair Value of Derivative Instruments in a Liability Position	380,000,000
Cash Collateral Posted	180,000,000
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	169,000,000
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	3,486,000	1,630,000
Other	(55,699,000)	(54,815,000)
Current assets	34,617,000	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	(7,892,000)	(12,755,000)
Investments and Other Assets	53,124,000	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	3,486,000	1,630,000
Other	(63,591,000)	(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	100,228,000	107,228,000
Collateral provided from counterparties	(11,145,000)	(11,145,000)
Other	57,053,000	56,172,000
Current Liabilities	(89,207,000)	(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	105,718,000	65,768,000
Other	7,869,000	12,754,000
Deferred Credits and Other	(64,168,000)	(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	205,946,000	172,996,000
Collateral provided from counterparties	(11,145,000)	(11,145,000)
Other	64,922,000	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	(174,001,000)	(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	6,466,000	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	3,377,000	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	9,843,000	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	(103,592,000)	(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	(80,252,000)	(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	(183,844,000)	(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	(91,251,000)	(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	80,364,000	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	57,639,000	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	138,003,000	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	(131,751,000)	(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	(97,503,000)	(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	$ (229,254,000)	$ (216,908,000)

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Regulatory Matters (Details 2) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Detail of regulatory assets
Regulatory assets, current	$ 87,000,000	$ 97,000,000
Regulatory assets, non-current	1,344,523,000	1,352,079,000
Pension and other postretirement benefits
Detail of regulatory assets
Regulatory assets, non-current	1,007,000,000	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	81,000,000	81,000,000
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	58,000,000	43,000,000
Regulatory assets, non-current	34,000,000	34,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	30,000,000	32,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	34,000,000	35,000,000
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, non-current	36,000,000	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	5,000,000	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	19,000,000	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
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, non-current	21,000,000	12,000,000
Demand side management
Detail of regulatory assets
Regulatory assets, current	5,000,000	7,000,000
Regulatory assets, non-current		1,000,000
Other.
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	15,000,000	14,000,000
Income taxes - investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, non-current	$ 15,000,000	$ 15,000,000

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net unrealized gains (loss), tax benefit (expense)	$ 16,551	$ (390)
Reclassification of net realized loss, tax benefit	5,728	5,865
Pension and other postretirement benefits activity, tax expense	$ 631	$ 566

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Regulatory Matters

3 Months Ended

Mar. 31, 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 increase the average retail customer bill approximately 6.6%.  The filing is based on a test year ended December 31, 2010, adjusted as described below.  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.  The Settlement Agreement requires the approval of the ACC.  Evidentiary hearings on the matter were completed on February 3, 2012 and briefs from the parties were filed on February 29, 2012.  See below for details regarding the Settlement Agreement.

The key financial provisions of APS’s original request included:

·An increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through APS’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through the Power Supply Adjustor (“PSA”) (which will decrease base rates);

·A rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;

·The following proposed capital structure and costs of capital:

	Capital Structure		Cost of Capital
Long-term debt	46.1	%	6.38	%
Common stock equity	53.9	%	11.00	%
Weighted-average cost of capital			8.87	%

·A base rate for fuel and purchased power costs (“Base Fuel Rate”) of $0.03242 per kilowatt-hour (“kWh”) based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

APS proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision.  In addition, APS proposed a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.

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 from $0.03757 to $0.03207 per 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 approximately $5 million annually;

·Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

·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.

If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012.  As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.

2008 General Retail Rate Case 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 included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates.  The new rates were effective January 1, 2010.  The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

·Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

·An authorized return on common equity of 11%;

·A capital structure comprised of 46.2% debt and 53.8% common equity;

·A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);

·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 and its use of renewable energy, 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.

Demand-Side Management Adjustor Charge (“DSMAC”).  The settlement agreement resulting from the 2008 retail rate case requires APS to submit an annual 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.

On June 1, 2010, APS filed its 2011 Demand-Side Management Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million.  On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed in the previous paragraph less the $10 million already being recovered in general retail base rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.

On June 1, 2011, APS filed its 2012 Demand-Side Management Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% 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 (1.5% of total energy resources). 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.

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):

	Three Months Ended March 31,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(47		)	(50		)
Amounts refunded through revenues	24			31
Ending balance	$	5		$	(77	)

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 must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  If the Settlement Agreement (discussed above) is approved, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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

Regulatory Assets and Liabilities

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

	March 31, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	1,007	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		81		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	58		34		43		34
Transmission vegetation management	9		30		9		32
Coal reclamation	2		34		2		35
Palo Verde VIEs (Note 7)	—		36		—		35
Deferred compensation	—		34		—		33
Deferred fuel and purchased power (a)	5		—		28		—
Tax expense of Medicare subsidy	2		19		2		18
Loss on reacquired debt	1		19		1		19
Income taxes — investment tax credit basis adjustment	—		15		—		15
Pension and other postretirement benefits deferral	—		21		—		12
Demand-side management (a)	5		—		7		1
Other	2		15		2		14
Total regulatory assets (b)	$	87	$	1,345	$	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):

	March 31, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	24	$	344	$	22	$	349
Asset retirement obligations	—		249		—		225
Renewable energy standard (b)	50		—		54		—
Income taxes — change in rates	—		59		—		59
Spent nuclear fuel	7		41		5		44
Deferred gains on utility property	2		14		2		14
Income taxes- deferred investment tax credit	1		32		1		30
Other	6		15		4		16
Total regulatory liabilities	$	90	$	754	$	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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Fair Value Measurements (Details 3) (USD $) In Thousands, unless otherwise specified					3 Months Ended					3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Electricity forward contracts	Mar. 31, 2012 Electricity forward contracts Option Model	Mar. 31, 2012 Electricity forward contracts Maximum Discounted cash flows perMWh	Mar. 31, 2012 Electricity forward contracts Minimum Discounted cash flows perMWh	Mar. 31, 2012 Option Contracts Maximum Option Model perMMBTU perMWh	Mar. 31, 2012 Option Contracts Minimum Option Model perMMBTU perMWh	Mar. 31, 2012 Natural gas forward contracts	Mar. 31, 2012 Natural gas forward contracts Maximum Discounted cash flows perMMBTU	Mar. 31, 2012 Natural gas forward contracts Minimum Discounted cash flows perMMBTU
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	$ 142,000	$ 125,000	$ 106,000	$ 35,000					$ 1,000
Electricity prices (per MWh)					67.50	7.13	94.23	21.15
Natural gas prices (per mmbtu)							4.31	1.90		4.20	1.85
Electricity volatilities (as a percent)							83.00%	14.00%
Natural gas volatilities (as a percent)							50.00%	17.00%

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Changes in Equity (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Changes in equity
Balance at beginning of period	$ 3,930,586	$ 3,775,226
NET INCOME (LOSS)	(481)	(9,674)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	(15,614)	10,446
COMPREHENSIVE INCOME (LOSS)	(16,095)	772
Dividends on common stock	(57,358)	(57,109)
Other	3,350	10,723
Balance at end of period	3,861,429	3,728,771
Shareholder equity
Changes in equity
Balance at beginning of period	3,821,850	3,683,327
NET INCOME (LOSS)	(8,257)	(15,135)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	(15,614)	10,446
COMPREHENSIVE INCOME (LOSS)	(23,871)	(4,689)
Dividends on common stock	(57,358)	(57,109)
Other	3,350	10,723
Balance at end of period	3,744,917	3,631,411
NONCONTROLLING INTERESTS
Changes in equity
Balance at beginning of period	108,736	91,899
NET INCOME (LOSS)	7,776	5,461
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME (LOSS)	7,776	5,461
Balance at end of period	116,512	97,360
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Balance at beginning of period	4,051,406	3,916,037
NET INCOME (LOSS)	3,662	(6,611)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	(15,755)	10,358
COMPREHENSIVE INCOME (LOSS)	(12,093)	3,747
Dividends on common stock	(57,400)	(57,100)
Other	1	1
Balance at end of period	3,981,914	3,862,685
ARIZONA PUBLIC SERVICE COMPANY | Shareholder equity
Changes in equity
Balance at beginning of period	3,943,007	3,824,953
NET INCOME (LOSS)	(4,105)	(12,081)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	(15,755)	10,358
COMPREHENSIVE INCOME (LOSS)	(19,860)	(1,723)
Dividends on common stock	(57,400)	(57,100)
Other	1	1
Balance at end of period	3,865,748	3,766,131
ARIZONA PUBLIC SERVICE COMPANY | NONCONTROLLING INTERESTS
Changes in equity
Balance at beginning of period	108,399	91,084
NET INCOME (LOSS)	7,767	5,470
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME (LOSS)	7,767	5,470
Balance at end of period	116,166	96,554
PINNACLE WEST CAPITAL CORPORATION | Shareholder equity
Changes in equity
Balance at beginning of period	3,821,850	3,683,327
NET INCOME (LOSS)	(8,257)	(15,135)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Other comprehensive income (loss)	(15,614)	10,446
COMPREHENSIVE INCOME (LOSS)	(23,871)	(4,689)
Dividends on common stock	(57,358)	(57,109)
Other	3,350	10,723
Balance at end of period	3,744,917	3,631,411
PINNACLE WEST CAPITAL CORPORATION | NONCONTROLLING INTERESTS
Changes in equity
Balance at beginning of period	108,736	91,899
NET INCOME (LOSS)	7,776	5,461
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME (LOSS)	7,776	5,461
Balance at end of period	$ 116,512	$ 97,360

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Retirement Plans and Other Benefits (Tables)

3 Months Ended

Mar. 31, 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 March 31,						Three Months Ended March 31,
	2012			2011			2012			2011
Service cost - benefits earned during the period	$	16		$	16		$	7		$	6
Interest cost on benefit obligation	30			31			12			12
Expected return on plan assets	(35		)	(33		)	(11		)	(10		)
Amortization of net actuarial loss	11			6			6			3
Net periodic benefit cost	$	22		$	20		$	14		$	11
Portion of cost charged to expense	$	6		$	8		$	3		$	4

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Consolidation and Nature of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Revenues
OPERATING REVENUES	$ 620,631	$ 648,847
Operating Expenses
Operations and maintenance	210,663	255,029
Depreciation and amortization	100,109	106,583
Other expenses	3,068	1,820
Other
Other expense (Note 11)	(4,068)	(1,741)
Income Taxes	(4,645)	(6,005)
Income From Continuing Operations	284	(10,368)
Income From Discontinued Operations	(765)	694
Cash Flows from Operating Activities
Change in other long-term assets	(21,469)	(33,169)
Change in other long-term liabilities	22,362	35,418
As previously reported
Operating Revenues
Regulated electricity segment revenues		647,974
Other revenues		11,601
Operating Expenses
Operations and maintenance		256,486
Depreciation and amortization		106,601
Other expenses		9,716
Other
Other expense (Note 11)		(1,699)
Income Taxes		(5,649)
Income From Continuing Operations		(9,325)
Income From Discontinued Operations		(349)
Cash Flows from Operating Activities
Expenditures for real estate investments		(40)
Gains and other changes in real estate assets		(3)
Change in other long-term assets		(33,129)
Change in other long-term liabilities		35,421
Reclassifications for discontinued operations
Operating Revenues
Regulated electricity segment revenues		(647,974)
Other revenues		(11,601)
OPERATING REVENUES		648,847
Operating Expenses
Operations and maintenance		(1,457)
Depreciation and amortization		(18)
Other expenses		(7,896)
Other
Other expense (Note 11)		(42)
Income Taxes		(356)
Income From Continuing Operations		(1,043)
Income From Discontinued Operations		1,043
Cash Flows from Operating Activities
Expenditures for real estate investments		40
Gains and other changes in real estate assets		3
Change in other long-term assets		(40)
Change in other long-term liabilities		(3)
Amount reported after reclassification for discontinued operations
Operating Revenues
OPERATING REVENUES		648,847
Operating Expenses
Operations and maintenance		255,029
Depreciation and amortization		106,583
Other expenses		1,820
Other
Other expense (Note 11)		(1,741)
Income Taxes		(6,005)
Income From Continuing Operations		(10,368)
Income From Discontinued Operations		694
Cash Flows from Operating Activities
Change in other long-term assets		(33,169)
Change in other long-term liabilities		$ 35,418

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Discontinued Operations

3 Months Ended

Mar. 31, 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 months ended March 31, 2012 and prior comparative period income statement amounts are included in discontinued operations.  At March 31, 2012, SunCor had approximately $8 million of assets on its balance sheet, including $7 million of intercompany receivables and $1 million of other assets.

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 months ended March 31, 2012 and 2011 (dollars in millions):

	Three Months Ended March 31,
	2012			2011
Revenue:
SunCor	$	—		$	1
APSES	—			11
Total revenue	$	—		$	12
Income (loss) before taxes:	$	(1	)	$	1
Income (loss) after taxes:	$	(1	)	$	1