SEC Info - Arizona Public Service Co, et al.

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		Alternative Formats (Word, et al.) And Results of Operations Arizona Public Service Company Controls and Procedures Exhibits Financial Statements Forward-Looking Statements Item 1 Item 1A Item 2 Item 3 Item 4 Item 5 Item 6 Legal Proceedings Management's Discussion and Analysis of Financial Condition Other Information Part I Part II Pinnacle West Capital Corporation Quantitative and Qualitative Disclosures About Market Risk Risk Factors Signatures Table of Contents Unregistered Sales of Equity Securities and Use of Proceeds
1	1st Page – Filing Submission
"	Table of Contents
"	Forward-Looking Statements
"	Part I
"	Item 1
"	Financial Statements
"	Pinnacle West Capital Corporation
"	Arizona Public Service Company
"	Item 2
"	Management's Discussion and Analysis of Financial Condition
"	And Results of Operations
"	Item 3
"	Quantitative and Qualitative Disclosures About Market Risk
"	Item 4
"	Controls and Procedures
"	Part II
"	Legal Proceedings
"	Item 1A
"	Risk Factors
"	Unregistered Sales of Equity Securities and Use of Proceeds
"	Item 5
"	Other Information
"	Item 6
"	Exhibits
"	Signatures

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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

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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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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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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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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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	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).

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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	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).

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.

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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

106

Discounted cash flows

Electricity prices

$7.13 - $67.50 per MWh

Option Contracts

—

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

Discounted cash flows

Natural gas prices

$1.85 - $4.20 per mmbtu

Total

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

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

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	)

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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.

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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.

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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.

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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.

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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.

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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.

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

	Condensed Consolidated Note Reference	APS’s Supplemental Note Reference
Consolidation and Nature of Operations	Note 1	—
Long-Term Debt and Liquidity Matters	Note 2	—
Regulatory Matters	Note 3	—
Retirement Plans and Other Benefits	Note 4	—
Business Segments	Note 5	—
Income Taxes	Note 6	—
Palo Verde Sale Leaseback Variable Interest Entities	Note 7	—
Derivative Accounting	Note 8	—
Changes in Equity	Note 9	Note S-1
Commitments and Contingencies	Note 10	—
Other Income and Other Expense	Note 11	Note S-2
Earnings Per Share	Note 12	—
Discontinued Operations	Note 13	—
Fair Value Measurements	Note 14	—
Nuclear Decommissioning Trust	Note 15	—
New Accounting Standards	Note 16	—

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. Changes in Equity

The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three 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).

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

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Part I, Item 1A of the 2011 Form 10-K.

OVERVIEW

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

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

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

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

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

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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, 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

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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	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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Part II - OTHER INFORMATION

Item 1. LEGAL PROCEEDING S

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.

Table of Contents

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.

Table of Contents

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

Table of Contents

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.

Table of Contents

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.

Arizona Public Service Co, et al. – ‘10-Q’ for 3/31/12

On: Thursday, 5/3/12, at 8:05am ET · For: 3/31/12 · Accession #: 1104659-12-32315 · File #s: 1-04473, 1-08962

Previous ‘10-Q’: ‘10-Q’ on 11/1/11 for 9/30/11 · Next: ‘10-Q’ on 8/2/12 for 6/30/12 · Latest: ‘10-Q’ on 11/2/23 for 9/30/23 · 4 References:

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

‘10-Q’ — Quarterly Report
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Dates Referenced Herein and Documents Incorporated by Reference

4 Subsequent Filings that Reference this Filing

		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)

This ‘10-Q’ Filing	Date	Other Filings

	7/1/16
	5/31/15
	12/31/14	10-K, 11-K, 8-K, ARS
	2/1/13
	12/31/12	10-K, 11-K, 5, 8-K
	12/1/12
	11/30/12
	10/1/12
	8/31/12
	7/1/12
	6/12/12
	6/1/12
	5/16/12	8-K, DEF 14A
Filed on:	5/3/12	8-K
	5/1/12
	4/27/12
	4/18/12	8-K
	4/4/12	4, 4/A, 5
	4/2/12	4, 4/A
For Period end:	3/31/12
	3/29/12	ARS, DEF 14A
	3/27/12
	3/20/12
	3/14/12
	3/12/12
	3/1/12
	2/29/12	8-K
	2/3/12	8-K
	2/1/12
	1/31/12
	1/13/12
	1/6/12	8-K
	1/1/12
	12/31/11	10-K, 11-K, 5, 8-K, ARS
	12/22/11
	12/14/11
	11/28/11
	10/4/11
	10/3/11
	9/12/11
	9/8/11
	7/1/11	4, 8-K/A
	6/21/11
	6/20/11
	6/1/11	8-K
	4/29/11	10-Q, 8-K
	3/31/11	10-Q, 8-K
	3/11/11
	3/1/11
	2/17/11	4
	1/30/11
	1/24/11
	1/1/11
	12/31/10	10-K, 11-K, 8-K, ARS
	11/8/10	8-K
	9/8/10
	7/27/10
	6/30/10	10-Q, 8-K
	6/1/10	3, 8-K
	5/19/10	8-K, DEF 14A, PRE 14A
	1/1/10
	12/31/09	10-K, 11-K, 8-K, ARS
	12/30/09
	9/23/09
	6/1/09
	12/31/08	10-K, 11-K, 8-K, ARS
	12/16/08
	6/30/08	10-Q, 8-K
	5/21/08	DEF 14A, PRE 14A
	9/3/03
	7/25/01
	6/20/01	3
	12/25/00
	9/24/93
		List all Filings

Arizona Public Service Co, et al. – ‘10-Q’ for 3/31/12

On: Thursday, 5/3/12, at 8:05am ET · For: 3/31/12 · Accession #: 1104659-12-32315 · File #s: 1-04473, 1-08962

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34Filing Table of Contents

‘10-Q’ — Quarterly ReportDocument Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

4 Subsequent Filings that Reference this Filing

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

‘10-Q’ — Quarterly Report
Document Table of Contents