PINNACLE WEST CAPITAL CORP - Quarter Report: 2013 September (Form 10-Q)

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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 September 30, 2013

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

For the transition period from to

Commission File
Number

Exact Name of Each Registrant as specified in its
charter; State of Incorporation; Address; and
Telephone Number

IRS Employer
Identification No.

1-8962

PINNACLE WEST CAPITAL CORPORATION

(an Arizona corporation)

400 North Fifth Street, P.O. Box 53999

Phoenix, Arizona 85072-3999

(602) 250-1000

86-0512431

1-4473

ARIZONA PUBLIC SERVICE COMPANY

(an Arizona corporation)

400 North Fifth Street, P.O. Box 53999

Phoenix, Arizona 85072-3999

(602) 250-1000

86-0011170

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

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

Smaller reporting company o

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

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

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

PINNACLE WEST CAPITAL CORPORATION		Number of shares of common stock, no par value, outstanding as of October 21, 2013: 110,044,952
ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of October 21, 2013: 71,264,947

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

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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	46
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	57
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	78
Item 4.	Controls and Procedures	78

Part II		80
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 5.	Other Information	80
Item 6.	Exhibits	82
Signatures		85

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, 2012 (“2012 Form 10-K”), Part II, Item 1A of this report and in Part I, Item 2 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, these factors include, but are not limited to:

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

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

· power plant and transmission system performance and outages;

· volatile fuel and purchased power costs;

· fuel and water supply availability;

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

· regulatory and judicial decisions, developments and proceedings;

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

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

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

· competition in retail and wholesale power markets;

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

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

· changes to our credit ratings;

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

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

· potential shortfalls in insurance coverage;

· new accounting requirements or new interpretations of existing requirements;

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

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

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

· technological developments affecting the electric industry; and

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

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

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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 September 30,
	2013			2012

OPERATING REVENUES	$	1,152,392		$	1,109,475

OPERATING EXPENSES
Fuel and purchased power	350,953			302,894
Operations and maintenance	233,323			220,729
Depreciation and amortization	107,388			100,353
Taxes other than income taxes	43,256			36,507
Other expenses	1,784			1,022
Total	736,704			661,505
OPERATING INCOME	415,688			447,970
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,569			5,708
Other income (Note 10)	160			420
Other expense (Note 10)	(7,435		)	(5,696		)
Total	(1,706		)	432
INTEREST EXPENSE
Interest charges	50,587			52,242
Allowance for borrowed funds used during construction	(3,235		)	(3,830		)
Total	47,352			48,412
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	366,630			399,990
INCOME TAXES	131,912			147,116
INCOME FROM CONTINUING OPERATIONS	234,718			252,874
LOSS FROM DISCONTINUED OPERATIONS
Net of income tax benefit of $7	—			(11		)
NET INCOME	234,718			252,863
Less: Net income attributable to noncontrolling interests (Note 6)	8,555			8,040
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	226,163		$	244,823

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	110,009			109,555
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	111,053			110,655

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	2.06		$	2.23
Net income attributable to common shareholders — basic	2.06			2.23
Income from continuing operations attributable to common shareholders — diluted	2.04			2.21
Net income attributable to common shareholders — diluted	2.04			2.21

DIVIDENDS DECLARED PER SHARE	$	—		$	—

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	226,163		$	244,834
Discontinued operations, net of tax	—			(11		)
Net income attributable to common shareholders	$	226,163		$	244,823

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 September 30,
	2013			2012

NET INCOME	$	234,718		$	252,863

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $95 and $47	(145		)	(72		)
Reclassification of net realized loss, net of tax benefit of $9,348 and $19,543	14,310			29,935
Pension and other postretirement benefits activity, net of tax (expense) of $(625) and $(640)	957			980
Total other comprehensive income	15,122			30,843

COMPREHENSIVE INCOME	249,840			283,706
Less: Comprehensive income attributable to noncontrolling interests	8,555			8,040

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	241,285		$	275,666

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Nine Months Ended September 30,
	2013			2012

OPERATING REVENUES	$	2,754,866		$	2,608,682

OPERATING EXPENSES
Fuel and purchased power	859,216			783,926
Operations and maintenance	685,873			647,628
Depreciation and amortization	317,410			301,068
Taxes other than income taxes	124,091			120,271
Other expenses	5,853			5,323
Total	1,992,443			1,858,216
OPERATING INCOME	762,423			750,466
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	18,698			15,639
Other income (Note 10)	1,387			1,357
Other expense (Note 10)	(13,421		)	(12,433		)
Total	6,664			4,563
INTEREST EXPENSE
Interest charges	151,372			162,209
Allowance for borrowed funds used during construction	(10,861		)	(10,428		)
Total	140,511			151,781
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	628,576			603,248
INCOME TAXES	221,424			219,160
INCOME FROM CONTINUING OPERATIONS	407,152			384,088
LOSS FROM DISCONTINUED OPERATIONS
Net of income tax benefit of $1,047	—			(1,595		)
NET INCOME	407,152			382,493
Less: Net income attributable to noncontrolling interests (Note 6)	25,338			23,582
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	381,814		$	358,911

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,935			109,449
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,913			110,420

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	3.47		$	3.29
Net income attributable to common shareholders — basic	3.47			3.28
Income from continuing operations attributable to common shareholders — diluted	3.44			3.26
Net income attributable to common shareholders — diluted	3.44			3.25

DIVIDENDS DECLARED PER SHARE	$	1.09		$	1.575

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	381,814		$	360,515
Discontinued operations, net of tax	—			(1,604		)
Net income attributable to common shareholders	$	381,814		$	358,911

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)

	Nine Months Ended September 30,
	2013			2012

NET INCOME	$	407,152		$	382,493

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $162 and $14,817	(247		)	(22,696		)
Reclassification of net realized loss, net of tax benefit of $15,471 and $34,361	23,685			52,632
Pension and other postretirement benefits activity, net of tax (expense) of $(807) and $(1,797)	1,235			2,752
Total other comprehensive income	24,673			32,688

COMPREHENSIVE INCOME	431,825			415,181
Less: Comprehensive income attributable to noncontrolling interests	25,338			23,582

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	406,487		$	391,599

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)

	September 30, 2013			December 31, 2012
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	135,457		$	26,202
Customer and other receivables	427,370			277,225
Accrued unbilled revenues	132,555			94,845
Allowance for doubtful accounts	(3,768		)	(3,340		)
Materials and supplies (at average cost)	223,385			218,096
Fossil fuel (at average cost)	34,959			31,334
Deferred income taxes	87,490			152,191
Income tax receivable (Note 5)	133,551			2,423
Assets from risk management activities (Note 7)	22,741			25,699
Deferred fuel and purchased power regulatory asset (Note 3)	37,383			72,692
Other regulatory assets (Note 3)	82,558			71,257
Other current assets	36,805			37,102
Total current assets	1,350,486			1,005,726

INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	26,046			35,891
Nuclear decommissioning trust (Note 13)	612,640			570,625
Other assets	60,219			62,694
Total investments and other assets	698,905			669,210

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,597,995			14,346,367
Accumulated depreciation and amortization	(5,101,498		)	(4,929,613		)
Net	9,496,497			9,416,754
Construction work in progress	605,987			565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	126,092			128,995
Intangible assets, net of accumulated amortization	160,134			162,150
Nuclear fuel, net of accumulated amortization	140,356			122,778
Total property, plant and equipment	10,529,066			10,396,393

DEFERRED DEBITS
Regulatory assets (Note 3)	1,105,882			1,099,900
Income tax receivable (Note 5)	—			70,389
Other	138,332			137,997
Total deferred debits	1,244,214			1,308,286

TOTAL ASSETS	$	13,822,671		$	13,379,615

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)

	September 30, 2013			December 31, 2012
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	250,023		$	221,312
Accrued taxes (Note 5)	183,858			124,939
Accrued interest	45,811			49,380
Common dividends payable	—			59,789
Short-term borrowings	—			92,175
Current maturities of long-term debt (Note 2)	566,481			122,828
Customer deposits	77,254			79,689
Liabilities from risk management activities (Note 7)	53,468			73,741
Regulatory liabilities (Note 3)	88,409			88,116
Other current liabilities	181,639			171,573
Total current liabilities	1,446,943			1,083,542

LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)
Long-term debt less current maturities	2,782,901			3,160,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414			38,869
Total long-term debt less current maturities	2,820,315			3,199,088

DEFERRED CREDITS AND OTHER
Deferred income taxes	2,363,783			2,151,371
Regulatory liabilities (Note 3)	798,226			759,201
Liability for asset retirements	364,635			357,097
Liabilities for pension and other postretirement benefits (Note 4)	939,414			1,058,755
Deferred investment tax credit	115,984			99,819
Liabilities from risk management activities (Note 7)	67,662			85,264
Customer advances	109,667			109,359
Coal mine reclamation	114,764			118,860
Unrecognized tax benefits (Note 5)	81,797			71,135
Other	178,053			183,835
Total deferred credits and other	5,133,985			4,994,696

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

EQUITY (Note 8)
Common stock, no par value	2,489,180			2,466,923
Treasury stock	(10,079		)	(4,211		)
Total common stock	2,479,101			2,462,712
Retained earnings	1,886,038			1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(63,181		)	(64,416		)
Derivative instruments	(26,154		)	(49,592		)
Total accumulated other comprehensive loss	(89,335		)	(114,008		)
Total shareholders’ equity	4,275,804			3,972,806
Noncontrolling interests (Note 6)	145,624			129,483
Total equity	4,421,428			4,102,289

TOTAL LIABILITIES AND EQUITY	$	13,822,671		$	13,379,615

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)

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	407,152		$	382,493
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	377,971			360,570
Deferred fuel and purchased power	13,093			51,533
Deferred fuel and purchased power amortization	23,158			(91,894		)
Allowance for equity funds used during construction	(18,698		)	(15,639		)
Deferred income taxes	256,132			197,527
Deferred investment tax credit	16,164			8,974
Change in derivative instruments fair value	537			(943		)
Changes in current assets and liabilities:
Customer and other receivables	(178,029		)	(76,697		)
Accrued unbilled revenues	(37,710		)	(11,186		)
Materials, supplies and fossil fuel	(8,914		)	(23,873		)
Income tax receivable	(131,128		)	6,466
Other current assets	(12,246		)	(10,035		)
Accounts payable	44,704			(69,776		)
Accrued taxes	58,919			69,899
Other current liabilities	4,096			17,071
Change in margin and collateral accounts — assets	(327		)	1,980
Change in margin and collateral accounts — liabilities	15,000			114,579
Change in long-term income tax receivable	137,270			(1,320		)
Change in unrecognized tax benefits	(57,585		)	(3,554		)
Change in other long-term assets	(24,345		)	(13,885		)
Change in other long-term liabilities	(2,884		)	37,181
Net cash flow provided by operating activities	882,330			929,471

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(581,515		)	(670,684		)
Contributions in aid of construction	34,910			41,451
Allowance for borrowed funds used during construction	(10,861		)	(10,428		)
Proceeds from nuclear decommissioning trust sales	363,944			295,126
Investment in nuclear decommissioning trust	(376,881		)	(308,063		)
Other	(1,553		)	(520		)
Net cash flow used for investing activities	(571,956		)	(653,118		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307			351,081
Repayment of long-term debt	(72,777		)	(421,703		)
Short-term borrowings and payments — net	(92,175		)	—
Dividends paid on common stock	(174,485		)	(167,074		)
Common stock equity issuance	10,396			9,684
Distributions to noncontrolling interests	(9,197		)	(2,630		)
Other	812			185
Net cash flow used for financing activities	(201,119		)	(230,457		)

NET INCREASE IN CASH AND CASH EQUIVALENTS	109,255			45,896

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	26,202			33,583

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	135,457		$	79,479

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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS and El Dorado Investment Company (“El Dorado”) and formerly SunCor Development Company (“SunCor”). Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”) (see Note 6 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These condensed consolidated financial statements and notes have been prepared consistently with the 2012 Form 10-K, with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

The following tables show the impact of the reclassifications to prior year (previously reported) amounts of the deferred investment tax credit and income tax receivables which have become more material in 2013 (dollars in thousands):

Balance Sheets - December 31, 2012	As previously reported		Reclassifications			Amount reported after reclassifications

Deferred investment tax credit	$	—	$	99,819		$	99,819
Deferred credits — other	283,654		(99,819		)	183,835

Statement of Cash Flows for the Nine Months Ended September 30, 2012	As previously reported			Reclassifications			Amount reported after reclassifications

Cash Flows from Operating Activities
Deferred income taxes	$	206,501		$	(8,974	)	$	197,527
Deferred investment tax credit	—			8,974			8,974
Income tax receivable	—			6,466			6,466
Accrued taxes	76,365			(6,466		)	69,899
Change in long-term income tax receivable	—			(1,320		)	(1,320		)
Change in other long-term assets	(15,205		)	1,320			(13,885		)

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

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

	Nine Months Ended September 30,
	2013		2012
Cash paid during the period for:
Income taxes, net of (refunds)	$	3,412	$	(651	)
Interest, net of amounts capitalized	141,047		152,582
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	11,377	$	11,281

2. Long-Term Debt and Liquidity Matters

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

Pinnacle West

At September 30, 2013, Pinnacle West’s $200 million credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At September 30, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding, and no commercial paper borrowings.

APS

On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.

On April 9, 2013, APS replaced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility. The new revolving credit facility terminates in April 2018.

On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029. On May 28, 2013, we remarketed the bonds. The interest rate for these bonds was set to a new term rate. The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018. During this time, the bonds will bear interest at a rate of 1.75% per annum. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2013 and were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.

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On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. These bonds were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.

At September 30, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At September 30, 2013, APS had no commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.

On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012.

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

Debt Fair Value

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy. See Note 12 for a discussion of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of September 30, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Pinnacle West	$	125	$	125	$	125	$	125
APS	3,262		3,538		3,197		3,750
Total	$	3,387	$	3,663	$	3,322	$	3,875

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2013, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.4 billion, and total capitalization was approximately $7.6 billion. APS would be prohibited from paying dividends if payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the

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same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs.

3. Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.

Settlement Agreement

The Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs (“Base Fuel Rate”) from $0.03757 to $0.03207 per kilowatt hour (“kWh”); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff (“RES”) surcharge to base rates in an estimated amount of $36.8 million.

APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement.

Other key provisions of the Settlement Agreement include the following:

· An authorized return on common equity of 10.0%;

· A capital structure comprised of 46.1% debt and 53.9% common equity;

· A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

· Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

· Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

· Deferral of 100% in all years if Arizona property tax rates decrease;

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· A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant (“Four Corners”);

· Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

· Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

· Modifications to the Power Supply Adjustor (“PSA”), including the elimination of the 90/10 sharing provision;

· A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge (“DSMAC”) to recoup capital expenditures not required under the terms of the 2008 rate case settlement agreement discussed below;

· Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

· Modification of the transmission cost adjustor (“TCA”) to streamline the process for future transmission-related rate changes; and

· Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.

The Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2008 rate case settlement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

2008 General Retail Rate Case On-Going Impacts

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008. The settlement agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

· A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

· Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

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· Various modifications to the existing energy efficiency, demand side management and renewable energy programs that require APS to, among other things, expand its conservation and demand side management programs through 2012 and its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand side management costs and incentives.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

On December 14, 2011, the ACC voted to approve APS’s 2012 RES plan covering the 2012-2016 timeframe and authorized a total 2012 RES budget of $110 million. On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requested 2013 RES funding of between $97 million and $107 million. In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan. That budget included $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for new commercial distributed energy production-based incentives beyond those for previously approved programs. The ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. In those proceedings, the ACC staff proposed a process whereby if a customer installs distributed generation without an incentive, the customer keeps the renewable energy credits generated and the RES distributed generation requirement is adjusted downward to reflect how much load is being served by renewable generation. APS has endorsed the ACC staff’s proposed solution. Finally, the ACC authorized an APS-led multi-session technical conference to consider APS’s net metering policy and the cost and benefits of distributed energy. The multi-session technical conference concluded on May 28, 2013.

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either: (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price. APS also proposed that the ACC: (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations. In its September 30, 2013 report, the ACC staff recognized that net metering shifts costs from solar customers to non-solar customers. The staff recommended that the ACC wait until APS’s

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next rate case to address the issue. As an alternative, the ACC staff recommended that the ACC assess one of two modest charges on new solar customers with a mechanism to return all incremental revenue collected from such charges to customers.

On July 12, 2013, APS filed its annual RES implementation plan covering the 2014-2018 timeframe. The plan requests a budget for 2014 of approximately $143 million. The plan does not propose any new programs. Rather, the plan requests the funding necessary to fulfill previously approved projects and commitments which are needed to comply with the RES targets and APS’s obligations under its 2008 rate case settlement agreement approved by the ACC, including the remaining 50 megawatts (“MW”) of the AZ Sun Program. AZ Sun is a program that contemplates the development of photovoltaic solar plants which APS owns or will own. On September 30, 2013, the ACC staff issued a report recommending approval of APS’s plan and proposed budget.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC.

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011. The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (2.75% of total energy resources for the same two-year period). The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs. This amount will be recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan. In 2013, the standards require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million. APS expects to receive a decision from the ACC in late 2013 or early 2014.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards (including cost recovery methodology, incentives, and the determination of cost effectiveness) should be modified or abolished.

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

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2013 and 2012 (dollars in millions):

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	Nine Months Ended September 30,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs — current period	(13		)	(52		)
Amounts (collected from) credited to customers	(23		)	92
Ending balance	$	37		$	68

The PSA rate for the PSA year beginning February 1, 2013 is $0.0013 per kWh as compared to ($0.0042) per kWh for the prior year. This represents a $0.0055 per kWh increase over the 2012 PSA charge. This new rate is comprised of a forward component of ($0.0010) per kWh and a historical component of $0.0023 per kWh. The Settlement Agreement allowed APS to exceed the $0.004 per kWh cap to PSA rate changes in this instance. Any uncollected (overcollected) deferrals during the 2013 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2014.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, the United States Federal Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 and will go into effect automatically unless suspended by the ACC.

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

Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula.

Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula. Pursuant to the Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover the FERC-approved transmission charges went into effect automatically on June 1, 2013.

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As part of APS’s proposed acquisition of Southern California Edison’s (“SCE”) interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing transmission agreement between the parties that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California. On May 1, 2013, APS submitted a request with FERC seeking authorization to cancel the transmission agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 10-year period. On September 13, 2013, FERC issued an Order accepting the notice of cancellation, but denying APS’s request for rate recovery of the costs associated with the cancellation. In accordance with its termination agreement with SCE (the “Termination Agreement”), APS believes that the denial by FERC of such rate recovery constitutes the failure of a condition that relieves APS of its obligations under the Termination Agreement. The parties are in discussions concerning this matter. If the matter is not resolved by negotiation, the Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter.

Lost Fixed Cost Recovery (“LFCR”) Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as roof-top solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the recent rate case and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.

APS filed its first LFCR adjustment on January 15, 2013 and will file for its LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved an LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the Settlement Agreement went into effect on July 1, 2012.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.

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Regulatory Assets and Liabilities

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

	Remaining Amortization		September 30, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits		(a)	$	—	$	754	$	—	$	780
Income taxes — allowance for equity funds used during construction	2043		4		105		4		92
Deferred fuel and purchased power — mark-to-market (Note 7)	2016		15		24		19		21
Transmission vegetation management	2016		9		16		9		23
Coal reclamation	2038		8		20		8		24
Palo Verde VIEs (Note 6)	2046		—		40		—		38
Deferred compensation	2036		—		36		—		34
Deferred fuel and purchased power (b) (c)	2013		37		—		73		—
Retired power plant costs	2020		3		19		—		—
Tax expense of Medicare subsidy	2024		2		15		2		17
Loss on reacquired debt	2034		1		17		2		18
Income taxes — investment tax credit basis adjustment	2042		1		30		1		26
Pension and other postretirement benefits deferral	2015		8		6		8		13
Lost fixed cost recovery (b)	2014		19		—		7		—
Transmission cost adjustor (b)	2014		12		2		10		—
Other	Various		1		22		1		14
Total regulatory assets (d)			$	120	$	1,106	$	144	$	1,100

(a) This asset represents the future recovery of under-funded pension and other postretirement benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future revenues.

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

(d) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”

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

	Remaining Amortization		September 30, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Removal costs		(a)	$	26	$	311	$	27	$	321
Asset retirement obligations		(a)	—		272		—		256
Renewable energy standard (b)	2014		27		22		43		—
Income taxes — change in rates	2042		—		68		—		66
Spent nuclear fuel	2047		5		37		10		36
Deferred gains on utility property	2019		2		11		2		12
Income taxes — deferred investment tax credit	2042		2		60		2		52
Demand side management (b)	2014		26		—		4		—
Other	Various		—		17		—		16
Total regulatory liabilities			$	88	$	798	$	88	$	759

(a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.

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

4. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred through June 30, 2012 as a regulatory asset for future recovery, pursuant to an ACC regulatory order. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset in July 2012. We amortized approximately $2 million for the three months ended September 30, 2013, and 2012, and approximately $6 million and $2 million for the nine months ended September 30, 2013 and 2012, respectively. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):

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	Pension Benefits												Other Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost — benefits earned during the period	$	16		$	16		$	48		$	48		$	6		$	7		$	18		$	20
Interest cost on benefit obligation	28			30			84			90			10			12			31			35
Expected return on plan assets	(36		)	(35		)	(110		)	(106		)	(11		)	(12		)	(34		)	(34		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	10			11			30			33			3			5			8			15
Net periodic benefit cost	$	18		$	22		$	53		$	66		$	8		$	12		$	23		$	36
Portion of cost charged to expense	$	10		$	12		$	29		$	25		$	5		$	7		$	14		$	13

Contributions

We have made voluntary contributions of $141 million to our pension plan in 2013. The minimum contributions for the pension plan due in 2013, 2014, and 2015 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero, $89 million, and $112 million, respectively. We expect to make contributions to the pension plan up to approximately $175 million each year in 2014 and 2015. We have contributed $11 million to our other postretirement benefit plans in 2013. The total contributions to our other postretirement benefit plans are expected to be approximately $14 million in 2013 and approximately $20 million each year in 2014 and 2015.

5. Income Taxes

The $70 million long-term income tax receivable on the Condensed Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009. On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt. As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter. This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities. The $137 million anticipated refund is expected to be received within the next twelve months and has been reclassified to current income tax receivable as of September 30, 2013.

Finalization of the current IRS examination of tax returns for the years ended December 31, 2008 and 2009 is likely to occur within the next twelve months. As a result, the $137 million anticipated refund has been reduced by approximately $4 million to reflect the likely ultimate outcome of this examination. Additionally, it is possible that uncertain tax positions could decrease by approximately $35 million. This decrease would be materially offset by an increase in deferred tax liabilities.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS, resulting in a

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cumulative effect adjustment. To account for the adoption of these regulations, for the quarter ended September 30, 2013, plant-related long-term deferred tax liabilities decreased by $80 million, with the offsetting decrease to current deferred income tax assets. Prior to the issuance of these regulations, this $80 million would have been repaid over 20 years through lower tax depreciation deductions.

Net Income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 6). As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.

The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions making qualified property placed into service in 2013 eligible for 50% bonus depreciation for federal income tax purposes. Full recognition of the cash benefit of this provision delayed realization of approximately $78 million in federal general business income tax credit carryforwards which were classified as current deferred income taxes as of December 31, 2012. However, as of September 30, 2013, the $78 million in federal general business tax credit carryforwards are expected to be realized within the next twelve months.

As of September 30, 2013, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.

6. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million per year for the years 2013 to 2015 related to these leases. The lease agreements include fixed rate renewal periods, which gives APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

On December 31, 2012, APS notified the lessor trust entities that APS would retain the assets beyond 2015 by either exercising the fixed rate lease renewals or by purchasing the assets. If APS elects to purchase the assets, the purchase price will be based on the fair market value of the assets at the end of 2015. If APS elects to extend the leases, we will be required to make payments beginning in 2016 of approximately $23 million annually. The length of the lease extensions is unknown at this time as it must be determined through an appraisal process. APS must give notice to the lessor trusts by June 30, 2014 notifying them which of these two options (lease renewal or purchasing the assets) it will exercise. The December 31, 2012 notification does not impact APS’s consolidation of the VIEs, as APS continues to be deemed the primary beneficiary of the VIEs.

As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three and nine months ended September 30, 2013 of $9 million and $25 million, respectively, and for the three and nine months ended September 30, 2012 of $8 million and $24 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same.

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Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

	September 30, 2013		December 31, 2012
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	126	$	129
Current maturities of long-term debt	20		27
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	37		39
Equity — Noncontrolling interests	146		129

Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2013, APS would have been required to pay the noncontrolling equity participants approximately $142 million and assume $57 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

For regulatory ratemaking purposes, the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

7. Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces

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both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as accounting hedges. This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts. For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through other comprehensive income (“OCI”), but are deferred through the PSA. The amounts previously recorded in accumulated OCI (“AOCI”) relating to these instruments will remain in AOCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur. Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 12 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and normal sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

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

Prior to the Settlement Agreement, for its regulated operations, APS deferred for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Due to the Settlement Agreement, for its regulated operations, APS now defers for future rate treatment 100% of the unrealized gains and losses for delivery periods after June 30, 2012 on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

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As of September 30, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

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Commodity	Quantity
Power	6,498	gigawatt hours
Gas	112	Bcfs (a)

(a) “Bcf” is Billion Cubic Feet.

Gains and Losses from Derivative Instruments

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):

		Three Months Ended September 30,						Nine Months Ended September 30,
Commodity Contracts	Financial Statement Location	2013			2012			2013			2012

Loss recognized in OCI on derivative instruments (effective portion)	Other comprehensive income (loss) — derivative instruments	$	(240	)	$	(119	)	$	(409	)	$	(37,513	)
Loss reclassified from AOCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(23,658		)	(49,478		)	(39,156		)	(86,993		)
Gain recognized in income (ineffective portion and amount excluded from effectiveness testing)	Fuel and purchased power (b)	—			—			—			117

(a) During the three and nine months ended September 30, 2013 and three months ended September 30, 2012, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges. During the nine months ended September 30, 2012, we had $1.8 million of losses reclassified from AOCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that a net loss of $23 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

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The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):

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		Three Months Ended September 30,					Nine Months Ended September 30,
Commodity Contracts	Financial Statement Location	2013			2012		2013			2012

Net gain recognized in income	Operating revenues (a)	$	196		$	258	$	400		$	19

Net gain (loss) recognized in income	Fuel and purchased power expense (a)	(1,341		)	12,870		(11,750		)	13,860
Total		$	(1,145	)	$	13,128	$	(11,350	)	$	13,879

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

Derivative Instruments in the Condensed Consolidated Balance Sheets

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and in the event of a default would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.

We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.

The significant majority of our derivative instruments are not currently designated as hedging instruments. The Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012, include gross liabilities of $5 million of derivative instruments designated as hedging instruments.

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The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2013 and December 31, 2012. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2013: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current Assets	$	32,201		$	(9,605	)	$	22,596		$	145		$	22,741
Investments and Other Assets	27,905			(1,859		)	26,046			—			26,046
Total Assets	60,106			(11,464		)	48,642			145			48,787

Current Liabilities	(66,680		)	32,675			(34,005		)	(19,463		)	(53,468		)
Deferred Credits and Other	(74,751		)	7,089			(67,662		)	—			(67,662		)
Total Liabilities	(141,431		)	39,764			(101,667		)	(19,463		)	(121,130		)
Total	$	(81,325	)	$	28,300		$	(53,025	)	$	(19,318	)	$	(72,343	)

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

(b) Includes cash collateral provided to counterparties of $28,300.

(c) Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $19,463, and cash margin provided to counterparties of $145.

As of December 31, 2012: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current Assets	$	42,495		$	(17,797	)	$	24,698		$	1,001		$	25,699
Investments and Other Assets	41,563			(5,672		)	35,891			—			35,891
Total Assets	84,058			(23,469		)	60,589			1,001			61,590

Current Liabilities	(105,324		)	57,046			(48,278		)	(25,463		)	(73,741		)
Deferred Credits and Other	(100,986		)	15,722			(85,264		)	—			(85,264		)
Total Liabilities	(206,310		)	72,768			(133,542		)	(25,463		)	(159,005		)
Total	$	(122,252	)	$	49,299		$	(72,953	)	$	(24,462	)	$	(97,415	)

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

(b) Includes cash collateral provided to counterparties of $49,299.

(c) Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions. Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463. This amount is not subject to offsetting.

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Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 90% of Pinnacle West’s $49 million of risk management assets as of September 30, 2013. This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on a subjective event and/or condition. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

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

	September 30, 2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	141
Cash Collateral Posted	28
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	88

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

We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $175 million if our debt credit ratings were to fall below investment grade.

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8. Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended September 30, 2013								Three Months Ended September 30, 2012
	Common Shareholders			Noncontrolling Interests		Total			Common Shareholders			Noncontrolling Interests		Total

Beginning balance, July 1	$	4,032,165		$	137,069	$	4,169,234		$	3,778,035		$	121,302	$	3,899,337

Net income	226,163			8,555		234,718			244,823			8,040		252,863
Other comprehensive income	15,122			—		15,122			30,843			—		30,843
Total comprehensive income	241,285			8,555		249,840			275,666			8,040		283,706

Issuance of capital stock	2,331			—		2,331			2,365			—		2,365
Reissuance of treasury stock — net	37			—		37			(82		)	—		(82		)
Other (primarily stock compensation)	(22		)	—		(22		)	258			—		258
Dividends on common stock	8			—		8			—			—		—
Ending balance, September 30	$	4,275,804		$	145,624	$	4,421,428		$	4,056,242		$	129,342	$	4,185,584

	Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total

Beginning balance, January 1	$	3,972,806		$	129,483		$	4,102,289		$	3,821,850		$	108,736		$	3,930,586

Net income	381,814			25,338			407,152			358,911			23,582			382,493
Other comprehensive income	24,673			—			24,673			32,688			—			32,688
Total comprehensive income	406,487			25,338			431,825			391,599			23,582			415,181

Issuance of capital stock	7,268			—			7,268			7,590			—			7,590
Reissuance (purchase) of treasury stock - net	(5,868		)	—			(5,868		)	3,277			—			3,277
Other (primarily stock compensation)	14,988			—			14,988			4,270			—			4,270
Dividends on common stock	(119,877		)	—			(119,877		)	(172,344		)	—			(172,344		)
Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,976		)	(2,976		)
Ending balance, September 30	$	4,275,804		$	145,624		$	4,421,428		$	4,056,242		$	129,342		$	4,185,584

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9. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy (“DOE”) in the United States Court of Federal Claims. The lawsuit seeks to recover APS’s damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. Activities in this legal proceeding are currently limited to review of supporting information for APS’s claim by the Government.

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

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.6 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $13.2 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential retrospective assessment per incident for all three units is approximately $111.1 million, with an annual payment limitation of approximately $16.4 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies. Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations. APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies

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totals approximately $18 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $48 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

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

	2013		2014		2015		2016		2017		Thereafter		Total
Fuel and Purchased Power	$	108	$	576	$	549	$	516	$	441	$	6,399	$	8,589

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

Superfund-Related Matters

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

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

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Southwest Power Outage

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

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

The FERC and the North American Electric Reliability Corporation (“NERC”) conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analysis and conclusions as to the causes of the events. The report includes recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report does not address potential reliability violations or an assessment of responsibility of the parties involved. APS continues to analyze business practices and procedures related to the September 8 events.

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

Litigation. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West intend to file a motion to dismiss the complaint.

Clean Air Act Lawsuit

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review (“NSR”) provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards (“NSPS”) program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order

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deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Environmental Matters

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

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

Mercury and Other Hazardous Air Pollutants. In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $120 million for Cholla Units 1-3. Estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. Salt River Project Agricultural Improvement and Power District (“SRP”), the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, greenhouse gas emissions and other rules or matters involving the Clean Air Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates

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for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Regional Haze Rules — Cholla

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan (“SIP”) and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. In addition, on February 4, 2013, APS filed a Petition for Reconsideration and Stay of the final BART rule with EPA. On March 22, 2013, APS filed a motion with the court to suspend the compliance deadlines under the BART rule until the court rules on the matter. The State of Arizona and three other Arizona utilities also filed similar petitions and motions. On September 30, 2013, the court issued an order denying these motions to suspend the compliance deadline.

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million. For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. Prior to year end, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, intend to file a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. APS believes the Assessment and the refund claim denial are without merit, but cannot predict the timing or outcome of this litigation.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2013, approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. One of these letters of credit expires in 2015 and two expire in 2016. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire on December 31, 2015, and totaled approximately $32 million at September 30, 2013. Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including certain natural gas tolling contracts entered into with third parties. At September 30, 2013, $60 million of such letters of credit were outstanding that will expire in 2014 and 2015.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification

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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.

Pinnacle West has issued parental guarantees and surety bonds for APS which were not material at September 30, 2013.

10. Other Income and Other Expense

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Other income:
Interest income	$	116		$	307		$	1,291		$	1,018
Miscellaneous	44			113			96			339
Total other income	$	160		$	420		$	1,387		$	1,357

Other expense:
Non-operating costs	$	(2,028	)	$	(1,645	)	$	(5,951	)	$	(5,885	)
Investment losses — net	(3,435		)	(2,254		)	(3,643		)	(2,366		)
Miscellaneous	(1,972		)	(1,797		)	(3,827		)	(4,182		)
Total other expense	$	(7,435	)	$	(5,696	)	$	(13,421	)	$	(12,433	)

11. Earnings Per Share

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	2.06	$	2.23	$	3.47	$	3.29
Loss from discontinued operations	—		—		—		(0.01		)
Earnings per share — basic	$	2.06	$	2.23	$	3.47	$	3.28

Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	2.04	$	2.21	$	3.44	$	3.26
Loss from discontinued operations	—		—		—		(0.01		)
Earnings per share — diluted	$	2.04	$	2.21	$	3.44	$	3.25

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Performance shares and restricted stock units (which are contingently issuable) increased the weighted average common shares outstanding by approximately 1,044,000 shares and 1,100,000 shares for the three months ended September 30, 2013 and 2012, respectively, and by approximately 978,000 shares and 971,000 shares for the nine months ended September 30, 2013 and 2012, respectively.

For the three and nine months ended September 30, 2013 and 2012, there were no common stock options that were excluded from the computation of diluted earnings per share as a result of the options’ exercise prices being greater than the average market price of the common shares.

12. Fair Value Measurements

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

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

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

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is

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binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 in the 2012 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

Cash equivalents represent short-term investments with original maturities of three months or less in exchange-traded money market funds that are valued using quoted prices in active markets.

Risk Management Activities — Derivative Instruments

Exchange-traded commodity contracts are valued using unadjusted quoted prices. For non-exchange-traded commodity contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.

Certain non-exchange-traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

Option contracts are primarily valued using a Black-Scholes option valuation model which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.

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Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization.

Investments Held in our Nuclear Decommissioning Trust

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

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

Fixed income securities issued by the United States Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained, which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.

Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services that utilize the valuation methodologies described to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 13 for additional discussion about our nuclear decommissioning trust.

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Fair Value Tables

The following table presents the fair value at September 30, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at September 30, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	12		$	48		$	(11	)(b)	$	49
Nuclear decommissioning trust:
U.S. commingled equity funds	—		245			—			—			245
Fixed income securities:
U.S. Treasury	109		—			—			—			109
Cash and cash equivalent funds	—		13			—			(3		)(c)	10
Corporate debt	—		83			—			—			83
Mortgage-backed securities	—		82			—			—			82
Municipality bonds	—		71			—			—			71
Other	—		13			—			—			13
Subtotal nuclear decommissioning trust	109		507			—			(3		)	613
Total	$	109	$	519		$	48		$	(14	)	$	662

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(49	)	$	(92	)	$	20	(b)	$	(121	)

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

(b) Primarily represents counterparty netting, margin and collateral (see Note 7).

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

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at December 31, 2012
Assets
Cash equivalents	$	16	$	—		$	—		$	—		$	16
Risk management activities — derivative instruments:
Commodity Contracts	—		22			62			(22		)(b)	62
Nuclear decommissioning trust:
U.S. commingled equity funds	—		204			—			—			204
Fixed income securities:
U.S. Treasury	104		—			—			—			104
Cash and cash equivalent funds	6		13			—			(4		)(c)	15
Corporate debt	—		80			—			—			80
Mortgage-backed securities	—		83			—			—			83
Municipality bonds	—		74			—			—			74
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	110		465			—			(4		)	571
Total	$	126	$	487		$	62		$	(26	)	$	649

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(96	)	$	(110	)	$	47	(b)	$	(159	)

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

(b) Represents counterparty netting, margin and collateral (see Note 7).

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net

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fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The significant unobservable inputs for these instruments include electricity prices, gas prices and volatilities. If electricity prices and electricity price volatilities increase, we would expect the impact on the fair value of these options to increase, and if these valuation inputs decrease, we would expect the impact on the fair value of these options to decrease. If natural gas prices and natural gas price volatilities increase, we would expect the impact on the fair value of these options to decrease, and if these inputs decrease, we would expect the impact on the fair value of the options to increase. The commodity prices and volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs.

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

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

	September 30, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	47	$	74	Discounted cash flows	Electricity forward price (per MWh)	$24.55 – $60.97	$	40.23

Option Contracts (b)	—		16		Option model	Electricity forward price (per MWh)	$38.56 – $82.07	$	55.74
						Electricity price volatilities	51% – 106%	74		%
						Natural gas forward price	$3.82 – $3.96	$	3.91
						Natural gas price volatilities	24% – 51%	31		%
Natural Gas:
Forward Contracts (a)	1		2		Discounted cash flows	Natural gas forward price (per mmbtu)	$3.31 – $4.25	$	3.97
Total	$	48	$	92

(a) Includes swaps and physical and financial contracts.

(b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.

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	December 31, 2012 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	57	$	82	Discounted cash flows	Electricity forward price (per MWh)	$23.06 – $64.20	$	43.16

Option Contracts	—		27		Option model	Electricity forward price (per MWh)	$36.66 – $92.19	$	60.97
						Natural gas forward price (per mmbtu)	$4.10 – $4.25	$	4.20
						Implied electricity price volatilities	15% – 66%	39		%
						Implied natural gas price volatilities	17% – 36%	23		%
Natural Gas:
Forward Contracts (a)	5		1		Discounted cash flows	Natural gas forward price (per mmbtu)	$3.25 – $4.44	$	3.93
Total	$	62	$	110

(a) Includes swaps and physical and financial contracts.

The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2013 and 2012 (dollars in millions):

Commodity Contracts	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net derivative balance at beginning of period	$	(53	)	$	(45	)	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—			—			2
Included in OCI	—			—			—			(2		)
Deferred as a regulatory asset or liability	4			(3		)	(2		)	4
Settlements	6			(1		)	8			(1		)
Transfers into Level 3 from Level 2	(1		)	(4		)	(1		)	(2		)
Transfers from Level 3 into Level 2	—			3			(1		)	—
Net derivative balance at end of period	$	(44	)	$	(50	)	$	(44	)	$	(50	)

Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

Amounts included in earnings are recorded in either operating revenues or purchased power depending on the nature of the underlying contract.

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

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

Financial Instruments Not Carried at Fair Value

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

13. Nuclear Decommissioning Trusts

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. See Note 12 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2013 and December 31, 2012 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
September 30, 2013
Equity securities	$	245		$	104	$	—
Fixed income securities	371			13		(5		)
Net payables (a)	(3		)	—		—
Total	$	613		$	117	$	(5	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2012
Equity securities	$	204		$	67	$	—
Fixed income securities	371			24		—
Net payables (a)	(4		)	—		—
Total	$	571		$	91	$	—

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

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The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Realized gains	$	1		$	1		$	4		$	5
Realized losses	(3		)	(1		)	(5		)	(3		)
Proceeds from the sale of securities (a)	110			84			364			295

(a) Proceeds are reinvested in the trust.

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

	Fair Value
Less than one year	$	12
1 year - 5 years	106
5 years - 10 years	104
Greater than 10 years	149
Total	$	371

14. New Accounting Standards

During 2013, we adopted, on a retrospective basis, new guidance relating to balance sheet offsetting disclosures. The new guidance requires enhanced disclosures regarding an entity’s ability to offset certain instruments on the balance sheet and how offsetting impacts the balance sheet. The adoption of this guidance resulted in expanded disclosures relating to our derivative instruments (see Note 7), but did not impact our financial statement results.

During 2013, we also adopted, on a prospective basis, new guidance relating to reporting amounts reclassified from AOCI. This guidance requires new disclosures relating to AOCI and how reclassifications from AOCI impact net income. As a result of adopting this new guidance, we have included a new footnote disclosure to provide the information required by the new standard (see Notes 15 and S-3). The adoption of this guidance did not impact our financial statement results.

In July 2013, new guidance was issued which will generally require entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. The new guidance is effective for us on January 1, 2014, with early application permitted. We are currently evaluating the impacts of this new guidance. The adoption of this new guidance may impact our balance sheet presentation, but will not impact our results of operations or cash flows.

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15. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2013 (dollars in thousands):

	Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total

Beginning balance	$	(40,319	)	$	(64,138	)	$	(104,457	)	$	(49,592	)	$	(64,416	)	$	(114,008	)

Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,635		)	(1,882		)

Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	957		(b)	15,267			23,685		(a)	2,870		(b)	26,555

Net current period other comprehensive income	14,165			957			15,122			23,438			1,235			24,673

Ending balance	$	(26,154	)	$	(63,181	)	$	(89,335	)	$	(26,154	)	$	(63,181	)	$	(89,335	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended September 30,
	2013			2012

ELECTRIC OPERATING REVENUES	$	1,151,535		$	1,108,623

OPERATING EXPENSES
Fuel and purchased power	350,953			302,894
Operations and maintenance	222,617			218,403
Depreciation and amortization	107,364			100,329
Income taxes	143,335			153,797
Taxes other than income taxes	43,015			36,255
Total	867,284			811,678
OPERATING INCOME	284,251			296,945

OTHER INCOME (DEDUCTIONS)
Income taxes	4,123			3,170
Allowance for equity funds used during construction	5,569			5,708
Other income (Note S-2)	721			815
Other expense (Note S-2)	(4,615		)	(3,352		)
Total	5,798			6,341

INTEREST EXPENSE
Interest on long-term debt	47,214			48,841
Interest on short-term borrowings	1,553			1,334
Debt discount, premium and expense	1,008			1,070
Allowance for borrowed funds used during construction	(3,235		)	(3,830		)
Total	46,540			47,415

NET INCOME	243,509			255,871

Less: Net income attributable to noncontrolling interests (Note 6)	8,555			8,040

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	234,954		$	247,831

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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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended September 30,
	2013			2012

NET INCOME	$	243,509		$	255,871

OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $95 and $47	(145		)	(72		)
Reclassification of net realized loss, net of tax benefit of $9,348 and $19,547	14,310			29,931
Pension and other postretirement benefits activity, net of tax (expense) of $(621) and $(568)	951			869
Total other comprehensive income	15,116			30,728

COMPREHENSIVE INCOME	258,625			286,599
Less: Comprehensive income attributable to noncontrolling interests	8,555			8,040

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	250,070		$	278,559

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 INCOME

(unaudited)

(dollars in thousands)

	Nine Months Ended September 30,
	2013			2012

ELECTRIC OPERATING REVENUES	$	2,752,427		$	2,606,458

OPERATING EXPENSES
Fuel and purchased power	859,216			783,926
Operations and maintenance	668,319			640,596
Depreciation and amortization	317,338			300,997
Income taxes	241,347			233,679
Taxes other than income taxes	123,366			119,499
Total	2,209,586			2,078,697
OPERATING INCOME	542,841			527,761

OTHER INCOME (DEDUCTIONS)
Income taxes	9,555			6,906
Allowance for equity funds used during construction	18,698			15,639
Other income (Note S-2)	3,012			2,343
Other expense (Note S-2)	(15,755		)	(11,969		)
Total	15,510			12,919

INTEREST EXPENSE
Interest on long-term debt	140,978			150,416
Interest on short-term borrowings	4,950			5,283
Debt discount, premium and expense	3,001			3,182
Allowance for borrowed funds used during construction	(10,861		)	(10,428		)
Total	138,068			148,453

NET INCOME	420,283			392,227

Less: Net income attributable to noncontrolling interests (Note 6)	25,338			23,573

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	394,945		$	368,654

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)

	Nine Months Ended September 30,
	2013			2012

NET INCOME	$	420,283		$	392,227

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $162 and $14,820	(247		)	(22,693		)
Reclassification of net realized loss, net of tax benefit of $15,471 and $34,367	23,684			52,625
Pension and other postretirement benefits activity, net of tax (expense) of $(798) and $(1,409)	1,222			2,158
Total other comprehensive income	24,659			32,090

COMPREHENSIVE INCOME	444,942			424,317

Less: Comprehensive income attributable to noncontrolling interests	25,338			23,573

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	419,604		$	400,744

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)

	September 30,			December 31,
	2013			2012
ASSETS

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	14,594,129		$	14,342,501
Accumulated depreciation and amortization	(5,097,804		)	(4,925,990		)
Net	9,496,325			9,416,511

Construction work in progress	605,987			565,716
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	126,092			128,995
Intangible assets, net of accumulated amortization	159,979			161,995
Nuclear fuel, net of accumulated amortization	140,356			122,778
Total property, plant and equipment	10,528,739			10,395,995

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	612,640			570,625
Assets from risk management activities (Note 7)	26,046			35,891
Other assets	33,203			31,650
Total investments and other assets	671,889			638,166

CURRENT ASSETS
Cash and cash equivalents	113,072			3,499
Customer and other receivables	426,425			274,815
Accrued unbilled revenues	132,555			94,845
Allowance for doubtful accounts	(3,768		)	(3,340		)
Materials and supplies (at average cost)	223,385			218,096
Income tax receivable	126,098			589
Fossil fuel (at average cost)	34,959			31,334
Deferred fuel and purchased power regulatory asset (Note 3)	37,383			72,692
Other regulatory assets (Note 3)	82,558			71,257
Deferred income taxes	538			74,420
Assets from risk management activities (Note 7)	22,741			25,699
Other current assets	35,983			37,077
Total current assets	1,231,929			900,983

DEFERRED DEBITS
Regulatory assets (Note 3)	1,105,882			1,099,900
Unamortized debt issue costs	22,367			22,492
Income tax receivable (Note 5)	—			70,784
Other	114,995			114,222
Total deferred debits	1,243,244			1,307,398

TOTAL ASSETS	$	13,675,801		$	13,242,542

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)

	September 30,			December 31,
	2013			2012
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,899,375			1,624,237
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(38,281		)	(39,503		)
Derivative instruments	(26,155		)	(49,592		)
Total shareholder equity	4,392,797			4,093,000
Noncontrolling interests (Note 6)	145,624			129,483
Total equity (Note S-1)	4,538,421			4,222,483
Long-term debt less current maturities (Note 2)	2,657,901			3,035,219
Palo Verde sale leaseback lessor notes less current maturities (Note 6)	37,414			38,869
Total capitalization	7,233,736			7,296,571

CURRENT LIABILITIES
Short-term borrowings	—			92,175
Current maturities of long-term debt (Note 2)	566,481			122,828
Accounts payable	243,470			215,577
Accrued taxes (Note 5)	178,349			116,700
Accrued interest	45,542			49,135
Common dividends payable	—			59,800
Customer deposits	77,254			79,689
Liabilities from risk management activities (Note 7)	53,468			73,741
Regulatory liabilities (Note 3)	88,409			88,116
Other current liabilities	152,392			145,326
Total current liabilities	1,405,365			1,043,087

DEFERRED CREDITS AND OTHER
Deferred income taxes	2,337,320			2,133,976
Regulatory liabilities (Note 3)	798,226			759,201
Liability for asset retirements	364,635			357,097
Liabilities for pension and other postretirement benefits (Note 4)	901,146			1,017,556
Deferred investment tax credit	115,984			99,819
Liabilities from risk management activities (Note 7)	67,662			85,264
Customer advances	109,667			109,359
Coal mine reclamation	114,764			118,860
Unrecognized tax benefits (Note 5)	81,589			70,932
Other	145,707			150,820
Total deferred credits and other	5,036,700			4,902,884

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

TOTAL LIABILITIES AND EQUITY	$	13,675,801		$	13,242,542

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)

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	420,283		$	392,227
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	377,899			360,499
Deferred fuel and purchased power	13,093			51,533
Deferred fuel and purchased power amortization	23,158			(91,894		)
Allowance for equity funds used during construction	(18,698		)	(15,639		)
Deferred income taxes	256,253			222,251
Deferred investment tax credit	16,164			8,974
Change in derivative instruments fair value	537			(943		)
Changes in current assets and liabilities:
Customer and other receivables	(179,494		)	(79,152		)
Accrued unbilled revenues	(37,710		)	(11,186		)
Materials, supplies and fossil fuel	(8,914		)	(23,873		)
Income tax receivable	(125,509		)	(775		)
Other current assets	(11,449		)	(10,446		)
Accounts payable	43,886			(72,802		)
Accrued taxes	61,649			62,834
Other current liabilities	1,073			112
Change in margin and collateral accounts — assets	(327		)	1,980
Change in margin and collateral accounts — liabilities	15,000			114,579
Change in unrecognized tax benefits	(57,585		)	(3,554		)
Change in long-term income tax receivable	137,665			(1,320		)
Change in other long-term assets	(28,686		)	(17,185		)
Change in other long-term liabilities	691			36,451
Net cash flow provided by operating activities	898,979			922,671

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(581,515		)	(670,684		)
Contributions in aid of construction	34,910			41,451
Allowance for borrowed funds used during construction	(10,861		)	(10,428		)
Proceeds from nuclear decommissioning trust sales	363,944			295,126
Investment in nuclear decommissioning trust	(376,881		)	(308,063		)
Other	(1,561		)	(520		)
Net cash flow used for investing activities	(571,964		)	(653,118		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307			351,081
Short-term borrowings — net	(92,175		)	—
Repayment of long-term debt	(72,777		)	(421,703		)
Dividends paid on common stock	(179,600		)	(162,400		)
Noncontrolling interests	(9,197		)	(2,630		)
Net cash flow used for financing activities	(217,442		)	(235,652		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	109,573			33,901
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,499			19,873
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	113,072		$	53,774
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid	$	3,412		$	—
Interest, net of amounts capitalized	138,626			149,338
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	11,377		$	11,281

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	—
Income Taxes	Note 5	—
Palo Verde Sale Leaseback Variable Interest Entities	Note 6	—
Derivative Accounting	Note 7	—
Changes in Equity	Note 8	Note S-1
Commitments and Contingencies	Note 9	—
Other Income and Other Expense	Note 10	Note S-2
Earnings Per Share	Note 11	—
Fair Value Measurements	Note 12	—
Nuclear Decommissioning Trusts	Note 13	—
New Accounting Standards	Note 14	—
Changes in Accumulated Other Comprehensive Income	Note 15	Note S-3

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. Changes in Equity

The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):

	Three Months Ended September 30, 2013							Three Months Ended September 30, 2012
	Shareholder Equity		Noncontrolling Interests			Total		Shareholder Equity		Noncontrolling Interests		Total

Beginning balance, July 1	$	4,142,726	$	137,070		$	4,279,796	$	3,902,791	$	121,302	$	4,024,093

Net income	234,954		8,555			243,509		247,831		8,040		255,871
OCI	15,116		—			15,116		30,728		—		30,728
Total comprehensive income	250,070		8,555			258,625		278,559		8,040		286,599

Other	1		(1		)	—		1		—		1
Ending balance, September 30	$	4,392,797	$	145,624		$	4,538,421	$	4,181,351	$	129,342	$	4,310,693

	Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total

Beginning balance, January 1	$	4,093,000		$	129,483		$	4,222,483		$	3,943,007		$	108,399		$	4,051,406

Net income	394,945			25,338			420,283			368,654			23,573			392,227
OCI	24,659			—			24,659			32,090			—			32,090
Total comprehensive income	419,604			25,338			444,942			400,744			23,573			424,317

Dividends on common stock	(119,800		)	—			(119,800		)	(162,400		)	—			(162,400		)
Net capital activities by noncontrolling interests	—			(9,197		)	(9,197		)	—			(2,630		)	(2,630		)
Other	(7		)	—			(7		)	—			—			—
Ending balance, September 30	$	4,392,797		$	145,624		$	4,538,421		$	4,181,351		$	129,342		$	4,310,693

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-2. Other Income and Other Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Other income:
Interest income	$	2		$	61		$	1,061		$	244
Miscellaneous	719			754			1,951			2,099
Total other income	$	721		$	815		$	3,012		$	2,343

Other expense:
Non-operating costs (a)	$	(2,263	)	$	(2,007	)	$	(6,868	)	$	(6,690	)
Asset dispositions	(1,203		)	(248		)	(3,864		)	(666		)
Miscellaneous	(1,149		)	(1,097		)	(5,023		)	(4,613		)
Total other expense	$	(4,615	)	$	(3,352	)	$	(15,755	)	$	(11,969	)

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

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-3. Changes in Accumulated Other Comprehensive Loss

	Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total

Beginning balance	$	(40,320	)	$	(39,232	)	$	(79,552	)	$	(49,592	)	$	(39,503	)	$	(89,095	)

Other comprehensive loss before reclassifications	(145		)	—			(145		)	(247		)	(1,630		)	(1,877		)

Amounts reclassified from accumulated other comprehensive loss	14,310		(a)	951		(b)	15,261			23,684		(a)	2,852		(b)	26,536

Net current period other comprehensive income	14,165			951			15,116			23,437			1,222			24,659

Ending balance	$	(26,155	)	$	(38,281	)	$	(64,436	)	$	(26,155	)	$	(38,281	)	$	(64,436	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4.

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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 1, Item 1A of the 2012 Form 10-K.

OVERVIEW

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

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

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

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

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

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Four Corners

Asset Purchase Agreement Terms and Approvals. SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant. On November 8, 2010, APS and SCE entered into an asset purchase agreement (“Asset Purchase Agreement”), providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The purchase price is $294 million, subject to certain adjustments. The Asset Purchase Agreement provides that the purchase price will be reduced by $7.5 million for each month between October 1, 2012 and the closing date. Completion of the purchase by APS is subject to the receipt of approvals by the ACC, the California Public Utilities Commission (“CPUC”) and the FERC. On March 29, 2012, the CPUC issued an order approving the sale. On April 18, 2012, the ACC voted to allow APS to move forward with the purchase. The ACC also authorized an accounting deferral of certain costs associated with the purchase until any such cost recovery proceeding concludes. The ACC reserved the right to review the prudence of the transaction for cost recovery purposes in a future proceeding if the purchase closes. APS intends to file an application to request rate adjustments prior to its next general rate case related to APS’s acquisition of SCE’s interest in Four Corners, assuming the transaction is consummated. APS cannot predict the outcome of this request.

The FERC application seeking authorization for the transaction was approved on November 27, 2012. The principal remaining condition to closing stated in the Asset Purchase Agreement is the negotiation and execution of a new coal supply contract on terms reasonably acceptable to APS.

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

Pollution Control Investments. As disclosed in our 2012 Form 10-K, EPA, in its final regional haze rule for Four Corners, set a date of July 1, 2013 for the Four Corners’ owners to elect one of two emissions alternatives to apply to Four Corners. Either alternative would involve substantial investment by the owners in additional post-combustion pollution controls, and accordingly contemplates the continued operation of Four Corners for a substantial period of time. On September 24, 2013, EPA extended the date by which the Four Corners participants must notify EPA of their chosen BART compliance strategy from July 1 to December 31, 2013.

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

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

Pursuant to the Asset Purchase Agreement, because all of the closing conditions were not originally satisfied by December 31, 2012, either APS or SCE has a right to terminate the Agreement, unless the party seeking to terminate is then in breach of the Agreement. APS cannot predict whether the closing conditions will be satisfied such that closing of its planned purchase of SCE’s interest in Four Corners can occur.

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

Renewable Energy. The ACC approved the RES in 2006. The renewable energy requirement is 4% of retail electric sales in 2013 and increases annually until it reaches 15% in 2025. In the settlement agreement related to the 2008 retail rate case, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 1,700 gigawatt hours of new renewable resources to be in service by year-end 2015, in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is currently estimated to be approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year. We expect renewable energy, including rooftop solar, to meet approximately 7% of our retail energy sales for 2013. A component of the RES targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of between $97 million and $107 million. In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan. That budget included $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for new commercial distributed energy production-based incentives beyond those for previously approved programs. The ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. In those proceedings, the ACC staff proposed a solution whereby if a customer installs distributed generation without an incentive, the customer keeps the renewable energy credits generated

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and the RES distributed generation requirement is adjusted downward to reflect how much load is being served by renewable generation. APS has endorsed the ACC staff’s proposed solution. Finally, the ACC authorized an APS-led multi-session technical conference to consider APS’s net metering policy and the costs and benefits of distributed energy. The multi-session technical conference concluded on May 28, 2013.

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either: (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price. APS also proposed that the ACC: (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations. In its September 20, 2013 report, the ACC staff recognized that net metering shifts costs from solar customers to non-solar customers. The ACC staff recommended that the ACC wait until APS’s next rate case to fully address the issue. As an alternative, the ACC staff recommended that the ACC assess one of two modest charges on new solar customers with a mechanism to return all incremental revenue collected from such charges to customers.

On July 12, 2013, APS filed its annual RES implementation plan covering the 2014-2018 timeframe. The plan requests a budget for 2014 of approximately $143 million. The plan does not propose any new programs. Rather, the plan requests the funding necessary to fulfill previously approved projects and commitments which are needed to comply with the RES targets and APS’s obligations under its 2008 rate case settlement agreement approved by the ACC, including the remaining 50 MW of AZ Sun. On September 30, 2013, the ACC staff issued a report recommending approval of APS’s plan and proposed budget.

The following table summarizes APS’s renewable energy sources in operation and under development as of October 31, 2013.

	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar (a)	101	69

Purchased Power Agreements:
Solar (b)	280	30
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	599	30

Total Distributed Energy: Solar (c)	277	65

Total Renewable Portfolio	977	164

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(a) Through the ACC-approved AZ Sun Program, APS has executed contracts for the development of 150 MW of new solar generation, representing an investment commitment of approximately $609 million.

(b) Includes 250 MW from the Solana Generating Station, which achieved commercial operation in October 2013.

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

Demand Side Management. In recent years, Arizona regulators have placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. In December 2009, the ACC initiated an Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. This ambitious standard became effective on January 1, 2011. The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs. This amount will be recovered by the then-existing DSMAC over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).

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

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

As part of APS’s proposed acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing transmission agreement between the parties that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California. On

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May 1, 2013, APS submitted a request with FERC seeking authorization to cancel the transmission agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 10-year period. On September 13, 2013, FERC issued an Order accepting the notice of cancellation, but denying APS’s request for rate recovery of the costs associated with the cancellation. In accordance with its Termination Agreement with SCE, APS believes that the denial by FERC of such rate recovery constitutes the failure of a condition that relieves APS of its obligation under the Termination Agreement. The parties are in discussions concerning this matter. If the matter is not resolved by negotiation, the Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter.

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

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

Key Financial Drivers

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

Electric Operating Revenues. For the years 2010 through 2012, retail electric revenues comprised approximately 93% of our total electric operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery

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mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth. Retail customer growth in APS’s service territory for the nine-month period ended September 30, 2013 was 1.3% compared with the comparable prior-year period. For the three years 2010 through 2012, APS’s customer growth averaged 0.7% per year. We currently expect annual customer growth to average about 2% for 2013 through 2015 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, decreased 0.1% for the nine-month period ended September 30, 2013 compared with the prior-year period, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, offset by mildly improving economic conditions. For the three years 2010 through 2012, APS experienced annual declines in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kilowatt-hours will increase on average by less than one percent during 2013 through 2015, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. A failure of the Arizona economy to continue to improve could further impact these estimates.

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

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

Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Condensed Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

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

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

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.4% of the assessed value for 2013 and 9.6% for 2012. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities. (See Note 3 for property tax deferrals contained in the Settlement Agreement).

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

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

RESULTS OF OPERATIONS

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

Operating Results

Three-month period ended September 30, 2013 compared with three-month period ended September 30, 2012. Our consolidated net income attributable to common shareholders for the three months ended September 30, 2013 was $226 million, compared with net income of $245 million for the prior-year period. The results reflect a decrease of approximately $18 million for the regulated electricity segment primarily due to lower retail sales as a result of changes in customer usage related to energy efficiency, customer conservation and distributed generation, partially offset by customer growth; higher operations and maintenance expenses; higher depreciation and amortization expenses; and higher property taxes; partially offset by lower income taxes.

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

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	Three Months Ended September 30,
	2013			2012			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	801		$	806		$	(5	)
Operations and maintenance	(234		)	(221		)	(13		)
Depreciation and amortization	(107		)	(100		)	(7		)
Taxes other than income taxes	(43		)	(37		)	(6		)
Other income (expenses), net	—			2			(2		)
Interest charges, net of allowance for borrowed funds used during construction	(47		)	(48		)	1
Income taxes	(133		)	(148		)	15
Less income related to noncontrolling interests (Note 6)	(9		)	(8		)	(1		)
Regulated electricity segment net income	228			246			(18		)

All other	(2		)	(1		)	(1		)

Net Income Attributable to Common Shareholders	$	226		$	245		$	(19	)

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $5 million lower for the three months ended September 30, 2013 compared with the prior-year period. The following table summarizes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)

Lower retail sales due to changes in customer usage, partially offset by customer growth	$	(21	)	$	(4	)	$	(17	)
Higher fuel and purchased power costs, net of related deferrals and off-system sales	49			48			1
Effects of weather	6			2			4
Higher demand-side management, renewable energy and similar regulatory surcharges	10			—			10
Miscellaneous items, net	(1		)	2			(3		)
Total	$	43		$	48		$	(5	)

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

· An increase of $9 million related to communication and other costs associated with net metering and deregulation;

· An increase of $6 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues;

· A decrease of $5 million in generation costs primarily due to lower power plant maintenance costs as a result of less work being completed in the third quarter of 2013 compared with the third quarter of 2012; and

· An increase of $3 million related to other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $7 million higher for the three months ended September 30, 2013 compared with the prior-year period primarily because of increased plant in service.

Taxes other than income taxes. Taxes other than income taxes were $6 million higher for the three months ended September 30, 2013 compared with the prior-year period primarily because of higher property tax rates in the current year.

Income taxes. Income taxes were $15 million lower for the three months ended September 30, 2013 compared with the prior-year period primarily due to lower pretax income in the current period.

Nine-month period ended September 30, 2013 compared with nine-month period ended September 30, 2012. Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2013 was $382 million, compared with net income of $359 million for the prior-year period. The results reflect an increase of approximately $21 million for the regulated electricity segment primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3); higher retail transmission revenues; lower net interest charges due to lower debt balances and lower interest rates in the current-year period; and the effects of weather. These positive factors were partially offset by higher operations and maintenance expenses; higher fuel and purchased power costs, net of related deferrals; and higher depreciation and amortization expenses.

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

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	Nine Months Ended September 30,
	2013			2012			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,893		$	1,823		$	70
Operations and maintenance	(686		)	(648		)	(38		)
Depreciation and amortization	(317		)	(301		)	(16		)
Taxes other than income taxes	(124		)	(120		)	(4		)
Other income (expenses), net	8			7			1
Interest charges, net of allowance for borrowed funds used during construction	(141		)	(152		)	11
Income taxes	(223		)	(221		)	(2		)
Less income related to noncontrolling interests (Note 6)	(25		)	(24		)	(1		)
Regulated electricity segment net income	385			364			21

All other	(3		)	(4		)	1
Income from Continuing Operations Attributable to Common Shareholders	382			360			22

Loss from Discontinued Operations Attributable to Common Shareholders (a)	—			(1		)	1

Net Income Attributable to Common Shareholders	$	382		$	359		$	23

(a) Includes activities related to SunCor.

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $70 million higher for the nine months ended September 30, 2013 compared with the prior-year period. The following table summarizes the major components of this change:

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	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)

Impacts of retail regulatory settlement effective July 1, 2012	$	60		$	5		$	55
Higher demand-side management, renewable energy and similar regulatory surcharges	25			5			20
Higher retail transmission revenues	18			—			18
Effects of weather	13			6			7
Lower retail sales due to changes in customer usage patterns and related pricing, partially offset by customer growth	(7		)	(1		)	(6		)
Higher fuel and purchased power costs, net of related deferrals and off-system sales	45			65			(20		)
Miscellaneous items, net	(8		)	(4		)	(4		)
Total	$	146		$	76		$	70

Operations and maintenance. Operations and maintenance expenses increased $38 million for the nine months ended September 30, 2013 compared with the prior-year period primarily because of:

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

· An increase of $10 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues;

· An increase of $9 million related to communication and other costs associated with net metering and deregulation;

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

· A decrease of $9 million in generation costs primarily related to lower fossil generation outage costs; and

· An increase of $3 million related to other miscellaneous factors.

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Depreciation and amortization. Depreciation and amortization expenses were $16 million higher for the nine months ended September 30, 2013 compared with the prior-year period primarily because of increased plant in service.

Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction, decreased $11 million for the nine months ended September 30, 2013 compared with the prior-year period primarily because of lower debt balances and lower interest rates in the current period.

LIQUIDITY AND CAPITAL RESOURCES

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

Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2013, APS’s common equity ratio, as defined, was 58%. Its total shareholder equity was approximately $4.4 billion, and total capitalization was approximately $7.6 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

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

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

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Summary of Cash Flows

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

Pinnacle West Consolidated

	Nine Months Ended September 30,						Net
	2013			2012			Change
Net cash flow provided by operating activities	$	882		$	929		$	(47	)
Net cash flow used for investing activities	(572		)	(653		)	81
Net cash flow used for financing activities	(201		)	(230		)	29
Net increase in cash and cash equivalents	$	109		$	46		$	63

Arizona Public Service Company

	Nine Months Ended September 30,						Net
	2013			2012			Change
Net cash flow provided by operating activities	$	899		$	923		$	(24	)
Net cash flow used for investing activities	(572		)	(653		)	81
Net cash flow used for financing activities	(217		)	(236		)	19
Net increase in cash and cash equivalents	$	110		$	34		$	76

Operating Cash Flows

Nine-month period ended September 30, 2013 compared with nine-month period ended September 30, 2012. Pinnacle West’s consolidated net cash provided by operating activities was $882 million in 2013, compared to $929 million in 2012, a decrease of $47 million in net cash provided. The decrease is primarily related to a $102 million change in cash collateral posted and $99 million of higher pension contributions made in the nine-month period ended September 30, 2013 compared to the same period in 2012 (approximately $23 million of which is reflected in capital expenditures). The decrease is partially offset by approximately $131 million of higher cash inflows due to the increase in pre-tax income primarily driven by higher authorized revenue requirements resulting from the retail regulatory settlement effective July 1, 2012 and other changes in working capital.

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

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contributions). Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We have made voluntary contributions of $141 million to our pension plan in 2013. The minimum contributions for the pension plan due in 2013, 2014 and 2015 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero, $89 million and $112 million, respectively. We expect to make contributions to the pension plan up to approximately $175 million each year in 2014 and 2015. We have contributed $11 million to our other postretirement benefit plans in 2013. The total contributions to our other postretirement benefit plans are expected to be approximately $14 million in 2013 and approximately $20 million each year in 2014 and 2015.

The $70 million long-term income tax receivable on the Condensed Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt. As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter. This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities. The net $137 million anticipated refund is expected to be received within the next twelve months and has been reclassified to current income tax receivable as of September 30, 2013.

Investing Cash Flows

Nine-month period ended September 30, 2013 compared with nine-month period ended September 30, 2012. Pinnacle West’s consolidated net cash used for investing activities was $572 million in 2013, compared to $653 million in 2012, a decrease of $81 million in net cash used. The decrease in net cash used for investing activities is primarily due to a decrease of approximately $83 million in capital expenditures.

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

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2013		2014		2015
APS
Generation:
Nuclear Fuel	$	56	$	80	$	86
Renewables	182		41		—
Environmental	21		63		142
Four Corners Units 4 and 5	224		—		—
Other Generation	137		223		254
Distribution	249		252		374
Transmission	138		201		213
Other (a)	48		49		41
Total APS	$	1,055	$	909	$	1,110

(a) Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’s existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment. For purposes of this table, we have assumed the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shutdown of Units 1-3, as discussed in the “Overview” section above. As a result, we included the estimated $224 million purchase price under Generation and have not included environmental expenditures for Units 1-3. We have not included estimated costs for Cholla’s compliance with EPA’s regional haze rule since we have challenged the rule judicially and are considering our future options with respect to that plant if the rule is upheld. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures.

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

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

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Financing Cash Flows and Liquidity

Nine-month period ended September 30, 2013 compared with nine-month period ended September 30, 2012. Pinnacle West’s consolidated net cash used for financing activities was $201 million in 2013, compared to $230 million of net cash used in 2012, a decrease of $29 million in net cash used. The decrease in net cash used for financing activities is primarily due to $349 million in lower repayments of long-term debt, largely offset by $215 million in lower issuances of long-term debt and a $92 million net change in APS’s short-term borrowings (see below).

Significant Financing Activities. On October 23, 2013, the Pinnacle West Board of Directors declared a quarterly dividend of $0.5675 per share of common stock, payable on December 2, 2013, to shareholders of record on November 4, 2013. This represents an increase in the indicated annual dividend from $2.18 per share to $2.27 per share.

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2012.

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

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

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

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

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

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At September 30, 2013, the ratio was approximately 44% for Pinnacle West and 43% 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

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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 October 28, 2013 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	Baa2	BBB+	BBB+
Commercial paper	P-3	A-2	F2
Outlook	Stable	Stable	Stable

APS
Corporate credit rating	Baa1	BBB+	BBB+
Senior unsecured	Baa1	BBB+	A-
Secured lease obligation bonds	Baa1	BBB+	A-
Commercial paper	P-2	A-2	F2
Outlook	Stable	Stable	Stable

Off-Balance Sheet Arrangements

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

Financial Assurances

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

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Contractual Obligations

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

	2013		2014-2015		2016-2017		Thereafter		Total
Fuel and purchased power	$	108	$	1,125	$	957	$	6,399	$	8,589

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

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

CRITICAL ACCOUNTING POLICIES

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

OTHER ACCOUNTING MATTERS

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

MARKET AND CREDIT RISKS

Market Risks

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

Interest Rate and Equity Risk

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

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Commodity Price Risk

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

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

	Nine Months Ended September 30,
	2013			2012
Mark-to-market of net positions at beginning of period	$	(122	)	$	(222	)
Recognized in earnings (a):
Change in mark-to-market losses for future period deliveries	—			1
Decrease in regulatory asset	2			50
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (b)	—			(37		)
Mark-to-market losses realized during the period	39			87
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(81	)	$	(121	)

(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 September 30, 2013 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” in Item 8 of our 2012 Form 10-K and Note 12 for more discussion of our valuation methods.

Source of Fair Value	2013			2014			2015			2016			2017			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(6	)	$	(24	)	$	(5	)	$	(2	)	$	—		$	—		$	(37	)
Prices based on unobservable inputs	(2		)	(10		)	(10		)	(9		)	(5		)	(8		)	(44		)
Total by maturity	$	(8	)	$	(34	)	$	(15	)	$	(11	)	$	(5	)	$	(8	)	$	(81	)

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

	September 30, 2013 Gain (Loss)					December 31, 2012 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) or OCI (a)
Electricity	$	6	$	(6	)	$	7	$	(7	)
Natural gas	25		(25		)	25		(25		)
Total	$	31	$	(31	)	$	32	$	(32	)

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

Credit Risk

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

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

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

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

(b) Changes in Internal Control Over Financial Reporting

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

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

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PART II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See “Environmental Matters” in Item 5 below and in Item 5 of the Pinnacle West/APS Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013 and “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2012 Form 10-K in regard to pending or threatened litigation and other disputes.

See Note 3 for ACC and FERC-related matters.

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

Item 1A. RISK FACTORS

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

Item 5. OTHER INFORMATION

Environmental Matters

EPA Environmental Regulation

Regional Haze — Navajo Plant. On January 18, 2013, EPA issued a proposed BART rule for the Navajo Plant, which would require installation of SCR technology in order to achieve a new, more stringent plantwide NOx emission limit. Under the proposal, the Navajo Plant participants would have up to five years after EPA issues its final determinations to achieve compliance with the BART requirements. APS’s total costs for post-combustion NOx controls could be up to approximately $200 million. The majority of these costs are not included in the capital expenditure estimates described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 2, since they will be incurred in years following 2015. EPA’s proposal also includes an “Alternative to BART,” which would provide the Navajo Plant with additional time to install the SCR technology. Under this “better than BART” alternative, the Navajo Plant participants would be required to install SCR technology on one unit per year in 2021, 2022 and 2023. In response to EPA’s request for comments on other options that could set longer time frames for installing pollution controls if the Navajo Plant can achieve additional emission reductions, on July 26, 2013, a group of stakeholders, including SRP, the operating agent for the Navajo Plant, submitted to EPA two suggested alternatives to BART, which would achieve greater NOx emission reductions than EPA’s proposed BART rule. On September 25, 2013, EPA issued a supplemental BART proposal proposing to determine that these alternatives are “better than BART” because NOx emissions that would be achieved thereunder would result in greater reasonable progress toward the national visibility goal than EPA’s proposed BART determination.

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Climate Change

President Obama’s Climate Action Plan. On June 25, 2013, President Obama unveiled his Climate Action Plan addressing his plans to reduce greenhouse gas (“GHG”) emissions in the United States. While the plan identifies a wide range of strategies for cutting GHG emissions in the United States, most important to APS and the electric utility industry is the implementation of carbon pollution standards for modified and existing fossil-fired generating plants. Concurrent with the President’s speech, the White House issued a Presidential Memorandum directing EPA to use its existing authorities under the Clean Air Act to develop GHG emission standards for new, modified, and existing power plants. The Presidential Memorandum directs EPA to propose GHG emission standards for modified and existing units by June 1, 2014 and to finalize them by June 1, 2015. The memorandum further directs EPA to reissue proposed standards for new power plants by September 20, 2013 and to finalize them in a timely fashion.

Consistent with President Obama’s June 2013 directive, pursuant to its authority under the Clean Air Act, on September 20, 2013, EPA issued a proposed rule, which would establish NSPS for new fossil-fired power plants. Once finalized, APS does not expect that the GHG NSPS for new units will have any material impact on its current operations. EPA indicated in its proposal that the rule will not apply to modified, reconstructed, or existing electric generating units, which are to be addressed in a subsequent rulemaking. We cannot currently predict the shape of any final rules or standards for existing fossil-fired power plants or assess how they might potentially impact the company. APS will continue to monitor these standards as they are developed.

Regulatory Initiatives. In 2009, EPA determined that GHG emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that GHGs fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, EPA has the authority to regulate GHG emissions of new motor vehicles under the Clean Air Act. As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new GHG emissions thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review,” or “NSR,” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source. The tailoring rule became applicable to power plants in January 2011. Several groups filed lawsuits challenging EPA’s endangerment finding and the tailoring rule, but the United States Court of Appeals for the District of Columbia Circuit upheld the rules. Petitioners asked the United States Supreme Court to reverse all or part of the appeals court’s decision upholding EPA’s GHG rules. On October 15, 2013, the Supreme Court granted these petitions limiting the question it would review to whether EPA permissibly determined that its regulation of GHG emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources, including power plants, that emit such gasses.

APS does not expect that any resulting Supreme Court decision or the tailoring rule will have a significant impact on its current operations. The rule will require APS to consider the impact of GHG emissions as part of its traditional New Source Review analysis for new sources and major modifications to existing plants.

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Item 6. EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description

12.1	Pinnacle West	Ratio of Earnings to Fixed Charges

12.2	APS	Ratio of Earnings to Fixed Charges

12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements

31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.2	Pinnacle West	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.4	APS	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

32.1*	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS*	Pinnacle West	XBRL Instance Document
	APS

101.SCH*	Pinnacle West	XBRL Taxonomy Extension Schema Document
	APS

101.CAL*	Pinnacle West	XBRL Taxonomy Extension Calculation Linkbase Document
	APS

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Exhibit No.	Registrant(s)	Description

101.LAB*	Pinnacle West	XBRL Taxonomy Extension Label Linkbase Document
	APS

101.PRE*	Pinnacle West	XBRL Taxonomy Extension Presentation Linkbase Document
	APS

101.DEF*	Pinnacle West	XBRL Taxonomy Definition Linkbase Document
	APS

*Furnished herewith as an Exhibit.

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

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit(1)	Date Filed

3.1	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of May 19, 2010	3.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-3-10

3.2	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-7-08

3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93

3.4	APS	Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012	3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473	5-22-12

3.5	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008	3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473	2-20-09

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

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SIGNATURES

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

		PINNACLE WEST CAPITAL CORPORATION
		(Registrant)


Dated:	October 31, 2013	By:	/s/ James R. Hatfield
			James R. Hatfield
			Executive Vice President and
			Chief Financial Officer
			(Principal Financial Officer and
			Officer Duly Authorized to sign this Report)


		ARIZONA PUBLIC SERVICE COMPANY
		(Registrant)


Dated:	October 31, 2013	By:	/s/ James R. Hatfield
			James R. Hatfield
			Executive Vice President and
			Chief Financial Officer
			(Principal Financial Officer and
			Officer Duly Authorized to sign this Report)