10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

OR

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

For the transition period from              to             

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

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

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION

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

ARIZONA PUBLIC SERVICE COMPANY

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

Indicate by check mark whether each registrant is a shell company (as defined in 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 April 25, 2014: 110,357,309
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of April 25, 2014: 71,264,947

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

TABLE OF CONTENTS

			Page
Forward-Looking Statements			2
Part I			3
	Item 1.	Financial Statements	3
		Pinnacle West Capital Corporation	3
		Arizona Public Service Company	42
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	67
	Item 4.	Controls and Procedures	67
Part II			68
	Item 1.	Legal Proceedings	68
	Item 1A.	Risk Factors	68
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	68
	Item 5.	Other Information	69
	Item 6.	Exhibits	70
Signatures			73

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

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (“2013 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;

·competition in retail and wholesale power markets;

·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;

·fuel and water supply availability;

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

·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;

·current and future economic conditions in Arizona, particularly in real estate markets;

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

·environmental and other concerns surrounding coal-fired generation;

·volatile fuel and purchased power costs;

·the investment performance of the assets of our nuclear decommissioning trusts, 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 2013 Form 10-K and in Part II, Item 1A of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures.  Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

2

PART I — FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended March 31,
	2014			2013
OPERATING REVENUES	$	686,251		$	686,652
OPERATING EXPENSES
Fuel and purchased power	249,786			230,679
Operations and maintenance	212,882			223,250
Depreciation and amortization	101,772			103,730
Taxes other than income taxes	45,845			40,021
Other expenses	796			2,049
Total	611,081			599,729
OPERATING INCOME	75,170			86,923
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,442			6,864
Other income (Note 10)	2,367			758
Other expense (Note 10)	(4,684		)	(3,752		)
Total	5,125			3,870
INTEREST EXPENSE
Interest charges	52,969			49,478
Allowance for borrowed funds used during construction	(3,770		)	(3,990		)
Total	49,199			45,488
INCOME BEFORE INCOME TAXES	31,096			45,305
INCOME TAXES	6,405			12,469
NET INCOME	24,691			32,836
Less: Net income attributable to noncontrolling interests (Note 6)	8,925			8,392
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	15,766		$	24,444
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	110,257			109,832
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,888			110,835
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	0.14		$	0.22
Net income attributable to common shareholders — diluted	$	0.14		$	0.22

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

3

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2014			2013
NET INCOME	$	24,691		$	32,836
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(599) and $(38)	(422		)	58
Reclassification of net realized loss, net of tax benefit of $1,323 and $3,300	3,116			5,053
Pension and other postretirement benefits activity, net of tax expense of $718 and $631	457			966
Total other comprehensive income	3,151			6,077
COMPREHENSIVE INCOME	27,842			38,913
Less: Comprehensive income attributable to noncontrolling interests	8,925			8,392
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	18,917		$	30,521

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

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	103,421		$	9,526
Customer and other receivables	245,884			299,904
Accrued unbilled revenues	88,907			96,796
Allowance for doubtful accounts	(2,504		)	(3,203		)
Materials and supplies (at average cost)	223,401			221,682
Fossil fuel (at average cost)	36,496			38,028
Deferred income taxes	58,630			91,152
Income tax receivable (Note 5)	4,647			135,517
Assets from risk management activities (Note 7)	16,951			17,169
Deferred fuel and purchased power regulatory asset (Note 3)	—			20,755
Other regulatory assets (Note 3)	76,317			76,388
Other current assets	45,780			39,895
Total current assets	897,930			1,043,609
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	21,626			23,815
Nuclear decommissioning trust (Note 13)	657,862			642,007
Other assets	60,753			60,875
Total investments and other assets	740,241			726,697
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,256,945			15,200,464
Accumulated depreciation and amortization	(5,360,781		)	(5,300,219		)
Net	9,896,164			9,900,245
Construction work in progress	646,236			581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	124,157			125,125
Intangible assets, net of accumulated amortization	144,446			157,689
Nuclear fuel, net of accumulated amortization	144,048			124,557
Total property, plant and equipment	10,955,051			10,888,985
DEFERRED DEBITS
Regulatory assets (Note 3)	719,596			711,712
Other	137,979			137,683
Total deferred debits	857,575			849,395
TOTAL ASSETS	$	13,450,797		$	13,508,686

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

5

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2014			December 31, 2013
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	224,820		$	284,516
Accrued taxes (Note 5)	179,137			130,998
Accrued interest	47,392			48,351
Common dividends payable	—			62,528
Short-term borrowings (Note 2)	9,500			153,125
Current maturities of long-term debt (Note 2)	540,424			540,424
Customer deposits	75,999			76,101
Liabilities from risk management activities (Note 7)	19,907			31,892
Liabilities for asset retirements	25,536			32,896
Deferred fuel and purchased power regulatory liability (Note 3)	18,897			—
Other regulatory liabilities (Note 3)	116,903			99,273
Other current liabilities	136,128			158,540
Total current liabilities	1,394,643			1,618,644
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	3,045,614			2,796,465
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,359,689			2,351,882
Regulatory liabilities (Note 3)	783,702			801,297
Liabilities for asset retirements	344,708			313,833
Liabilities for pension and other postretirement benefits (Note 4)	442,136			513,628
Liabilities from risk management activities (Note 7)	29,106			70,315
Customer advances	115,033			114,480
Coal mine reclamation	208,183			207,453
Deferred investment tax credit	152,114			152,361
Unrecognized tax benefits (Note 5)	13,502			42,209
Other	184,666			185,659
Total deferred credits and other	4,632,839			4,753,117
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 8)
Common stock, no par value; authorized 150,000,000 shares, 110,389,065 and 110,280,703 issued at respective dates	2,497,485			2,491,558
Treasury stock at cost; 34,828 and 98,944 shares at respective dates	(844		)	(4,308		)
Total common stock	2,496,641			2,487,250
Retained earnings	1,801,047			1,785,273
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(54,538		)	(54,995		)
Derivative instruments	(20,364		)	(23,058		)
Total accumulated other comprehensive loss	(74,902		)	(78,053		)
Total shareholders’ equity	4,222,786			4,194,470
Noncontrolling interests (Note 6)	154,915			145,990
Total equity	4,377,701			4,340,460
TOTAL LIABILITIES AND EQUITY	$	13,450,797		$	13,508,686

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	24,691		$	32,836
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	122,394			124,344
Deferred fuel and purchased power	31,630			31,194
Deferred fuel and purchased power amortization	8,022			1,122
Allowance for equity funds used during construction	(7,442		)	(6,864		)
Deferred income taxes	8,810			(9,265		)
Deferred investment tax credit	(247		)	21,428
Change in derivative instruments fair value	(13		)	333
Changes in current assets and liabilities:
Customer and other receivables	25,986			3,931
Accrued unbilled revenues	7,889			4,698
Materials, supplies and fossil fuel	(187		)	(9,386		)
Income tax receivable	130,870			(433		)
Other current assets	(10,669		)	(2,525		)
Accounts payable	(50,990		)	11,925
Accrued taxes	48,139			39,615
Other current liabilities	(15,864		)	(62,636		)
Change in margin and collateral accounts — assets	(290		)	933
Change in margin and collateral accounts — liabilities	(29,075		)	24,205
Change in other long-term assets	(9,636		)	(31,202		)
Change in other long-term liabilities	(34,861		)	37,904
Net cash flow provided by operating activities	249,157			212,157
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(207,459		)	(182,859		)
Contributions in aid of construction	7,736			14,912
Allowance for borrowed funds used during construction	(3,770		)	(3,990		)
Proceeds from nuclear decommissioning trust sales	103,157			135,240
Investment in nuclear decommissioning trust	(107,470		)	(139,553		)
Other	(702		)	(470		)
Net cash flow used for investing activities	(208,508		)	(176,720		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000			104,307
Short-term borrowings and payments — net	(143,625		)	(92,175		)
Dividends paid on common stock	(62,520		)	(58,067		)
Common stock equity issuance	9,390			9,441
Other	1			(36		)
Net cash flow provided by (used for) financing activities	53,246			(36,530		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	93,895			(1,093		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	9,526			26,202
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	103,421		$	25,109

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”).  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 have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC).  Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading.

The following table shows more detail of previously reported amounts for the changes in deferred investment tax credit and income tax receivable. Previously reported amounts were netted in the Statement of Cash Flows (dollars in thousands):

Statement of Cash Flows for the Year Ended March 31, 2013	As previously reported		Changes to conform to current year presentation			Amount reported after changes to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	12,163	$	(21,428	)	$	(9,265	)
Deferred investment tax credit	—		21,428			21,428
Accrued taxes and income tax receivable	39,182		(39,182		)	—
Income tax receivable	—		(433		)	(433		)
Accrued taxes	—		39,615			39,615

Supplemental Cash Flow Information

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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended March 31,
	2014			2013
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(131,078	)	$	425
Interest, net of amounts capitalized	49,147			49,038
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	24,908		$	6,575

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

Pinnacle West’s $200 million credit facility matures in November 2016.  At March 31, 2014, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At March 31, 2014, Pinnacle West had commercial paper borrowings of $10 million, no outstanding borrowings under its credit facility and no letters of credit outstanding.

APS

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. 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.  On January 15, 2014, these series of bonds were canceled.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of Southern California Edison’s (“SCE”) 48% ownership interest in each of Units 4 and 5 of the Four Corners Power Plant (“Four Corners”) and to replenish cash used in 2013 to re-acquire two series of tax-exempt indebtedness.

At March 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in November 2016 and a $500 million facility that matures in April 2018.  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2014, APS had no

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.

On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013.

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.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of March 31, 2014				As of December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,461		3,794		3,212		3,454
Total	$	3,586	$	3,919	$	3,337	$	3,579

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 March 31, 2014, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.8 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.1 billion, assuming APS’s total capitalization remains the same.

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 by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “2012 Settlement Agreement”)

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

Settlement Agreement

The 2012 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 2012 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 2012 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 2012 Settlement Agreement.

Other key provisions of the 2012 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 increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

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

·A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

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

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·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 APS’s 2009 retail rate case settlement agreement (the “2009 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 2012 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 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.

Cost Recovery Mechanisms

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

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

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, 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.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable

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energy credits.  On April 4, 2014, ACC staff submitted a proposal outlining various options which could be used to determine compliance with the renewable energy rules.  APS filed comments on the proposal and is awaiting the ACC’s selection of a proposal and modification of the rules to implement such proposal.

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

On June 1, 2012, APS filed its 2013 DSM 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.

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2014 and 2013 (dollars in millions):

	Three Months Ended March 31,
	2014			2013
Beginning balance	$	21		$	73
Deferred fuel and purchased power costs — current period	(32		)	(31		)
Amounts charged to customers	(8		)	(1		)
Ending balance	$	(19	)	$	41

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the United States Federal 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

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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 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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

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.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.

Lost Fixed Cost Recovery 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 rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement 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 a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014.

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

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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.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are being held in 2014.

Net Metering

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.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.

Beginning in May 2014, the ACC will conduct a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.

Four Corners

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  If approved, these adjustments would result in an average bill impact to residential customers of approximately 2%.  This includes the deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $47 million as of March 31, 2014.  A hearing on this matter is scheduled to begin August 4, 2014 and we anticipate a decision by the end of 2014.  APS cannot predict the outcome of this matter.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its

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portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  We are unable to predict the timing or outcome of these requests.  Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.

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Regulatory Assets and Liabilities

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

	Remaining Amortization	March 31, 2014				December 31, 2013
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)	$	—	$	313	$	—	$	314
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2043	4		104		4		105
Deferred fuel and purchased power — mark-to-market (Note 7)	2016	—		26		5		29
Transmission vegetation management	2016	9		12		9		14
Coal reclamation	2038	8		16		8		18
Palo Verde VIEs (Note 6)	2046	—		42		—		41
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		21		—
Tax expense of Medicare subsidy	2023	2		15		2		15
Loss on reacquired debt	2034	1		18		1		17
Income taxes — investment tax credit basis adjustment	2043	1		39		1		39
Pension and other postretirement benefits deferral	2015	8		2		8		4
Four Corners cost deferral	2024	—		47		—		37
Lost fixed cost recovery (b)	2015	32		—		25		—
Transmission cost adjustor (b)	2016	6		2		8		2
Retired power plant costs	2020	3		17		3		18
Other	Various	2		31		2		25
Total regulatory assets (d)		$	76	$	720	$	97	$	712

(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.  See Note 4 for further discussion.

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

(c)Subject to a carrying charge.

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

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

	Remaining Amortization	March 31, 2014				December 31, 2013
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	28	$	298	$	28	$	303
Asset retirement obligations	(a)	—		253		—		266
Renewable energy standard (b)	2015	35		16		33		15
Income taxes — change in rates	2043	1		73		—		74
Spent nuclear fuel	2047	5		37		6		36
Deferred gains on utility property	2019	2		9		2		10
Income taxes — deferred investment tax credit	2043	3		79		3		79
Demand side management (b)	2015	34		—		27		—
Deferred fuel and purchased power (b) (c)	2015	19		—		—		—
Deferred fuel and purchased power — mark to market	2015	9		—		—		—
Other	Various	—		19		—		18
Total regulatory liabilities		$	136	$	784	$	99	$	801

(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.

(c)Subject to carrying charge.

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 in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We amortized approximately $2 million for the three months ended March 31, 2014 and 2013, 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 March 31,						Three Months Ended March 31,
	2014			2013			2014			2013
Service cost — benefits earned during the period	$	15		$	17		$	5		$	6
Interest cost on benefit obligation	32			29			11			10
Expected return on plan assets	(40		)	(37		)	(12		)	(11		)
Amortization of net actuarial loss	2			9			—			3
Net periodic benefit cost	$	9		$	18		$	4		$	8
Portion of cost charged to expense	$	5		$	10		$	3		$	5

Contributions

The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016).  Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $105 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016).  The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

5.Income Taxes

During the first quarter of 2014, a $135 million cash refund was received from the IRS related to tax returns for the years ended December 31, 2008 and 2009.  This refund was classified as a current income tax receivable at December 31, 2013.

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.

In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  As a result of this guidance, $29 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Condensed Consolidated Balance Sheets and $16 million were recorded as an increase to net current deferred income tax liabilities on the APS Condensed Consolidated Balance Sheets as of March 31, 2014.

As of March 31, 2014, the tax year ended December 31, 2010 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 2010.

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

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million per year during 2014 and 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 determined through an appraisal process.  During 2014, APS must notify the lessor trust which of these two options (lease renewal or purchasing the assets) it will exercise.

As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2014 of $9 million and for the three months ended March 31, 2013 of $8 million, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders remains the same.  Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):

	March 31, 2014		December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	124	$	125
Current maturities of long-term debt	26		26
Long-term debt excluding current maturities	13		13
Equity — Noncontrolling interests	155		146

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 leases.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of March 31, 2014, APS would have been required to pay the noncontrolling equity participants approximately $133 million and assume $39 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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

7.Derivative Accounting

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

On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow 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 OCI, but are deferred through the PSA.  The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA.  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 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

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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.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of March 31, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	5,503	GWh
Gas	107	Billion cubic feet

Gains and Losses from Derivative Instruments

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2014			2013
Gain Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	177		$	96
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(4,439		)	(8,353		)

(a)During the three months ended March 31, 2014 and 2013, we had no amounts reclassified from accumulated OCI 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 $19 million before income taxes will be reclassified from accumulated OCI 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 months ended March 31, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2014			2013
Net Loss Recognized in Income	Operating revenues (a)	$	(92	)	$	(117	)
Net Gain Recognized in Income	Fuel and purchased power (a)	18,107			17,350
Total		$	18,015		$	17,233

(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 a 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 March 31, 2014 and December 31, 2013, include gross liabilities of $4 million and $5 million, respectively, of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, 2014 and December 31, 2013.  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.

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As of March 31, 2014:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset  (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
Current Assets	$	32,470		$	(15,816	)	$	16,654		$	297		$	16,951
Investments and Other Assets	23,913			(2,287		)	21,626			—			21,626
Total Assets	56,383			(18,103		)	38,280			297			38,577
Current Liabilities	(42,161		)	30,897			(11,264		)	(8,643		)	(19,907		)
Deferred Credits and Other	(65,511		)	36,405			(29,106		)	—			(29,106		)
Total Liabilities	(107,672		)	67,302			(40,370		)	(8,643		)	(49,013		)
Total	$	(51,289	)	$	49,199		$	(2,090	)	$	(8,346	)	$	(10,436	)

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

(b)Includes cash collateral provided to counterparties of $49,199.

(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 $8,643, and cash margin provided to counterparties of $297.

As of December 31, 2013:(dollars in thousands)	Gross Recognized Derivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			Amount Reported on Balance Sheet
Current Assets	$	24,587		$	(7,425	)	$	17,162		$	7		$	17,169
Investments and Other Assets	25,364			(1,549		)	23,815			—			23,815
Total Assets	49,951			(8,974		)	40,977			7			40,984
Current Liabilities	(50,540		)	26,166			(24,374		)	(7,518		)	(31,892		)
Deferred Credits and Other	(72,123		)	1,808			(70,315		)	—			(70,315		)
Total Liabilities	(122,663		)	27,974			(94,689		)	(7,518		)	(102,207		)
Total	$	(72,712	)	$	19,000		$	(53,712	)	$	(7,511	)	$	(61,223	)

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

(b)Includes cash collateral provided to counterparties of $19,000.

(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 $7,518, and cash margin provided to counterparties of $7.

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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 84% of Pinnacle West’s $39 million of risk management assets as of March 31, 2014.  This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2014 (dollars in millions):

	March 31, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	108
Cash Collateral Posted	49
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	50

(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 $180 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 months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014						Three Months Ended March 31, 2013
	Common Shareholders		Noncontrolling Interests		Total		Common Shareholders			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,194,470	$	145,990	$	4,340,460	$	3,972,806		$	129,483	$	4,102,289
Net income	15,766		8,925		24,691		24,444			8,392		32,836
Other comprehensive income	3,151		—		3,151		6,077			—		6,077
Total comprehensive income	18,917		8,925		27,842		30,521			8,392		38,913
Issuance of capital stock	2,592		—		2,592		2,574			—		2,574
Reissuance (purchase) of treasury stock — net	3,465		—		3,465		(6,271		)	—		(6,271		)
Other (primarily stock compensation)	3,342		—		3,342		14,825			—		14,825
Ending balance, March 31	$	4,222,786	$	154,915	$	4,377,701	$	4,014,455		$	137,875	$	4,152,330

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 (“Court of Federal Claims”).  The lawsuit seeks to recover 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 Protection Act.  This lawsuit is currently pending in the Court of Federal Claims.

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

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adjustments.  The maximum retrospective premium 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 million, with an annual payment limitation of approximately $16.5 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 replacement 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, 2014, a sublimit of $2.25 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies.  Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations.  APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds.  The maximum amount APS could incur under the current NEIL policies totals approximately $20 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 $54 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

There have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2013 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

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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.

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.

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.

On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS.  FERC Staff alleges that each of the named entities violated varying numbers of NERC Reliability Standards.  APS is alleged to have violated seven Reliability Standard Requirements.  The allegations of violations are preliminary determinations by FERC Staff and do not constitute findings by FERC itself that any violations have occurred.

APS intends to work with FERC Staff to resolve the matter.  If violations of the 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.  APS cannot predict the timing or financial or operational impacts that may result from the Staff’s Notice of Alleged Violations, including any payments that may result from a settlement if one is reached, or any claims that may be made as a result of the outages.

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 filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.  The appeal is now pending before the Ninth Circuit Court of Appeals.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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Clean Air Act Citizen 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 environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS.  The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project.  On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCRs”).  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 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $350 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 $130 million for Cholla Units 2 and 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.

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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, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Regional Haze Rules — Cholla

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan (“SIP”) and promulgating a FIP that is inconsistent with the state’s considered 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.  Briefing in the case was completed in February 2014, and the parties are waiting for the court to schedule oral argument.

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.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed 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.

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Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At March 31, 2014, 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 $24 million at March 31, 2014.  Additionally, APS has issued a letter of credit to support collateral obligations under a natural gas tolling contract entered into with third parties.  At March 31, 2014, that letter of credit totaled $5 million and will expire in 2014.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

Pinnacle West has issued parental guarantees and surety bonds for APS which were not material at March 31, 2014.

10.          Other Income and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	251		$	76
Miscellaneous	2,116			682
Total other income	$	2,367		$	758
Other expense:
Non-operating costs	$	(2,372	)	$	(1,932	)
Investment losses — net	(140		)	(112		)
Miscellaneous	(2,172		)	(1,708		)
Total other expense	$	(4,684	)	$	(3,752	)

11.          Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):

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	Three Months Ended March 31,
	2014		2013
Net income attributable to common shareholders	$	15,766	$	24,444
Average common shares outstanding — basic	110,257		109,832
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	631		1,003
Average common shares outstanding — diluted	110,888		110,835
Earnings per average common share attributable to common shareholders — basic	$	0.14	$	0.22
Earnings per average common share attributable to common shareholders — diluted	$	0.14	$	0.22

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 U.S. Treasury securities.

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

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their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 8 in the 2013 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 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 the 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

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the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.

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

Investments Held in our Nuclear Decommissioning Trusts

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 U.S. government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield 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.

We price securities using information provided by our trustee for our nuclear decommissioning trust assets.  Our trustee uses 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.

34

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at March 31, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at March 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	36		$	(18)	(b)	$	39
Nuclear decommissioning trust:
U.S. commingled equity funds	—		277			—			—			277
Fixed income securities:
U.S. Treasury	120		—			—			—			120
Cash and cash equivalent funds	—		14			—			(5)		(c)	9
Corporate debt	—		96			—			—			96
Mortgage-backed securities	—		79			—			—			79
Municipality bonds	—		64			—			—			64
Other	—		13			—			—			13
Subtotal nuclear decommissioning trust	120		543			—			(5		)	658
Total	$	120	$	564		$	36		$	(23	)	$	697
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(23	)	$	(85	)	$	59	(b)	$	(49	)

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

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

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

35

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 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 December 31, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	9		$	41		$	(9)	(b)	$	41
Nuclear decommissioning trust:
U.S. commingled equity funds	—		272			—			—			272
Fixed income securities:
U.S. Treasury	107		—			—			—			107
Cash and cash equivalent funds	—		11			—			(3)		(c)	8
Corporate debt	—		88			—			—			88
Mortgage-backed securities	—		85			—			—			85
Municipality bonds	—		71			—			—			71
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	107		538			—			(3		)	642
Total	$	107	$	547		$	41		$	(12	)	$	683
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(33	)	$	(90	)	$	21	(b)	$	(102	)

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

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

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

Fair Value Measurements Classified as Level 3

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

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

36

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease.  If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase.  The commodity prices and 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 risk management derivative Level 3 instruments at March 31, 2014 and December 31, 2013:

	March 31, 2014 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	34	$	60	Discounted cash flows	Electricity forward price (per MWh)	$23.13 — $67.47	$	42.28
Option Contracts (b)	—		22		Option model	Electricity forward price (per MWh)	$40.32 — $93.94	$	60.49
						Natural gas forward price (per MMbtu)	$3.64 — $3.84	$	3.76
						Electricity price volatilities	24% — 100%	52		%
						Natural gas price volatilities	23% — 44%	30		%
Natural Gas:
Forward Contracts (a)	2		3		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.60 — $4.40	$	3.91
Total	$	36	$	85

(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.

37

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2013 Fair Value (millions)
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted- Average
Electricity:
Forward Contracts (a)	$	40	$	66	Discounted cash flows	Electricity forward price (per MWh)	$24.89 - $65.04	$	41.09
Option Contracts (b)	—		19		Option model	Electricity forward price (per MWh)	$39.91 - $85.41	$	58.70
						Natural gas forward price (per MMbtu)	$3.57 - $3.80	$	3.71
						Electricity price volatilities	35% - 94%	59		%
						Natural gas price volatilities	22% - 36%	27		%
Natural Gas:
Forward Contracts (a)	1		5		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.47 - $4.31	$	3.87
Total	$	41	$	90

(a)Includes swaps and physical and financial contracts.

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

The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2014 and 2013 (dollars in millions):

Commodity Contracts	Three Months Ended March 31,
	2014			2013
Net derivative balance at beginning of period	$	(49	)	$	(48	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	4			(1		)
Settlements	—			(2		)
Transfers into Level 3 from Level 2	(3		)	(1		)
Transfers from Level 3 into Level 2	(1		)	(1		)
Net derivative balance at end of period	$	(49	)	$	(53	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

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

38

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2014 and December 31, 2013 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2014
Equity securities	$	277		$	132	$	—
Fixed income securities	386			13		(3		)
Net payables (a)	(5		)	—		—
Total	$	658		$	145	$	(3	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2013
Equity securities	$	272		$	129	$	—
Fixed income securities	373			11		(6		)
Net payables (a)	(3		)	—		—
Total	$	642		$	140	$	(6	)

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

39

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Three Months Ended March 31,
	2014			2013
Realized gains	$	1		$	2
Realized losses	(2		)	(1		)
Proceeds from the sale of securities (a)	103			135

(a)Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2014 is as follows (dollars in millions):

	Fair Value
Less than one year	$	17
1 year — 5 years	109
5 years — 10 years	111
Greater than 10 years	149
Total	$	386

14.New Accounting Standards

During 2014, we adopted, on a prospective basis, new guidance relating to the presentation of unrecognized tax benefits.  This guidance generally requires 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.  Prior to adopting this guidance, we presented unrecognized tax benefits on a gross basis.  The adoption of this new guidance changed our balance sheet presentation of unrecognized tax benefits, but did not impact our operating results or cash flows.  See Note 5 for details regarding the impacts of adopting this guidance.

40

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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-months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,058	)	$	(54,995	)	$	(78,053	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(422		)	—			(422		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	457		(b)	3,573			5,053		(a)	966		(b)	6,019
Net current period OCI	2,694			457			3,151			5,111			966			6,077
Ending balance, March 31	$	(20,364	)	$	(54,538	)	$	(74,902	)	$	(44,481	)	$	(63,450	)	$	(107,931	)

(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.

41

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2014			2013
ELECTRIC OPERATING REVENUES	$	685,545		$	685,827
OPERATING EXPENSES
Fuel and purchased power	249,786			230,679
Operations and maintenance	208,285			220,752
Depreciation and amortization	101,748			103,706
Income taxes	10,478			16,060
Taxes other than income taxes	45,613			39,768
Total	615,910			610,965
OPERATING INCOME	69,635			74,862
OTHER INCOME (DEDUCTIONS)
Income taxes	1,210			2,332
Allowance for equity funds used during construction	7,442			6,864
Other income (Note S-2)	2,762			1,343
Other expense (Note S-2)	(5,056		)	(6,296		)
Total	6,358			4,243
INTEREST EXPENSE
Interest on long-term debt	48,896			46,221
Interest on short-term borrowings	1,413			1,429
Debt discount, premium and expense	1,011			1,011
Allowance for borrowed funds used during construction	(3,770		)	(3,990		)
Total	47,550			44,671
NET INCOME	28,443			34,434
Less: Net income attributable to noncontrolling interests (Note 6)	8,925			8,392
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	19,518		$	26,042

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

42

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2014			2013
NET INCOME	$	28,443		$	34,434
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(599) and $(38)	(421		)	58
Reclassification of net realized loss, net of tax benefit of $1,323 and $3,300	3,116			5,052
Pension and other postretirement benefits activity, net of tax expense of $606 and $576	566			882
Total other comprehensive income	3,261			5,992
COMPREHENSIVE INCOME	31,704			40,426
Less: Comprehensive income attributable to noncontrolling interests	8,925			8,392
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	22,779		$	32,034

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

43

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31,			December 31,
	2014			2013
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	15,253,694		$	15,196,598
Accumulated depreciation and amortization	(5,357,699		)	(5,296,501		)
Net	9,895,995			9,900,097
Construction work in progress	646,236			581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	124,157			125,125
Intangible assets, net of accumulated amortization	144,291			157,534
Nuclear fuel, net of accumulated amortization	144,048			124,557
Total property, plant and equipment	10,954,727			10,888,682
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	657,862			642,007
Assets from risk management activities (Note 7)	21,626			23,815
Other assets	34,411			33,709
Total investments and other assets	713,899			699,531
CURRENT ASSETS
Cash and cash equivalents	103,400			3,725
Customer and other receivables	245,272			299,055
Accrued unbilled revenues	88,907			96,796
Allowance for doubtful accounts	(2,504		)	(3,203		)
Materials and supplies (at average cost)	223,401			221,682
Fossil fuel (at average cost)	36,496			38,028
Income tax receivable	289			135,179
Assets from risk management activities (Note 7)	16,951			17,169
Deferred fuel and purchased power regulatory asset (Note 3)	—			20,755
Other regulatory assets (Note 3)	76,317			76,388
Other current assets	45,176			39,153
Total current assets	833,705			944,727
DEFERRED DEBITS
Regulatory assets (Note 3)	719,596			711,712
Unamortized debt issue costs	22,686			21,860
Other	114,437			114,865
Total deferred debits	856,719			848,437
TOTAL ASSETS	$	13,359,050		$	13,381,377

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

44

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31,			December 31,
	2014			2013
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,823,914			1,804,398
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(29,747		)	(30,313		)
Derivative instruments	(20,364		)	(23,059		)
Total shareholder equity	4,331,661			4,308,884
Noncontrolling interests (Note 6)	154,915			145,990
Total equity (Note S-1)	4,486,576			4,454,874
Long-term debt less current maturities (Note 2)	2,920,614			2,671,465
Total capitalization	7,407,190			7,126,339
CURRENT LIABILITIES
Short-term borrowings (Note 2)	—			153,125
Current maturities of long-term debt (Note 2)	540,424			540,424
Accounts payable	219,910			281,237
Accrued taxes (Note 5)	173,040			122,460
Accrued interest	47,207			48,132
Common dividends payable	—			62,500
Customer deposits	75,999			76,101
Deferred income taxes	21,951			2,033
Liabilities from risk management activities (Note 7)	19,907			31,892
Liabilities for asset retirements	25,536			32,896
Deferred fuel and purchased power regulatory liability	18,897			—
Other regulatory liabilities (Note 3)	116,903			99,273
Other current liabilities	118,934			130,774
Total current liabilities	1,378,708			1,580,847
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,355,237			2,347,724
Regulatory liabilities (Note 3)	783,702			801,297
Liabilities for asset retirements	344,708			313,833
Liabilities for pension and other postretirement benefits (Note 4)	405,597			476,017
Liabilities from risk management activities (Note 7)	29,106			70,315
Customer advances	115,033			114,480
Coal mine reclamation	208,183			207,453
Deferred investment tax credit	152,114			152,361
Unrecognized tax benefits (Note 5)	26,284			42,209
Other	153,188			148,502
Total deferred credits and other	4,573,152			4,674,191
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	13,359,050		$	13,381,377

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

45

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	28,443		$	34,434
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	122,370			124,320
Deferred fuel and purchased power	31,630			31,194
Deferred fuel and purchased power amortization	8,022			1,122
Allowance for equity funds used during construction	(7,442		)	(6,864		)
Deferred income taxes	8,696			(8,670		)
Deferred investment tax credit	(247		)	21,426
Change in derivative instruments fair value	(13		)	333
Changes in current assets and liabilities:
Customer and other receivables	25,749			2,464
Accrued unbilled revenues	7,889			4,698
Materials, supplies and fossil fuel	(187		)	(9,386		)
Income tax receivable	134,890			261
Other current assets	(10,807		)	(2,526		)
Accounts payable	(52,621		)	12,892
Accrued taxes	50,580			43,062
Other current liabilities	(5,257		)	(58,419		)
Change in margin and collateral accounts — assets	(290		)	933
Change in margin and collateral accounts — liabilities	(29,075		)	24,205
Change in other long-term assets	(10,439		)	(29,022		)
Change in other long-term liabilities	(28,083		)	41,760
Net cash flow provided by operating activities	273,808			228,217
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(207,459		)	(182,859		)
Contributions in aid of construction	7,736			14,912
Allowance for borrowed funds used during construction	(3,770		)	(3,990		)
Proceeds from nuclear decommissioning trust sales	103,157			135,240
Investment in nuclear decommissioning trust	(107,470		)	(139,553		)
Other	(702		)	(470		)
Net cash flow used for investing activities	(208,508		)	(176,720		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000			104,307
Short-term borrowings — net	(153,125		)	(92,175		)
Dividends paid on common stock	(62,500		)	(59,800		)
Net cash flow provided by (used for) financing activities	34,375			(47,668		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	99,675			3,829
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,725			3,499
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	103,400		$	7,328
Supplemental disclosure of cash flow information
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(134,323	)	$	—
Interest, net of amounts capitalized	$	47,464		$	48,146
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	24,908		$	6,575

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

46

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 months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014								Three Months Ended March 31, 2013
	Shareholder Equity			Noncontrolling Interests		Total			Shareholder Equity			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,308,884		$	145,990	$	4,454,874		$	4,093,000		$	129,483	$	4,222,483
Net income	19,518			8,925		28,443			26,042			8,392		34,434
OCI	3,261			—		3,261			5,992			—		5,992
Total comprehensive income	22,779			8,925		31,704			32,034			8,392		40,426
Other	(2		)	—		(2		)	(2		)	—		(2		)
Ending balance, March 31	$	4,331,661		$	154,915	$	4,486,576		$	4,125,032		$	137,875	$	4,262,907

S-2.Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	138		$	23
Miscellaneous	2,624			1,320
Total other income	$	2,762		$	1,343
Other expense:
Non-operating costs (a)	$	(2,587	)	$	(2,320	)
Asset dispositions	(183		)	(1,264		)
Miscellaneous	(2,286		)	(2,712		)
Total other expense	$	(5,056	)	$	(6,296	)

(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

The following table shows the changes in accumulated other comprehensive income (loss), including reclassification adjustments, net of tax, by component for the three-month periods ended March 31, 2014 and March 31, 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,059	)	$	(30,313	)	$	(53,372	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
OCI (loss) before reclassifications	(421		)	—			(421		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	566		(b)	3,682			5,052		(a)	882		(b)	5,934
Net current period OCI	2,695			566			3,261			5,110			882			5,992
Ending balance, March 31	$	(20,364	)	$	(29,747	)	$	(50,111	)	$	(44,482	)	$	(38,621	)	$	(83,103	)

(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 2013 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.  As a result of the Fukushima event, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force.  In response to these recommendations, Palo Verde expects to spend approximately $120 million for capital enhancements to the plant over the next several years (APS’s share is 29.1%).

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 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 and Coal Supply Matters.  On December 30, 2013, APS purchased SCE’s 48% interest in each of Units 4 and 5 of Four Corners.  The final purchase price for the interest was approximately $182 million, subject to certain minor post-closing adjustments.  In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction.  On December 30, 2013, APS filed an application with the ACC to request rate adjustments prior to its next general rate case related to APS’s acquisition of SCE’s interest in Four Corners.  If approved, these would result in an average bill impact to residential customers of approximately 2%.  A hearing on this matter is scheduled to begin August 4, 2014 and we anticipate a decision by the end of 2014.  APS cannot predict the outcome of this request.

Concurrently with the closing of the SCE transaction, 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, transferred its ownership of BNCC to Navajo Transitional Energy Company, LLC (“NTEC”), a company formed by the Navajo Nation to own the mine and develop other energy projects.  BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016.  Also occurring concurrently with the closing, the Four Corners’ co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031 (the “2016 Coal Supply Agreement”).  El Paso Electric Company (“EPE”), a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement.  Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation.  When APS ultimately acquires a right to EPE’s interest in Four Corners, by agreement or operation of law, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC.  The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.

Pollution Control Investments and Shutdown of Units 1, 2 and 3.  EPA, in its final regional haze rule for Four Corners, required the Four Corners’ owners to elect one of two emissions alternatives to apply to the plant.  On December 30, 2013, APS, on behalf of the co-owners, notified EPA that they chose the alternative BART compliance strategy requiring the permanent closure of Units 1, 2 and 3 by January 1, 2014 and installation and operation of selective catalytic reduction (“SCR”) controls on Units 4 and 5 by July 31, 2018.  On December 30, 2013, APS retired Units 1, 2 and 3.

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 are pursuing.  A federal environmental review is underway as part of the DOI review process.  In March 2014, APS received a draft of the environmental impact statement (“DEIS”) in connection with the DOI review process.  As a proponent of the Four Corners Power Plant and Navajo Mine Energy Project, APS, along with other members of the public, will submit comments on the DEIS by the May 27, 2014 public comment deadline.  APS will also require a Prevention of Significant Deterioration (“PSD”) permit from EPA to install SCR control technology at Four Corners.  APS cannot predict whether these

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federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners.

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 2016, along with other transmission costs for upgrades and replacements.  APS is also working to establish and expand smart grid technologies throughout its service territory 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 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025.  In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 1,700 GWh of new renewable resources to be in service by year-end 2015, in addition to its 2008 renewable resource commitments.  Taken together, APS’s commitment is currently estimated to be approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year.  A component of the RES targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, 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.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits.  On April 4, 2014, ACC staff submitted a proposal outlining various options which could be used to determine compliance with the renewable energy rules.  APS filed comments on the proposal and is awaiting the ACC’s selection of a proposal and modification of the rules to implement such proposal.

The following table summarizes APS’s renewable energy sources in operation and under development as of May 2, 2014.

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	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar (a)	137	32
Purchased Power Agreements:
Solar (b)	310	--
Wind	289	--
Geothermal	10	--
Biomass	14	--
Biogas	6	--
Total Purchased Power Agreements	629	--
Total Distributed Energy: Solar (c)	335	35
Total Renewable Portfolio	1,101	67

(a)Included in these numbers is 150 MW of solar resources procured through the AZ Sun Program.

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

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

APS is developing owned solar resources through the ACC-approved AZ Sun Program.  Under this program to date, APS estimates its investment commitment will be approximately $695 million.  Under the AZ Sun Program, an additional 20 MW has been approved to be contracted, but is not included in the table above since it is not yet under contract.  On April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned solar under the program.  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 December 2009, Arizona regulators 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.  The ACC initiated an Energy Efficiency rulemaking, with a proposed EES 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.

On June 1, 2012, APS filed its 2013 DSM 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.

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy

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Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

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 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 the 2012 Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case.  See Note 3 for details regarding the 2012 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 acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  We are unable to predict the timing or outcome of these requests.  Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.

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 Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also

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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.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are being held in 2014.

Net Metering.  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.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.

Beginning in May 2014, the ACC will conduct a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.

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.

El Dorado.  The operations of El Dorado, our only other operating subsidiary, 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.

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 2011 through 2013, 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 customers in APS’s service territory increased 1.3% for the three-month period ended March 31, 2014 compared with the prior year period.  For the three years 2011 through 2013, APS’s customer growth averaged 1.0% per year.  We currently expect annual customer growth to average about 2.5% for 2014 through 2016 based on our assessment of modestly improving economic conditions, both nationally and in Arizona.  Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.6% for the three-month period ended March 31, 2014 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 and customer growth.  For the three years 2011 through 2013, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average about 1% during 2014 through 2016, 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 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 and energy conservation, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes.  Based on past experience, a reasonable range of variation in our kWh 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, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.  In the 2009 Settlement Agreement, 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.  See Note 3 regarding deferral of certain costs pursuant to an ACC order.

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 10.5% 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 2012 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 March 31, 2014 compared with three-month period ended March 31, 2013.

Our consolidated net income attributable to common shareholders for the three months ended March 31, 2014 was $16 million, compared with consolidated net income of $24 million for the prior-year period.  The results reflect a decrease of approximately $9 million for the regulated electricity segment primarily related to the effects of weather and higher property taxes.  These negative factors were partially offset by lower operations and maintenance expenses related to lower employee benefit costs and lower income taxes.

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

	Three Months Ended March 31,
	2014			2013			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	436		$	455		$	(19	)
Operations and maintenance	(213		)	(223		)	10
Depreciation and amortization	(102		)	(104		)	2
Taxes other than income taxes	(46		)	(40		)	(6		)
Other income (expenses), net	5			3			2
Interest charges, net of allowance for borrowed funds used during construction	(49		)	(45		)	(4		)
Income taxes	(6		)	(13		)	7
Less income related to noncontrolling interests (Note 6)	(9		)	(8		)	(1		)
Regulated electricity segment net income	16			25			(9		)
All other	—			(1		)	1
Net Income Attributable to Common Shareholders	$	16		$	24		$	(8	)

Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $19 million lower for the three months ended March 31, 2014 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)
Effects of weather	$	(37	)	$	(14	)	$	(23	)
Lower net fuel and purchased power costs, including related deferrals and higher off-system sales	29			27			2
Miscellaneous items, net	8			6			2
Total	$	—		$	19		$	(19	)

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Operations and maintenance.  Operations and maintenance expenses decreased $10 million for the three months ended March 31, 2014 compared with the prior-year period primarily related to lower employee benefit costs partially offset by other miscellaneous factors.

Taxes other than income taxes.  Taxes other than income taxes were $6 million higher for the three months ended March 31, 2014 compared with the prior-year period primarily due to higher property tax rates and higher plant balances.

Income taxes.  Income taxes were $7 million lower for the three months ended March 31, 2014 compared with the prior-year period primarily due to lower pretax income.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness.  The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and 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 March 31, 2014, APS’s common equity ratio, as defined, was 56%.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.8 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.1 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.

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the three months ended March 31, 2014 and 2013 (dollars in millions):

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Pinnacle West Consolidated

	Three Months Ended March 31						Net
	2014			2013			Change
Net cash flow provided by operating activities	$	249		$	212		$	37
Net cash flow used for investing activities	(208		)	(176		)	(32		)
Net cash flow provided by (used for) financing activities	53			(37		)	90
Net increase (decrease) in cash and cash equivalents	$	94		$	(1	)	$	95

Arizona Public Service Company

	Three Months Ended March 31						Net
	2014			2013			Change
Net cash flow provided by operating activities	$	274		$	228		$	46
Net cash flow used for investing activities	(208		)	(176		)	(32		)
Net cash flow provided by (used for) financing activities	34			(48		)	82
Net increase in cash and cash equivalents	$	100		$	4		$	96

Operating Cash Flows

Three-month period ended March 31, 2014 compared with three-month period ended March 31, 2013.  Pinnacle West’s consolidated net cash provided by operating activities was $249 million in the first quarter of 2014 compared to $212 million in the first quarter of 2013, an increase of $37 million in net cash provided.  The increase is primarily related to a $135 million income tax refund received in the first quarter of 2014, partially offset by a $55 million change in cash collateral posted, $44 million of higher pension contributions in the three month-period ended March 31, 2014 (approximately $7 million of which is reflected in capital expenditures), 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 Income 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 107% funded as of January 1, 2013 and is estimated to be approximately 103% funded as of January 1, 2014.  The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.  Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015 and $122 million in 2016).  Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $105 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016).  The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

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During the first quarter of 2014, a $135 million cash refund was received from the IRS related to tax returns for the years ended December 31, 2008 and 2009.  This refund was classified as a current income tax receivable at December 31, 2013.

Investing Cash Flows

Three-month period ended March 31, 2014 compared with three-month period ended March 31, 2013.  Pinnacle West’s consolidated net cash used for investing activities was $208 million in the first quarter of 2014, compared to $176 million in the first quarter of 2013, an increase of $32 million in net cash used primarily related to increased capital expenditures.

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

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2014		2015		2016
APS
Generation:
Nuclear Fuel	$	74	$	86	$	88
Renewables	130		7		—
Environmental	25		57		213
Other Generation	227		248		355
Distribution	240		374		363
Transmission	206		213		196
Other (a)	71		41		48
Total APS	$	973	$	1,026	$	1,263

(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.  The estimated Renewables expenditures include 20 MW of utility-scale solar projects which were approved by the ACC in the 2014 RES Implementation Plan.  We have not included estimated costs for Cholla’s compliance with the Mercury and Air Toxics Standards or EPA’s regional haze rule since we have challenged the regional haze rule judicially and are considering our future options with respect to that plant if the regional haze rule is upheld.  The portion of estimated costs through 2016 for installation of pollution control equipment needed to ensure Four Corners’ compliance with EPA’s regional haze rules have been included in the table above.  We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

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

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

Financing Cash Flows and Liquidity

Three-month period ended March 31, 2014 compared with three-month period ended March 31, 2013.  Pinnacle West’s consolidated net cash provided by financing activities was $53 million in the first quarter of 2014, compared to $37 million of net cash used in the first quarter of 2013, an increase of $90 million in net cash provided.  The increase in net cash provided by financing activities is primarily due to $146 million in higher issuances of long-term debt, partially offset by a $51 million net change in short-term borrowings (see below).

Significant Financing Activities.  On April 23, 2014, the Pinnacle West Board of Directors declared a dividend of $0.5675 per share of common stock, payable on June 2, 2014 to shareholders of record in May 5, 2014.

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. 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.  On January 15, 2014, these series of bonds were canceled.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt indebtedness (see Note 2).

On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013.

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.

Pinnacle West’s $200 million credit facility matures in November 2016.  At March 31, 2014, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At March 31, 2014, Pinnacle West had commercial paper borrowings of $10 million, no outstanding borrowings under its credit facility and no letters of credit outstanding.

At March 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in November 2016 and a $500 million credit facility that matures in April 2018.  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 can use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2014, APS had no

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commercial paper borrowings and no outstanding borrowings or letters of credit under its revolving credit facilities.

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

Other Financing Matters.

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

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

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.  Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At March 31, 2014, the ratio was approximately 47% for Pinnacle West and 46% for APS.  Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt.  See further discussion of “cross-default” provisions below.

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

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

See Note 2 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of April 25, 2014 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

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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	Baa1	A-	BBB+
Commercial paper	P-2	A-2	F2
Outlook	Stable	Stable	Stable
APS
Corporate credit rating	A3	A-	BBB+
Senior unsecured	A3	A-	A-
Secured lease obligation bonds	A3	A-	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.

Contractual Obligations

There have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2013 Form 10-K.

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 2013 Form 10-K.  See “Critical Accounting Policies” in Item 7 of the 2013 Form 10-K for further details about our critical accounting policies.

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OTHER ACCOUNTING MATTERS

During 2014, we have adopted 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 trust fund (see Note 12 and Note 13) and benefit plan assets.  The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments.  Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

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

The following table shows the net pretax changes in mark-to-market of our derivative positions for the three months ended March 31, 2014 and 2013 (dollars in millions):

	Three Months Ended March 31,
	2014			2013
Mark-to-market of net positions at beginning of year	$	(73	)	$	(122	)
Decrease in regulatory asset	17			20
Recognized in OCI:
Mark-to-market losses realized during the period	5			8
Change in valuation techniques	—			—
Mark-to-market of net positions at end of year	$	(51	)	$	(94	)

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The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at March 31, 2014 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 2013 Form 10-K and Note 12 for more discussion of our valuation methods.

Source of Fair Value	2014			2015			2016			2017			2018			Years thereafter			Total fair value
Observable prices provided by other external sources	$	—		$	(1	)	$	(2	)	$	1		$	—		$	—		$	(2	)
Prices based on unobservable inputs	(9		)	(14		)	(12		)	(5		)	(4		)	(5		)	(49		)
Total by maturity	$	(9	)	$	(15	)	$	(14	)	$	(4	)	$	(4	)	$	(5	)	$	(51	)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 (dollars in millions):

	March 31, 2014 Gain (Loss)					December 31, 2013 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings (a)
Natural gas	$	—	$	—		$	—	$	—
Regulatory asset (liability) or OCI (b)
Electricity	4		(4		)	6		(6		)
Natural gas	30		(30		)	26		(26		)
Total	$	34	$	(34	)	$	32	$	(32	)

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

(b)These contracts are economic 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 7 for a discussion of our credit valuation adjustment policy.

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Item 3.                   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4.                   CONTROLS AND PROCEDURES

(a)Disclosure Controls and Procedures

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

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2014.  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, has evaluated the effectiveness of APS’s disclosure controls and procedures as of March 31, 2014.  Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b)Changes in Internal Control Over Financial Reporting

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

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended March 31, 2014 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 “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2013 Form 10-K with 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 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 2013 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 2013 Form 10-K are not the only risks facing Pinnacle West and APS.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.

Item 2.                   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

The following table contains information about our purchases of our common stock during the first quarter of 2014.

Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 — January 31, 2014	—	—
February 1 — February 28, 2014	82,474	$	54.99
March 1 — March 31, 2014	—	—
Total	82,474	$	54.99	—	—

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

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Item 5.                   OTHER INFORMATION

Physical Security Standards

On March 7, 2014, FERC issued an order requiring NERC to act within 90 days to develop standards that will require utilities to take steps, or to demonstrate that they have taken steps, to address physical security risks and vulnerabilities related to the reliable operation of the bulk-power system.  Among other things, FERC’s order states that facilities that are critical to the operation of the bulk-power system should be identified; potential threats and vulnerabilities should be evaluated; owners and operators should develop a security plan; confidential information should be protected; and a party other than the asset owner should verify owner risk assessment.  Until the NERC standards are established, we cannot predict the extent of any financial or operational impacts on APS.

Union Contract Extension

As previously disclosed in Part I, Item 1 “Business — Other Information” in the 2013 Form 10-K, APS and union representatives from the fossil generation, transmission and distribution, facilities maintenance, warehousing and transportation business areas were engaged in discussions to enter into an extension of their collective bargaining agreement that was to expire in April 2014.  The parties entered into a one-year extension of the collective bargaining agreement, which will now expire in April 2015.  The extension provides a wage increase of 2.25% effective April 1, 2014.

Amendment to Palo Verde Participation Agreement

APS, Public Service Company of New Mexico, SRP, SCE, EPE, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles are parties to the Arizona Nuclear Power Project Participation Agreement, dated as of August 23, 1973, as amended by fifteen amendments (“Participation Agreement”). The Arizona Nuclear Power Project is also known as the Palo Verde Nuclear Generating Station. The Participation Agreement was further amended by Amendment Number 16, dated April 28, 2014. Amendment Number 16 extends the expiration date of the Participation Agreement to align with the license extensions granted by the NRC in April 2011 for each of the three units at Palo Verde. The latest expiration date of the original operating licenses had been November 25, 2027, which was extended by the NRC to November 25, 2047. Also, in accordance with Amendment Number 16, the term of the Participation Agreement will automatically extend in the event of future extensions of the NRC operating licenses.

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Item 6.                   EXHIBITS

(a)Exhibits

Exhibit No.	Registrant(s)	Description
10.1*	Pinnacle West APS	Second Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005
10.2	Pinnacle West APS	Amendment No. 16, dated April 28, 2014, to  ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles
10.3	Pinnacle West APS	Four Corners Project Co-Tenancy Agreement Amendment No. 7, dated December 30, 2013, among APS, El Paso Electric Company, Public Service Company of New Mexico, SRP, SCE, and Tucson Electric Power Company
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

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Exhibit No.	Registrant(s)	Description
101.INS	Pinnacle West APS	XBRL Instance Document
101.SCH	Pinnacle West APS	XBRL Taxonomy Extension Schema Document
101.CAL	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Pinnacle West APS	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Pinnacle West APS	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Pinnacle West APS	XBRL Taxonomy Definition Linkbase Document

*Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 6 of Form 10-Q.

**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:   May 2, 2014	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:   May 2, 2014	By:	/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)

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EX-10.1

Exhibit 10.1

SECOND AMENDMENT TO THE
PINNACLE WEST CAPITAL CORPORATION
SUPPLEMENTAL EXCESS BENEFIT RETIREMENT PLAN OF 2005

Effective as of January 1, 2005, Pinnacle West Capital Corporation (the “Company”) adopted the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (the “Plan”).  The Plan has been amended on one occasion.  By this instrument, the Company amends the Plan as described below.  Defined terms used in this Second Amendment shall have the meaning specified in the Plan.

1.             This Second Amendment shall be effective as of February 21, 2014.

2.             This Second Amendment amends the provisions of the Plan noted below.  This Second Amendment also supersedes the other provisions of the Plan to the extent those provisions are inconsistent with the provisions and intent of this Second Amendment.

3.             Section 5(b) of the Plan is hereby amended and restated in its entirety to read as follows:

(b)           Spouse’s Benefit with Respect to Officer Traditional Benefits Described in Sections 4(a)(1) and 4(a)(2)(i).

If a participant entitled to benefits under Section 4(a)(1) or Section 4(a)(2)(i) dies while still employed by the Company or an Affiliate, the participant’s spouse shall be entitled to a one hundred percent (100%) survivor annuity.  The one hundred percent (100%) survivor annuity shall provide a benefit to the participant’s surviving spouse, for the spouse’s life, equal to one hundred percent (100%) of the monthly benefit for life that the participant would have received under Section 4(a)(1) or Section 4(a)(2)(i) had he or she (i) terminated employment on the day before he or she died, (ii) survived to the day on which he or she would first be eligible to commence benefits under Section 5(a), (iii) elected to retire and commence benefits under the Plan and the Retirement Plan in the form of a joint and 100% survivor annuity, and (iv) then died.  Benefits payable to the surviving spouse shall commence on the first day of the month following the participant’s date of death.

Benefits payable to any other participant who is entitled to benefits under Section 4(a)(1) or Section 4(a)(2)(i) who has terminated employment with the Company and all Affiliates (a “terminated participant”) and dies prior to

commencing benefits also shall be paid in the form of a one hundred percent (100%) survivor annuity.  The one hundred percent (100%) survivor annuity payable to the surviving spouse of a terminated participant shall provide a benefit to the terminated participant’s surviving spouse, for the spouse’s life, equal to one hundred percent (100%) of the monthly benefit for life that the participant would have received under Section 4(a)(1) or Section 4(a)(2)(i) had he or she (i) survived to the day on which he or she would first be eligible to commence benefits under Section 5(a) and (ii) elected to retire and commence benefits under the Plan and the Retirement Plan in the form of a joint and one hundred percent (100%) survivor annuity commencing on the day determined in accordance with the next sentence.  The one hundred  percent (100%) survivor annuity benefits payable to the surviving spouse of a terminated participant shall commence as follows:  (i) upon death if at the time of such death the participant has either attained age sixty-five (65) or has both attained age fifty-five (55) and completed ten (10) Years of Service; or (ii) age sixty-five (65) if at the time of such death the participant has neither attained age sixty-five (65) nor both attained age fifty-five (55) and completed ten (10) Years of Service.

4.             Except as otherwise amended by this Second Amendment, the Plan shall continue in full force and effect.

IN WITNESS WHEREOF, Pinnacle West Capital Corporation has caused this Second Amendment to be executed as of this 19th day of February, 2014.

Pinnacle West Capital Corporation
By:	/s/ Donald E. Brandt
Its:	Chairman of the Board, President and Chief Executive Officer

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EX-10.2

Exhibit 10.2

AMENDMENT NUMBER 16

TO THE ARIZONA NUCLEAR POWER PROJECT

PARTICIPATION AGREEMENT

1.PARTIES:

The Parties to this Amendment Number 16 to the Arizona Nuclear Power Project Participation Agreement, hereinafter referred to as “Amendment Number 16,” are: ARIZONA PUBLIC SERVICE COMPANY, a corporation organized and existing under and by virtue of the laws of the State of Arizona, hereinafter referred to as “Arizona”; SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an agricultural improvement district organized and existing under and by virtue of the laws of the State of Arizona, hereinafter referred to as “Salt River Project”; SOUTHERN CALIFORNIA EDISON COMPANY, a corporation organized and existing under and by virtue of the laws of the State of California, hereinafter referred to as “Edison”; PUBLIC SERVICE COMPANY OF NEW MEXICO, a corporation organized and existing under and by virtue of the laws of the State of New Mexico, hereinafter referred to as “PNM”; EL PASO ELECTRIC COMPANY, a corporation organized and existing under and by virtue of the laws of the State of Texas, hereinafter referred to as “El Paso”; SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, a joint powers agency organized and existing under and by virtue of the laws of the State of California, doing business  in the State of Arizona as SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY ASSOCIATION, hereinafter referred to as “SCPPA”; and DEPARTMENT OF WATER AND POWER OF THE CITY OF LOS ANGELES, a municipal corporation organized and existing under and by virtue of the laws of the State of California, hereinafter referred to as “LADWP”; all hereinafter individually referred to as “Party” and collectively as “Parties.”

2.RECITALS:

2.1.Arizona, Salt River Project, Edison, PNM, El Paso, SCPPA and LADWP are parties to a certain agreement entitled Arizona Nuclear Power Project Participation Agreement, dated as of August 23, 1973, as amended by: Amendment Number 1, dated as of January 1, 1974; Amendment Number 2, dated as of August 28,1975; Amendment Number 3, dated as of July 22, 1976; Amendment Number 4, dated as of December 15, 1977; Amendment Number 5, dated as of December 5, 1979; Amendment Number 6, effective as of October 16, 1981; Amendment Number 7, effective as of April 1, 1982; Amendment Number 8, executed as of September 12, 1983; Amendment Number 9, executed as of June 12, 1984 Amendment Number 10, executed as of November 21, 1985; Amendment Number 11, effective January 10, 1987; Amendment Number 12, effective August 5, 1988; Amendment Number 13, effective June 15, 1991; Amendment Number 14, effective June 20, 2000, retroactive to January 1, 1993; and Amendment Number 15, effective January 13, 2011, hereinafter, as so amended, collectively referred to as the “Participation Agreement.”

2.2.On April 21, 2011, the NRC, by letter to Arizona, confirmed the issuance of Renewed Facility Operating License Nos. NPF-41 (Unit 1), NPF-51 (Unit 2), and NPF -74 (Unit 3) for Palo Verde Station (collectively, the “License Extensions”).

2.3.Pursuant to the License Extensions, (i) Renewed Facility Operating License No. NPF-41 (Unit 1) expires at midnight on June 1, 2045; (ii) Renewed Facility Operating License No. NPF-51 (Unit 2) expires at midnight on April 24, 2046; and (iii) Renewed Facility Operating License No. NPF-74 (Unit 3) expires at midnight on November 25, 2047

(collectively, the “Extended License”).  The latest expiration date of the original licenses previously had been November 25, 2027.

2.4.Pursuant to Section 35.7 of the Participation Agreement, the latest termination date of the Participation Agreement currently is December 31, 2027, which does not include the License Extensions.

2.5Section 8A.4.4 of the Participation Agreement currently requires each Participant to accumulate Termination Funds over “the remaining license term (as specified in the original license issued for each Generating Unit . . . .” (emphasis added)

2.6.Arizona, PNM and El Paso (in Texas, not New Mexico) have already included in their cost of service the amounts for contributions to their decommissioning trust that reflect the Extended License (“60 Year Termination Funding Curves”), rather than the Original License (“40 Year Termination Funding Curves”), and collect from their respective ratepayers on that basis.

2.7The Termination Funding Committee currently uses the 40 Year Termination Funding Curves to measure compliance of the Participants with the termination funding requirements set forth in the Participation Agreement and the Termination Funding Committee Manual.  Therefore, the ability of Arizona, PNM and El Paso to meet their termination funding obligations is adversely impacted by the reduced recovery from their ratepayers under the 60 Year Termination Funding Curves, and their continuing obligation to maintain their Termination Funds at the higher levels required by the 40 Year Termination Funding Curves.

2.8On June 18, 2012, the Termination Funding Committee held its annual meeting to submit its Annual Funding Status Reports and to resolve the foregoing termination funding curve issues.  At the meeting, the Termination Funding Committee resolved, upon proper motion, that the 60 Year Termination Funding Curves were technically correct, and conditionally adopted the 60 Year Termination Funding Curves subject to the Administrative Committee’s extension of the Participation Agreement term.

2.9On October 19, 2012, the Administrative Committee unanimously voted to adopt this Amendment Number 16.

3.AGREEMENT:

For and in consideration of the premises and the mutual obligations of and undertakings by the Parties as hereinafter provided in this Amendment Number 16 to the Participation Agreement, the Parties agree as set forth below.

4.EFFECTIVE DATE:

This Amendment Number 16 shall become effective on the date that the Party which last in time executes this Amendment Number 16.  The amended termination funding curves that are associated with this Amendment Number 16 shall be applied retroactively to January 1, 2012.

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5.DEFINED TERMS:

5.1.The Capitalized and italicized words and phrases used in this Amendment Number 16 shall have the meanings ascribed to them in the Participation Agreement as amended by this Amendment Number 16.

5.2.All references to a “Section” or “Sections” in this Amendment Number 16 shall mean a Section or Sections of the Participation Agreement unless the text expressly states otherwise.

6.AMENDMENTS TO THE ARIZONA NUCLEAR POWER PROJECT MADE BY THIS AMENDMENT NUMBER 16:

6.1.Amend Section 8A.4.4, by deleting the strikethrough text and substituting therefore the underlined text:

“Within six months after the date on which Amendment No. 13 shall become effective or such other date established by the Administrative Committee, the Termination Funding Committee shall establish criteria and standards, consistent with applicable law, including the rules and regulations of the NRC [including without limitation such discount factors, allowances for inflation, bases for estimating future net earnings on accumulations in the Termination Fund(s) of the Participants and other elements as may be appropriate to provide reasonable assurance that each Participant will accumulate in its Termination Fund(s) over the then-applicable remaining license term for each Generating Unit (as specified in the original license issued for each Generating Unit authorizing fuel load and low power operation of such unit) sufficient funds to pay such Participant’s share of the most current estimate of the Termination Costs of such unit)] that will be used by the committee to determine whether or not the periodic deposits made by each Participant in its Termination Fund(s) have been adequate and the accumulations in its Termination Funds will be adequate to meet the requirements of Section 8A.7.2.3 hereof and to comply with applicable laws. At least once every three years the Termination Funding Committee shall review such criteria and standards and make such adjustments thereto as are warranted by the circumstances then existing or as may be required by applicable law. Additionally, the Termination Funding Committee shall establish the format, content and time for submission of the funding status reports and certificates that Participants are required to submit pursuant to Section 8A.7.2.4 hereof.”

6.2.Amend Section 35.7, by deleting the strikethrough text and substituting therefore the underlined text:

“This Participation Agreement shall terminate on the earlier of:  (i) the expiration date of the longest operating license period authorized by the NRC (or any governmental agency that is a successor to the NRC) for Palo Verde StationDecember 31, 2027, or (ii) the date on which all Generating Units shall have been permanently removed from service and all Termination Work in respect of all Generating/Terminated Units has been completed; provided, however, that . . .”

6.3.Except as amended by this Amendment Number 16, the remaining terms of the Participation Agreement shall remain in full force and effect.

7.EXECUTION BY COUNTERPARTS:

This Amendment Number 16 may be executed in any number of counterparts, whether by facsimile, electronic signature or otherwise, and upon execution by all Participants, each executed counterpart shall have the same force and effect as an original instrument and as if all Participants had signed the same instrument. Any signature page of this Amendment Number 16 may be detached from any

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counterpart of the Amendment Number 16 without impairing the legal effect of any signature thereon, and may be attached to another counterpart of this Amendment Number 16 identical in form hereto but having attached to it one or more signature pages.

8.SIGNATURE CLAUSE:

Each of the signatories below represents that he/she is appropriately authorized to enter into this Amendment Number 16 on behalf of the Party for which he/she signs.

ARIZONA PUBLIC SERVICE COMPANY
By:	/s/ Randall K. Edington
Its:	Executive Vice President/Chief Nuclear Officer
Date:	4/28/14

STATE OF ARIZONA	)
	) ss.
County of Maricopa	)

On this 28th day of April, 2012, before me, the undersigned Notary Public, personally appeared Randall K. Edington who acknowledged him/herself to be the Executive Vice President/Chief Nuclear Officer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, and that he/she as such officer, being authorized to do, executed the foregoing instrument for the purposes therein contained by signing the name of the company by him/herself as such Executive Vice President/Chief Nuclear Officer.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

	/s/ Jennifer R. Stokic
	Notary Public
My Commission Expires:
1-17-2015

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8.SIGNATURE CLAUSE:

Each of the signatories below represents that he/she is appropriately authorized to enter into this Amendment Number 16 on behalf of the Party for which he/she signs.

	SALT RIVER PROJECT AGRICULTURAL
	IMPROVEMENT AND POWER DISTRICT
	By:	/s/ Michael Hummel
	Its:	AGM& Chief Power System Executive
	Date:	April 10, 2014
ATTEST AND COUNTERSIGN:
By:
Its:
Date:

STATE OF ARIZONA	)
	) ss.
County of Maricopa	)

On this 10th day of  April, 2014, before me, the undersigned Notary Public, personally appeared Michael Hummel who acknowledged him/herself to be the AGM& Chief Power System Executive of SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an Arizona corporation, and that he/she as such officer, being authorized to do, executed the foregoing instrument for the purposes therein contained by signing the name of the company by him/herself as such AGM& Chief Power System Executive.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

/s/ Christina M. Hallows

Notary Public

My Commission Expires:

September 5, 2014

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8.SIGNATURE CLAUSE:

Each of the signatories below represents that he/she is appropriately authorized to enter into this Amendment Number 16 on behalf of the Party for which he/she signs.

SOUTHERN CALIFORNIA EDISON
COMPANY
By:	/s/ Thomas J. Palmisano
Its:	Vice-President & CNO
Date:	3/16/2014

STATE OF CALIFORNIA	)
	) ss.
County of Los Angeles	)

On this 16th day of April, 2014, before me, the undersigned Notary Public, personally appeared Thomas J. Palmisano who acknowledged him/herself to be the Vice-President of SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation, and that he/she as such officer, being authorized to do, executed the foregoing instrument for the purposes therein contained by signing the name of the company by him/herself as such Southern California Edison.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

	/s/ Brad Meindertsma
	Notary Public
My Commission Expires:
12-1-2015

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8.             SIGNATURE CLAUSE:

Each of the signatories below represents that he/she is appropriately authorized to enter into this Amendment Number 16 on behalf of the Party for which he/she signs.

PUBLIC SERVICE COMPANY OF NEW
MEXICO
By:	/s/ Ronald E. Talbot
Its:	SVP and COO
Date:	April 16, 2014

STATE OF NEW MEXICO	)
	) ss.
County of Bernalillo	)

On this 16th day of April, 2014, before me, the undersigned Notary Public, personally appeared Ronald E. Talbot who acknowledged him/herself to be the SVP and COO of PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation, and that he/she as such officer, being authorized to do, executed the foregoing instrument for the purposes therein contained by signing the name of the company by him/herself as such SVP and COO.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

	/s/ Susan G. Gordon
	Notary Public
My Commission Expires:
September 12, 2016

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8.             SIGNATURE CLAUSE:

Each of the signatories below represents that he/she is appropriately authorized to enter into this Amendment Number 16 on behalf of the Party for which he/she signs.

EL PASO ELECTRIC COMPANY
By:	/s/ T.V. Shockler
Its:	Chief Executive Officer
Date:	March 17, 2014

STATE OF TEXAS	)
	) ss.
County of El Paso	)

On this 17th day of March, 2014, before me, the undersigned Notary Public, personally appeared T.V. Shockler who acknowledged him/herself to be the Chief Executive Officer of EL PASO ELECTRIC COMPANY, a Texas corporation, and that he/she as such officer, being authorized to do, executed the foregoing instrument for the purposes therein contained by signing the name of the company by him/herself as such Chief Executive Officer.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

	/s/ Hilda Vargas
	Notary Public
My Commission Expires:
July 1, 2017

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8.             SIGNATURE CLAUSE:

Each of the signatories below represents that he/she is appropriately authorized to enter into this Amendment Number 16 on behalf of the Party for which he/she signs.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, doing business in the State of Arizona as SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY ASSOCIATION
By:	/s/ Ron Davis
Its:	President
Date:	December 20, 2012

STATE OF CALIFORNIA	)
	) ss.
County of Los Angeles	)

On this 20th day of  December, 2012, before me, the undersigned Notary Public, personally appeared Ron Davis who acknowledged him/herself to be the President of SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, doing business in the State of Arizona as SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY ASSOCIATION, a California joint powers agency, and that he/she as such officer, being authorized to do, executed the foregoing instrument for the purposes therein contained by signing the name of the company by him/herself as such                                                         .

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

	/s/ Salpi Ortiz
	Notary Public
My Commission Expires:
February 20, 2015

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8.             SIGNATURE CLAUSE:

Each of the signatories below represents that he/she is appropriately authorized to enter into this Amendment Number 16 on behalf of the Party for which he/she signs.

DEPARTMENT OF WATER AND
POWER OF THE CITY OF LOS
ANGELES
By:	/s/ Marcie L. Edwards
Its:	General Manager
Date:	March 31, 2014
And
By:	/s/ Barbara E. Moschos
Its:	Board Secretary
Date:	March 31, 2014

STATE OF CALIFORNIA	)
	) ss.
County of Los Angeles	)

On this 31st day of March, 2014, before me, the undersigned Notary Public, personally appeared Marcie L. Edwards who acknowledged him/herself to be the General Manager of DEPARTMENT OF WATER AND POWER  OF THE CITY OF LOS ANGELES, a California joint powers agency, and that he/she as such officer, being authorized to do, executed the foregoing instrument for the purposes therein contained by signing the name of the company by him/herself as such General Manager.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

	/s/ Reynan L. Ledesma
	Notary Public
My Commission Expires:
July 17, 2014

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EX-10.3

Exhibit 10.3

AMENDMENT NO. 7 TO FOUR CORNERS PROJECT CO-TENANCY AGREEMENT

THIS AMENDMENT NO. 7 TO FOUR CORNERS PROJECT CO-TENANCY AGREEMENT (this “Amendment”) is made and entered into as of December 30, 2013, by and among ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation (“Arizona”); EL PASO ELECTRIC COMPANY, a Texas corporation (“El Paso”); PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“New Mexico”); SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an agricultural improvement district, organized and existing under the laws of the State of Arizona (“Salt River Project”); SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation (“Edison”); and TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“Tucson”).  Arizona, El Paso, New Mexico, Salt River Project, Edison and Tucson are herein collectively referred to as the “Parties”.

RECITALS

The Parties entered into the Four Corners Project Co-Tenancy Agreement, effective as of July 19, 1966, and amendments thereto through Amendment No. 6, dated February 3, 2000 (as amended by such amendments, the “Co-Tenancy Agreement”), providing, among other things, for the allocation of ownership in the Four Corners Project.

Arizona and Edison are parties to a Purchase and Sale Agreement, dated as of November 8, 2010 (the “Purchase Agreement”), providing, among other things, for the sale by Edison to Arizona, and the purchase by Arizona from Edison, of Edison’s interests in the Four Corners Project and the Facilities Switchyard (the “Edison Interest Transfer”).

Following the Edison Interest Transfer, Arizona, the owner of the Initial Four Corners Plant, intends to retire Units 1, 2 and 3 of the Initial Four Corners Plant.

This Amendment will take effect on the Amendment No. 7 Effective Date, as defined herein.

STATEMENT OF AGREEMENT

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1.Defined Terms.  Defined terms used but not defined in this Amendment shall have the respective meanings ascribed to such terms in the Co-Tenancy Agreement.

2.Amendment of Section 1.  Section 1 is hereby amended to delete “SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation (hereinafter referred to as “Edison”);” from the eighth line thereof.

3.Amendment of Section 2.5.  Section 2.5 is hereby amended to substitute “Southern California Edison Company, a California corporation (hereinafter referred to as “Edison”)” for “Edison” in the first line thereof, and to add the following immediately following

the last sentence thereof:  “Amendment No. 7 to this Agreement (“Amendment No. 7”) provides, among other things, for updated ownership percentages as they existed following the consummation of the transfer to Arizona by Edison of Edison’s interests in the Four Corners Project pursuant to that certain Purchase and Sale Agreement, dated as of November 8, 2010 (the “Purchase Agreement”).  As of the effective date of Amendment No. 7, Edison is no longer a party to this Agreement, and all references to Edison as well as Edison’s designation as a Participant, as that term is defined in Section 5.27 herein, are limited to facts or matters occurring or agreements entered into prior to the effective date of Amendment No. 7.”

4.Amendment of Section 5.11(a).  Section 5.11(a) is hereby amended to delete the language after “Clerk,” in the sixth line and replace it with “as amended from time to time.”  References in the Co-Tenancy Agreement to the effective date thereof or of a particular provision or instrument shall mean the effective date of the original Co-Tenancy Agreement or of the particular provision or instrument when first referenced in the original Co-Tenancy Agreement as then amended.”

5.Amendment of Section 5.27.  Section 5.27 is hereby amended to delete “, Edison” in the second line thereof, to add the following clause immediately following “Project” in the third line thereof:  “, and, when referring specifically to facts or matters occurring or agreements entered into prior to the effective date of Amendment No. 7, Edison”,” and to add the following sentence immediately following the last sentence thereof:  “The term “Original Participants” shall refer to “Arizona, El Paso, New Mexico, Salt River Project, Edison and Tucson.”.

6.Amendment of Section 6.2.  Section 6.2 is hereby amended to read in full as follows:

“6.2  The Participants shall hold title to and own as tenants in common all the facilities forming part of the Four Corners Project (excluding the Common Facilities, the Switchyard Facilities, the New Facilities, the Related Facilities not included in the New Facilities, and the Reserve Auxiliary Power Source) as follows:

6.2.1  Arizona shall own an undivided 63% interest therein.

6.2.2  El Paso shall own an undivided 7% interest therein.

6.2.3  New Mexico shall own an undivided 13% interest therein.

6.2.4  Salt River Project shall own an undivided 10% interest therein.

6.2.5  Tucson shall own an undivided 7% interest therein.”

7.Amendment of Section 6.2(a).  Section 6.2(a) is hereby amended to read in full as follows:

“6.2(a)  The Participants shall hold title to and own as tenants in common the Related Facilities not included in the New Facilities existing on the effective date of Amendment No. 7 as follows:

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6.2(a)1  Arizona shall own an undivided 73.20% interest therein.

6.2(a)2  El Paso shall own an undivided 5.07% interest therein.

6.2(a)3  New Mexico shall own an undivided 9.42% interest therein.

6.2(a)4  Salt River Project shall own an undivided 7.24% interest therein.

6.2(a)5  Tucson shall own an undivided 5.07% interest therein.

The Participants shall hold title to and own as tenants in common all Related Facilities, including improvements thereto, acquired or constructed after the effective date of Amendment No. 7 as follows:

6.2(a)6  Arizona shall own an undivided 63% interest therein.

6.2(a)7  El Paso shall own an undivided 7% interest therein.

6.2(a)8  New Mexico shall own an undivided 13% interest therein.

6.2(a)9  Salt River Project shall own an undivided 10% interest therein.

6.2(a)10  Tucson shall own an undivided 7% interest therein.”

8.Amendment of Section 6.3.1.  Section 6.3.1 is hereby amended to substitute “63%” for “15%” in the first line thereof.

9.Amendment of Section 6.3.2.  Section 6.3.2 is hereby amended to substitute “[Reserved]” for the text thereof.

10.Amendment of Section 6.3(a)1.  Section 6.3(a)1 is hereby amended to substitute “Arizona” for “Edison” in the first line thereof.

11.Amendment of Section 6.4.1.  Section 6.4.1 is hereby amended to substitute “63%” for “15%” in the first line thereof.

12.Amendment of Section 6.4.2.  Section 6.4.2 is hereby amended to substitute “[Reserved]” for the text thereof.

13.Amendment of Section 6.5.  Section 6.5 is hereby amended read in full as follows:

“6.5  The Participants shall hold title to and own as tenants in common the Common Facilities and the Existing Related Facilities included in the New Facilities, in both cases, existing on the effective date of Amendment No. 7 as follows:

6.5.1  Arizona shall own an undivided 73.20% interest therein.

6.5.2  El Paso shall own an undivided 5.07% interest therein.

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6.5.3  New Mexico shall own an undivided 9.42% interest therein.

6.5.4  Salt River Project shall own an undivided 7.24% interest therein.

6.5.5  Tucson shall own an undivided 5.07% interest therein.

The Participants shall hold title to and own as tenants in common all Future Related Facilities, including improvements thereto, acquired or constructed after the effective date of Amendment No. 7 as follows:

6.5.6  Arizona shall own an undivided 63% interest therein.

6.5.7  El Paso shall own an undivided 7% interest therein.

6.5.8  New Mexico shall own an undivided 13% interest therein.

6.5.9  Salt River Project shall own an undivided 10% interest therein.

6.5.10  Tucson shall own an undivided 7% interest therein.”

14.Amendment of Section 6.6.1.  Section 6.6.1 is hereby amended to substitute “63%” for “15%” in the first line thereof.

15.Amendment of Section 6.6.2.  Section 6.6.2 is hereby amended to substitute “[Reserved]” for the text thereof.

16.Amendment of Section 6.7.  Section 6.7 is hereby amended to delete “Edison,” from the second line thereof.

17.Amendment of Section 6.8.  Section 6.8 is hereby amended to delete “Edison,” from the second line thereof.

18.Amendment of Section 6.9.  Section 6.9 is hereby amended to delete “Edison,” from the third line thereof.

19.Amendment of Section 7.1.1.  Section 7.1.1 is hereby amended to substitute “75.33%” for “43.33%” in the first line thereof.

20.Amendment of Section 7.1.2.  Section 7.1.2 is hereby amended to substitute “[Reserved]” for the text thereof.

21.Amendment of Section 7.2.1.  Section 7.2.1 is hereby amended to substitute “52.23%” for “40.23%” in the first line thereof.

22.Amendment of Section 7.2.2.  Section 7.2.2 is hereby amended to substitute “[Reserved]” for the text thereof.

23.Amendment of Section 7.3.1.  Section 7.3.1 is hereby amended to substitute “63%” for “15%” in the first line thereof.

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24.Amendment of Section 7.3.2.  Section 7.3.2 is hereby amended to substitute “[Reserved]” for the text thereof.

25.Amendment of Section 7.4.1.  Section 7.4.1 is hereby amended to substitute “57.90%” for “54.44%” in the first line thereof.

26.Amendment of Section 7.4.2.  Section 7.4.2 is hereby amended to substitute “[Reserved]” for the text thereof.

27.Amendment of Section 7.5.1.  Section 7.5.1 is hereby amended to substitute “62.45%” for “19.25%” in the first line thereof.

28.Amendment of Section 7.5.2.  Section 7.5.2 is hereby amended to substitute “[Reserved]” for the text thereof.

29.Amendment of Section 7.7.  Section 7.7 is hereby amended to delete “Edison,” from the second line thereof.

30.Amendment of Section 8.1.1.  Section 8.1.1 is hereby amended to substitute “63%” for “15%” in the first line thereof.

31.Amendment of Section 8.1.2.  Section 8.1.2 is hereby amended to substitute “[Reserved]” for the text thereof.

32.Amendment of Section 10.1.  Section 10.1 is hereby amended to read in full as follows:

“10.1If, because of emergency or planned shutdowns of Common Facilities or Related Facilities or the curtailment for any cause in the use thereof, Units 1, 2, 3 (prior to their respective retirements), 4 and 5 are not all operable simultaneously and continuously at their Net Effective Generating Capacity, then the reduced capacity entitlement of each Participant, because of the inability to operate said Units simultaneously and continuously at their Net Effective Generating Capacity, shall be determined as follows:

Reduced Capacity Entitlement of
Initial Four Corners Plant

C = N x NEGC1
              NEGC2

Reduced Capacity Entitlement of
Four Corners Project

CD1U = N x (NEGC2 — NEGC1) x P
                              NEGC2

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Where:

C = Reduced capacity entitlement of Arizona in Initial Four Corners Plant.

CD 1U = With respect to each Participant, the reduced capacity entitlement of such Participant in the Four Corners Project.

N = Reduced Net Effective Generating Capacity of the Enlarged Four Corners Generating Station.

NEGC1 = The Net Effective Generating Capacity of the Initial Four Corners Plant at the time of such emergency or planned shutdown or curtailment.

NEGC2 = The Net Effective Generating Capacity of the Enlarged Four Corners Generating Station at the time of such emergency or planned shutdown or curtailment.

P = With respect to each Participant, such Participant’s percentage of Net Effective Generation under Section 8.1.”

33.Amendment of Section 10.3.  Section 10.3 is hereby amended to read in full as follows:

“10.3Except as otherwise provided in this Section 10, no Participant shall exercise its rights relating to the Common Facilities or Related Facilities so as to endanger or unreasonably interfere with the operation of the Initial Four Corners Plant (prior to the retirement of each of Units 1, 2 and 3 of the Initial Four Corners Plant) or the Four Corners Project.”

34.Compliance with Section 13.11.2 and Section 13.12 of the Co-Tenancy Agreement.  In accordance with Section 13.11.2 of the Co-Tenancy Agreement, Arizona agrees to assume from and after the Amendment No. 7 Effective Date the obligations and duties of Edison under the Project Agreements.  In accordance with Section 13.12 of the Co-Tenancy Agreement, Arizona agrees that it shall not transfer or assign all or any portion of the Transfer Interest acquired by Arizona upon consummation of the Edison Interest Transfer without complying with Section 13 of the Co-Tenancy Agreement.

35.Amendment of Section 23.1.3.36.Section 23.1.3 is hereby amended to read in full as follows:

“23.1.3  Public Service Company of New Mexico
c/o Secretary
Main Offices
Albuquerque, New Mexico 87158-1245”

36.Amendment of Section 23.1.537..  Section 23.1.5 is hereby amended to substitute “[Reserved]” for the text thereof.

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37.Amendment of Exhibit 2, Figure 1.  Figure 1 of Exhibit 2 is hereby replaced in its entirety by Figure 1 attached to this Amendment.

38.Amendment No. 7 Effective Date; Termination.  The “Amendment No. 7 Effective Date” means the date of consummation of the Edison Interest Transfer pursuant to the Purchase Agreement (the “Edison Transfer Closing Date”); provided, however, that this Amendment will terminate if (a) Arizona or Edison provides written notice to the Parties to the effect that the Edison Transfer Closing Date will not occur, or (b) the Purchase Agreement is terminated, or (c) the Edison Transfer Closing Date does not occur on or prior to December 31, 2013.

39.Notices.  Any notice provided for in this Amendment shall be deemed properly served, given or made if delivered in person or sent by registered or certified mail, postage prepaid, to the persons specified below:

Arizona Public Service Company

c/o Secretary

P.O. Box 53999

Phoenix, Arizona 85072 3999

El Paso Electric Company

c/o Secretary

P.O. Box 982

El Paso, Texas 79960

Public Service Company of New Mexico

c/o Secretary

Main Offices

Albuquerque, New Mexico 87158-1245

Salt River Project Agricultural

Improvement and Power District

c/o Secretary

P.O. Box 1980

Phoenix, Arizona 85281

Southern California Edison Company

c/o Secretary

P.O. Box 800

Rosemead, California 91770

Tucson Electric Power Company

c/o Secretary

P.O. Box 711

Tucson, Arizona 85702

7

40.Effect of Amendment.  The Parties acknowledge and agree that (a) except as specifically amended by this Amendment, the Co-Tenancy Agreement is unamended, and (b) the Co-Tenancy Agreement, as amended by this Amendment, remains in full force and effect.

41.Counterparts; Facsimile.  This Amendment may be executed in any number of counterparts, each of which will be deemed an original, but all of which together shall constitute one and the same instrument.  Any facsimile copies hereof or signature hereon shall, for all purposes, be deemed originals.

8

IN WITNESS WHEREOF, the Parties have executed this Amendment as of the day and year first above written.

ARIZONA PUBLIC SERVICE COMPANY
By:	/s/ David A. Hansen
Its:	V.P. Fossil Generation
EL PASO ELECTRIC COMPANY
By:	/s/ T V Shockley
Its:	Chief Executive Officer
PUBLIC SERVICE COMPANY OF NEW MEXICO
By:	/s/ Chris Olson
Its:	Vice President, PNM Generation
SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT
By:	/s/ Mike Hummel
Its:	Associate General Manager & Chief
	Power System Executive
Reviewed by SRP Legal Services
By:	/s/ Karilee S. Ramaley
Its:	Senior Attorney
SOUTHERN CALIFORNIA EDISON COMPANY
By:	/s/ Robert C. Boada
Its:	Vice President and Treasurer
TUCSON ELECTRIC POWER COMPANY
By:	/s/ Mark Mansfield
Its:	VP Generation

Signature Page to

Amendment No. 7 to Project Co-Tenancy Agreement

EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Three Months Ended March 31,		Twelve Months Ended December 31,
	2014		2013		2012		2011		2010		2009
Earnings:
Income from continuing operations attributable to common shareholders	$	15,766	$	406,074	$	387,380	$	328,110	$	324,688	$	236,839
Income taxes	6,405		230,591		237,317		183,604		160,869		138,551
Fixed charges	54,851		206,089		219,437		246,462		248,664		241,807
Total earnings	$	77,022	$	842,754	$	844,134	$	758,176	$	734,221	$	617,197
Fixed Charges:
Interest expense	$	52,969	$	201,888	$	214,616	$	241,995	$	244,174	$	237,766
Estimated interest portion of annual rents	1,882		4,201		4,821		4,467		4,490		4,041
Total fixed charges	$	54,851	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Ratio of Earnings to Fixed Charges (rounded down)	1.40		4.08		3.84		3.07		2.95		2.55

EX-12.2

Exhibit 12.2

ARIZONA PUBLIC SERVICE COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Three Months Ended March 31,		Twelve Months Ended December 31,
	2014		2013		2012		2011		2010		2009
Earnings:
Income from continuing operations attributable to common shareholders	$	19,518	$	424,969	$	395,497	$	336,249	$	335,663	$	251,225
Income taxes	9,268		245,095		244,396		192,542		170,465		152,574
Fixed charges	53,084		202,457		214,227		238,286		234,184		227,274
Total earnings	$	81,870	$	872,521	$	854,120	$	767,077	$	740,312	$	631,073
Fixed Charges:
Interest charges	$	50,309	$	194,616	$	205,533	$	229,326	$	225,269	$	218,969
Amortization of debt discount	1,011		4,046		4,215		4,616		4,559		4,675
Estimated interest portion of annual rents	1,764		3,795		4,479		4,344		4,356		3,630
Total fixed charges	$	53,084	$	202,457	$	214,227	$	238,286	$	234,184	$	227,274
Ratio of Earnings to Fixed Charges (rounded down)	1.54		4.30		3.98		3.21		3.16		2.77

EX-12.3

Exhibit 12.3

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED

STOCK DIVIDEND REQUIREMENTS

(dollars in thousands)

	Three Months Ended March 31,		Twelve Months Ended December 31,
	2014		2013		2012		2011		2010		2009
Earnings:
Income from continuing operations attributable to common shareholders	$	15,766	$	406,074	$	387,380	$	328,110	$	324,688	$	236,839
Income taxes	6,405		230,591		237,317		183,604		160,869		138,551
Fixed charges	54,851		206,089		219,437		246,462		248,664		241,807
Total earnings	$	77,022	$	842,754	$	844,134	$	758,176	$	734,221	$	617,197
Fixed Charges:
Interest expense	$	52,969	$	201,888	$	214,616	$	241,995	$	244,174	$	237,766
Estimated interest portion of annual rents	1,882		4,201		4,821		4,467		4,490		4,041
Total fixed charges	$	54,851	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	22,171	$	636,665	$	624,697	$	511,714	$	485,557	$	375,390
Net income from continuing operations attributable to common shareholders	15,766		406,074		387,380		328,110		324,688		236,839
Ratio of income before income taxes to net income	1.41		1.57		1.61		1.56		1.50		1.59
Preferred stock dividends	—		—		—		—		—		—
Preferred stock dividend requirements — ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	54,851	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Preferred stock dividend requirements	—		—		—		—		—		—
Total	$	54,851	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Ratio of Earnings to Fixed Charges (rounded down)	1.40		4.08		3.84		3.07		2.95		2.55

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Donald E. Brandt, certify that:

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

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

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

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

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

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

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

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

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

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

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

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

Date:May 2, 2014
	/s/ Donald E. Brandt
	Donald E. Brandt
	Chairman, President and Chief Executive Officer

2

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James R. Hatfield, certify that:

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

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

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

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

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

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

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

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

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

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

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

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

Date:May 2, 2014
	/s/ James R. Hatfield
	James R. Hatfield
	Executive Vice President and Chief Financial Officer

2

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Donald E. Brandt, certify that:

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

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

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

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

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

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

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

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

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

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

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

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

Date:      May 2, 2014.

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

2

EX-31.4

Exhibit 31.4

CERTIFICATION

I, James R. Hatfield, certify that:

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

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

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

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

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

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

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

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

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

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

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

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

Date:May 2, 2014

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

2

EX-32.1

Exhibit 32.1

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

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended March 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:May 2, 2014

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended March 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:May 2, 2014

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

EX-32.2

Exhibit 32.2

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

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended March 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:May 2, 2014

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended March 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:May 2, 2014

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

XML

Regulatory Matters (Details 3) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Detail of regulatory assets
Regulatory assets, current	$ 76,000,000	$ 97,000,000
Regulatory assets, non-current	719,596,000	711,712,000
Pension and other postretirement benefits
Detail of regulatory assets
Regulatory assets, non-current	313,000,000	314,000,000
Income taxes - allowance for funds used during construction ("AFUDC") equity
Detail of regulatory assets
Regulatory assets, current	4,000,000	4,000,000
Regulatory assets, non-current	104,000,000	105,000,000
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current		5,000,000
Regulatory assets, non-current	26,000,000	29,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	12,000,000	14,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	8,000,000	8,000,000
Regulatory assets, non-current	16,000,000	18,000,000
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, non-current	42,000,000	41,000,000
Deferred compensation
Detail of regulatory assets
Regulatory assets, non-current	36,000,000	34,000,000
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current		21,000,000
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	15,000,000	15,000,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	18,000,000	17,000,000
Income taxes - investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	39,000,000	39,000,000
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	8,000,000	8,000,000
Regulatory assets, non-current	2,000,000	4,000,000
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, non-current	47,000,000	37,000,000
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	32,000,000	25,000,000
Transmission cost adjustor
Detail of regulatory assets
Regulatory assets, current	6,000,000	8,000,000
Regulatory assets, non-current	2,000,000	2,000,000
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	3,000,000	3,000,000
Regulatory assets, non-current	17,000,000	18,000,000
Other
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	$ 31,000,000	$ 25,000,000

XML

Fair Value Measurements (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Assets
Nuclear decommissioning trust	$ 657,862,000	$ 642,007,000
Total assets	36,000,000	41,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Nuclear decommissioning trust	120,000,000	107,000,000
Total assets	120,000,000	107,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Nuclear decommissioning trust	120,000,000	107,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Risk management activities-derivative instruments: Commodity contracts	21,000,000	9,000,000
Nuclear decommissioning trust	543,000,000	538,000,000
Total assets	564,000,000	547,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(23,000,000)	(33,000,000)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Nuclear decommissioning trust	277,000,000	272,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	14,000,000	11,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	96,000,000	88,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	79,000,000	85,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Nuclear decommissioning trust	64,000,000	71,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Nuclear decommissioning trust	13,000,000	11,000,000
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Risk management activities-derivative instruments: Commodity contracts	36,000,000	41,000,000
Total assets	36,000,000	41,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(85,000,000)	(90,000,000)
Fair value measurement on a recurring basis | Other
Assets
Risk management activities-derivative instruments: Commodity contracts	(18,000,000)	(9,000,000)
Nuclear decommissioning trust	(5,000,000)	(3,000,000)
Total assets	(23,000,000)	(12,000,000)
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	59,000,000	21,000,000
Fair value measurement on a recurring basis | Other | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	(5,000,000)	(3,000,000)
Fair value measurement on a recurring basis | Fair Value
Assets
Risk management activities-derivative instruments: Commodity contracts	39,000,000	41,000,000
Nuclear decommissioning trust	658,000,000	642,000,000
Total assets	697,000,000	683,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(49,000,000)	(102,000,000)
Fair value measurement on a recurring basis | Fair Value | US commingled equity funds
Assets
Nuclear decommissioning trust	277,000,000	272,000,000
Fair value measurement on a recurring basis | Fair Value | U.S. Treasury
Assets
Nuclear decommissioning trust	120,000,000	107,000,000
Fair value measurement on a recurring basis | Fair Value | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	9,000,000	8,000,000
Fair value measurement on a recurring basis | Fair Value | Corporate debt
Assets
Nuclear decommissioning trust	96,000,000	88,000,000
Fair value measurement on a recurring basis | Fair Value | Mortgage-backed securities
Assets
Nuclear decommissioning trust	79,000,000	85,000,000
Fair value measurement on a recurring basis | Fair Value | Municipality bonds
Assets
Nuclear decommissioning trust	64,000,000	71,000,000
Fair value measurement on a recurring basis | Fair Value | Other
Assets
Nuclear decommissioning trust	$ 13,000,000	$ 11,000,000

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Changes in Equity (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Changes in equity
Balance	$ 4,340,460	$ 4,102,289
Net income	24,691	32,836
Other comprehensive income	3,151	6,077
COMPREHENSIVE INCOME	27,842	38,913
Issuance of capital stock	2,592	2,574
Reissuance (purchase) of treasury stock - net	3,465	(6,271)
Other (primarily stock compensation)	3,342	14,825
Balance	4,377,701	4,152,330
Common Shareholders
Changes in equity
Balance	4,194,470	3,972,806
Net income	15,766	24,444
Other comprehensive income	3,151	6,077
COMPREHENSIVE INCOME	18,917	30,521
Issuance of capital stock	2,592	2,574
Reissuance (purchase) of treasury stock - net	3,465	(6,271)
Other (primarily stock compensation)	3,342	14,825
Balance	4,222,786	4,014,455
Noncontrolling Interests
Changes in equity
Balance	145,990	129,483
Net income	8,925	8,392
COMPREHENSIVE INCOME	8,925	8,392
Balance	$ 154,915	$ 137,875

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Other Income and Other Expense (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Other income:
Interest income	$ 251	$ 76
Miscellaneous	2,116	682
Total other income	2,367	758
Other expense:
Non-operating costs	(2,372)	(1,932)
Miscellaneous	(2,172)	(1,708)
Total other expense	(4,684)	(3,752)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	138	23
Miscellaneous	2,624	1,320
Total other income	2,762	1,343
Other expense:
Non-operating costs	(2,587)	(2,320)
Asset dispositions	(183)	(1,264)
Miscellaneous	(2,286)	(2,712)
Total other expense	$ (5,056)	$ (6,296)

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended					3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended			3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended			3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2014 Electricity forward contracts	Dec. 31, 2013 Electricity forward contracts	Mar. 31, 2014 Electricity forward contracts Minimum Discounted cash flows	Dec. 31, 2013 Electricity forward contracts Minimum Discounted cash flows	Mar. 31, 2014 Electricity forward contracts Maximum Discounted cash flows	Dec. 31, 2013 Electricity forward contracts Maximum Discounted cash flows	Mar. 31, 2014 Electricity forward contracts Weighted Average Discounted cash flows	Dec. 31, 2013 Electricity forward contracts Weighted Average Discounted cash flows	Mar. 31, 2014 Option Contracts	Dec. 31, 2013 Option Contracts	Mar. 31, 2014 Option Contracts Minimum Option model	Dec. 31, 2013 Option Contracts Minimum Option model	Mar. 31, 2014 Option Contracts Maximum Option model	Dec. 31, 2013 Option Contracts Maximum Option model	Mar. 31, 2014 Option Contracts Weighted Average Option model	Dec. 31, 2013 Option Contracts Weighted Average Option model	Mar. 31, 2014 Natural gas forward contracts	Dec. 31, 2013 Natural gas forward contracts	Mar. 31, 2014 Natural gas forward contracts Minimum Discounted cash flows	Dec. 31, 2013 Natural gas forward contracts Minimum Discounted cash flows	Mar. 31, 2014 Natural gas forward contracts Maximum Discounted cash flows	Dec. 31, 2013 Natural gas forward contracts Maximum Discounted cash flows	Mar. 31, 2014 Natural gas forward contracts Weighted Average Discounted cash flows	Dec. 31, 2013 Natural gas forward contracts Weighted Average Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 36		$ 41	$ 34	$ 40															$ 2	$ 1
Liabilities	85		90	60	66							22	19							3	5
Electricity forward price (per MWh)						23.13	24.89	67.47	65.04	42.28	41.09			40.32	39.91	93.94	85.41	60.49	58.70
Electricity price volatilities (as a percent)														24.00%	35.00%	100.00%	94.00%	52.00%	59.00%
Natural gas forward price (per MMbtu)														3.64	3.57	3.84	3.80	3.76	3.71			3.60	3.47	4.40	4.31	3.91	3.87
Natural gas price volatilities (as a percent)														23.00%	22.00%	44.00%	36.00%	30.00%	27.00%
Changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs
Net derivative balance at beginning of period	(49)	(48)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	4	(1)
Settlements		(2)
Transfers into Level 3 from Level 2	(3)	(1)
Transfers from Level 3 into Level 2	(1)	(1)
Net derivative balance at end of period	(49)	(53)
Transfers in or out of Level 1 to or from any other hierarchy level	$ 0

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Derivative Accounting (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Commodity Contracts
Assets
Amount Reported on Balance Sheet	$ 39,000
Assets and Liabilities
Gross Recognized Derivatives	(51,289)	(72,712)
Amounts Offset	49,199	19,000
Net Recognized Derivatives	(2,090)	(53,712)
Other	(8,346)	(7,511)
Amount Reported on Balance Sheet	(10,436)	(61,223)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	32,470	24,587
Amounts Offset	(15,816)	(7,425)
Net Recognized Derivatives	16,654	17,162
Other	297	7
Amount Reported on Balance Sheet	16,951	17,169
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	23,913	25,364
Amounts Offset	(2,287)	(1,549)
Net Recognized Derivatives	21,626	23,815
Amount Reported on Balance Sheet	21,626	23,815
Commodity Contracts | Total Assets
Assets
Gross Recognized Derivatives	56,383	49,951
Amounts Offset	(18,103)	(8,974)
Net Recognized Derivatives	38,280	40,977
Other	297	7
Amount Reported on Balance Sheet	38,577	40,984
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(42,161)	(50,540)
Amounts Offset	30,897	26,166
Net Recognized Derivatives	(11,264)	(24,374)
Other	(8,643)	(7,518)
Amount Reported on Balance Sheet	(19,907)	(31,892)
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(65,511)	(72,123)
Amounts Offset	36,405	1,808
Net Recognized Derivatives	(29,106)	(70,315)
Amount Reported on Balance Sheet	(29,106)	(70,315)
Commodity Contracts | Total Liabilities
Liabilities
Gross Recognized Derivatives	(107,672)	(122,663)
Amounts Offset	67,302	27,974
Net Recognized Derivatives	(40,370)	(94,689)
Other	(8,643)	(7,518)
Amount Reported on Balance Sheet	(49,013)	(102,207)
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	$ 4,000	$ 5,000

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Nuclear Decommissioning Trusts (Tables)

3 Months Ended

Mar. 31, 2014

Nuclear Decommissioning Trusts

Fair value of APS's nuclear decommissioning trust fund assets

The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at March 31, 2014 and December 31, 2013 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2014
Equity securities	$	277		$	132	$	—
Fixed income securities	386			13		(3		)
Net payables (a)	(5		)	—		—
Total	$	658		$	145	$	(3	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2013
Equity securities	$	272		$	129	$	—
Fixed income securities	373			11		(6		)
Net payables (a)	(3		)	—		—
Total	$	642		$	140	$	(6	)

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

Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds

The following table sets forth approximate realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Three Months Ended March 31,
	2014			2013
Realized gains	$	1		$	2
Realized losses	(2		)	(1		)
Proceeds from the sale of securities (a)	103			135

(a) Proceeds are reinvested in the trust.

Fair value of fixed income securities, summarized by contractual maturities

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2014 is as follows (dollars in millions):

	Fair Value
Less than one year	$	17
1 year — 5 years	109
5 years — 10 years	111
Greater than 10 years	149
Total	$	386

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Changes in Accumulated Other Comprehensive Loss (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (78,053)	$ (114,008)
OCI (loss) before reclassifications	(422)	58
Amounts reclassified from accumulated other comprehensive loss	3,573	6,019
Total other comprehensive income	3,151	6,077
Ending balance	(74,902)	(107,931)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(23,058)	(49,592)
OCI (loss) before reclassifications	(422)	58
Amounts reclassified from accumulated other comprehensive loss	3,116	5,053
Total other comprehensive income	2,694	5,111
Ending balance	(20,364)	(44,481)
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(54,995)	(64,416)
Amounts reclassified from accumulated other comprehensive loss	457	966
Total other comprehensive income	457	966
Ending balance	$ (54,538)	$ (63,450)

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Changes in Accumulated Other Comprehensive Loss (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (78,053)	$ (114,008)
OCI (loss) before reclassifications	(422)	58
Amounts reclassified from accumulated other comprehensive loss	3,573	6,019
Total other comprehensive income	3,151	6,077
Ending balance	(74,902)	(107,931)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(23,058)	(49,592)
OCI (loss) before reclassifications	(422)	58
Amounts reclassified from accumulated other comprehensive loss	3,116	5,053
Total other comprehensive income	2,694	5,111
Ending balance	(20,364)	(44,481)
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(54,995)	(64,416)
Amounts reclassified from accumulated other comprehensive loss	457	966
Total other comprehensive income	457	966
Ending balance	(54,538)	(63,450)
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(53,372)	(89,095)
OCI (loss) before reclassifications	(421)	58
Amounts reclassified from accumulated other comprehensive loss	3,682	5,934
Total other comprehensive income	3,261	5,992
Ending balance	(50,111)	(83,103)
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(23,059)	(49,592)
OCI (loss) before reclassifications	(421)	58
Amounts reclassified from accumulated other comprehensive loss	3,116	5,052
Total other comprehensive income	2,695	5,110
Ending balance	(20,364)	(44,482)
ARIZONA PUBLIC SERVICE COMPANY | Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(30,313)	(39,503)
Amounts reclassified from accumulated other comprehensive loss	566	882
Total other comprehensive income	566	882
Ending balance	$ (29,747)	$ (38,621)

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Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2014

Regulatory Matters

Schedule of changes in the deferred fuel and purchased power regulatory asset (liability)

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2014 and 2013 (dollars in millions):

	Three Months Ended March 31,
	2014			2013
Beginning balance	$	21		$	73
Deferred fuel and purchased power costs — current period	(32		)	(31		)
Amounts charged to customers	(8		)	(1		)
Ending balance	$	(19	)	$	41

Schedule of regulatory assets

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

	Remaining Amortization	March 31, 2014				December 31, 2013
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)	$	—	$	313	$	—	$	314
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2043	4		104		4		105
Deferred fuel and purchased power — mark-to-market (Note 7)	2016	—		26		5		29
Transmission vegetation management	2016	9		12		9		14
Coal reclamation	2038	8		16		8		18
Palo Verde VIEs (Note 6)	2046	—		42		—		41
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		21		—
Tax expense of Medicare subsidy	2023	2		15		2		15
Loss on reacquired debt	2034	1		18		1		17
Income taxes — investment tax credit basis adjustment	2043	1		39		1		39
Pension and other postretirement benefits deferral	2015	8		2		8		4
Four Corners cost deferral	2024	—		47		—		37
Lost fixed cost recovery (b)	2015	32		—		25		—
Transmission cost adjustor (b)	2016	6		2		8		2
Retired power plant costs	2020	3		17		3		18
Other	Various	2		31		2		25
Total regulatory assets (d)		$	76	$	720	$	97	$	712

(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.  See Note 4 for further discussion.

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

(c) Subject to a carrying charge.

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

Schedule of regulatory liabilities

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

	Remaining Amortization	March 31, 2014				December 31, 2013
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	28	$	298	$	28	$	303
Asset retirement obligations	(a)	—		253		—		266
Renewable energy standard (b)	2015	35		16		33		15
Income taxes — change in rates	2043	1		73		—		74
Spent nuclear fuel	2047	5		37		6		36
Deferred gains on utility property	2019	2		9		2		10
Income taxes — deferred investment tax credit	2043	3		79		3		79
Demand side management (b)	2015	34		—		27		—
Deferred fuel and purchased power (b) (c)	2015	19		—		—		—
Deferred fuel and purchased power — mark to market	2015	9		—		—		—
Other	Various	—		19		—		18
Total regulatory liabilities		$	136	$	784	$	99	$	801

(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.

(c) Subject to carrying charge.

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Commitments and Contingencies (Details 2) (ARIZONA PUBLIC SERVICE COMPANY, USD $) In Millions, unless otherwise specified	0 Months Ended	1 Months Ended	3 Months Ended		0 Months Ended
	Jan. 22, 2014 item	Sep. 30, 2011 MW item kV	Mar. 31, 2014 item	Sep. 08, 2011	Aug. 06, 2013 Contaminated groundwater wells item
Superfund-Related Matters
Costs related to investigation and study under Superfund site			$ 2
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit					24
Southwest Power Outage
Capacity of transmission line that tripped out of service (in kV)		500
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost		10 minutes
Number of customers losing service in Yuma area		69,700
Capacity of firm load that were reported to have been affected due to outages affecting portions of southern Arizona, southern California and northern Mexico (in MW)		7,900
Number of customers that were reported to have been affected due to outages		2,700,000
Number of alleged entities	6
Number of Reliability Standard Requirements Violations alleged	7
Maximum possible fine per violation per day that the violation is found to have been in existence				1
Financial Assurances
Outstanding letters of credit to support existing variable interest rate pollution control bonds			76
Number of letters of credit expiring in 2015			1
Number of letters of credit expiring in 2016			2
Letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions			24
Outstanding letters of credit to support natural gas tolling contract obligations			$ 5

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Income Taxes
Income tax refunds	$ 135
Increase (decrease) in deferred income taxes due to adoption of regulations	29
Palo Verde VIE
Income Taxes
Income tax expense associates with the VIE's	0
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Increase (decrease) in deferred income taxes due to adoption of regulations	$ 16

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Regulatory Matters (Details) (USD $)	3 Months Ended				0 Months Ended	1 Months Ended			1 Months Ended	0 Months Ended	3 Months Ended				0 Months Ended		3 Months Ended				1 Months Ended		3 Months Ended		0 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 APS	Mar. 31, 2013 APS	Dec. 03, 2013 APS ACC Net Metering	Jan. 31, 2012 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing	Jun. 30, 2011 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing	Jan. 06, 2012 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing	Jan. 31, 2012 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing Maximum	Dec. 30, 2013 Filing with the Arizona Corporation Commission APS ACC Residential customers rate case filing	Mar. 31, 2014 Cost Recovery Mechanisms Power Supply Adjustor (PSA)	Mar. 31, 2014 Cost Recovery Mechanisms APS 2013 DSMAC	Dec. 31, 2012 Cost Recovery Mechanisms APS 2013 DSMAC	Mar. 31, 2014 Cost Recovery Mechanisms APS 2014 DSMAC	Mar. 02, 2014 Cost Recovery Mechanisms APS Lost Fixed Cost Recovery Mechanism	Feb. 12, 2013 Cost Recovery Mechanisms APS Lost Fixed Cost Recovery Mechanism	Mar. 31, 2014 Cost Recovery Mechanisms APS Lost Fixed Cost Recovery Mechanism	Mar. 31, 2014 Cost Recovery Mechanisms APS ACC RES	Jun. 02, 2012 Cost Recovery Mechanisms APS ACC 2013 DSMAC	Jul. 12, 2013 Cost Recovery Mechanisms APS ACC RES implementation plan covering 2014-2018 timeframe	Feb. 28, 2014 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA)	Feb. 28, 2013 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA)	Mar. 31, 2014 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA)	Mar. 31, 2013 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA)	Jun. 01, 2013 Cost Recovery Mechanisms APS FERC Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters
Regulatory Matters
Net retail rate increase							$ 95,500,000
Approximate percentage of increase in the average retail customer bill							6.60%
Settlement Agreement
Net change in base rates						0
Non-fuel base rate increase						116,300,000
Fuel-related base rate decrease						153,100,000
Current base fuel rate (in dollars per kWh)						0.03757
Approved base fuel rate (in dollars per kWh)						0.03207
Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates						36,800,000
Authorized return on common equity (as a percent)						10.00%
Percentage of debt in capital structure						46.10%
Percentage of common equity in capital structure						53.90%
Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent)								25.00%
Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent)								50.00%
Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent)								75.00%
Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent)								100.00%
Approximate percentage of increase in the average retail customer bill under proposed Four Corners rate filing										2.00%
Annual cost recovery due to modifications to the Environmental Improvement Surcharge									5,000,000
Elimination of the sharing provision of fuel and purchased power costs						9
Period to process the subsequent rate cases						12 months
ACC staff sufficiency findings, general period of time						30 days
Change in regulatory asset
Plan term																		5 years
Amount of proposed budget													87,600,000							143,000,000
Amount of approved budget												68,900,000		68,900,000
Percentage of cumulative energy savings for current year																			5.00%
Beginning balance																							21,000,000	73,000,000
Deferred fuel and purchased power costs-current period	(31,630,000)	(31,194,000)	(31,630,000)	(31,194,000)																			(32,000,000)	(31,000,000)
Amounts charged to customers	(8,022,000)	(1,122,000)	(8,022,000)	(1,122,000)																			(8,000,000)	(1,000,000)
Ending balance																							(19,000,000)	41,000,000
Charge on future customers who install rooftop solar panels (in dollars per kWh)					0.70
Estimated monthly collection due to charge on future customers who install rooftop solar panels					4.90
PSA rate (in dollars per kWh)																					0.001557
PSA rate for prior year (in dollars per kWh)																						0.001329
Forward component of increase in PSA (in dollars per kWh)											0.001277
Historical component of increase in PSA (in dollars per kWh)											0.000280
Increase in annual wholesale transmission rates																									26,000,000
Fixed costs recoverable per residential power lost (in dollars per kWh)																	0.031
Fixed costs recoverable per non-residential power lost (in dollars per kWh)																	0.023
Amount of adjustment approved representing prorated sales losses															$ 25,300,000	$ 5,100,000

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Other Income and Other Expense (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Other income:
Interest income	$ 251	$ 76
Miscellaneous	2,116	682
Total other income	2,367	758
Other expense:
Non-operating costs	(2,372)	(1,932)
Investment losses - net	(140)	(112)
Miscellaneous	(2,172)	(1,708)
Total other expense	$ (4,684)	$ (3,752)

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Other Income and Other Expense (APSC) (Tables)

3 Months Ended

Mar. 31, 2014

Detail of other income and other expense

The following table provides detail of other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	251		$	76
Miscellaneous	2,116			682
Total other income	$	2,367		$	758
Other expense:
Non-operating costs	$	(2,372	)	$	(1,932	)
Investment losses — net	(140		)	(112		)
Miscellaneous	(2,172		)	(1,708		)
Total other expense	$	(4,684	)	$	(3,752	)

ARIZONA PUBLIC SERVICE COMPANY

Detail of other income and other expense

The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	138		$	23
Miscellaneous	2,624			1,320
Total other income	$	2,762		$	1,343
Other expense:
Non-operating costs (a)	$	(2,587	)	$	(2,320	)
Asset dispositions	(183		)	(1,264		)
Miscellaneous	(2,286		)	(2,712		)
Total other expense	$	(5,056	)	$	(6,296	)

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (APSC) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$ 15,256,945	$ 15,200,464
Accumulated depreciation and amortization	(5,360,781)	(5,300,219)
Net	9,896,164	9,900,245
Construction work in progress	646,236	581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	124,157	125,125
Intangible assets, net of accumulated amortization	144,446	157,689
Nuclear fuel, net of accumulated amortization	144,048	124,557
Total property, plant and equipment	10,955,051	10,888,985
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	657,862	642,007
Assets from risk management activities (Note 7)	21,626	23,815
Other assets	60,753	60,875
Total investments and other assets	740,241	726,697
CURRENT ASSETS
Cash and cash equivalents	103,421	9,526
Customer and other receivables	245,884	299,904
Accrued unbilled revenues	88,907	96,796
Allowance for doubtful accounts	(2,504)	(3,203)
Materials and supplies (at average cost)	223,401	221,682
Fossil fuel (at average cost)	36,496	38,028
Income tax receivable	4,647	135,517
Assets from risk management activities (Note 7)	16,951	17,169
Deferred fuel and purchased power regulatory asset (Note 3)		20,755
Other regulatory assets (Note 3)	76,317	76,388
Other current assets	45,780	39,895
Total current assets	897,930	1,043,609
DEFERRED DEBITS
Regulatory assets (Note 3)	719,596	711,712
Other	137,979	137,683
Total deferred debits	857,575	849,395
TOTAL ASSETS	13,450,797	13,508,686
CAPITALIZATION
Common stock	2,496,641	2,487,250
Retained earnings	1,801,047	1,785,273
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(54,538)	(54,995)
Derivative instruments	(20,364)	(23,058)
Total shareholders' equity	4,222,786	4,194,470
Noncontrolling interests (Note 6)	154,915	145,990
Total equity	4,377,701	4,340,460
CURRENT LIABILITIES
Short-term borrowings (Note 2)	9,500	153,125
Current maturities of long-term debt (Note 2)	540,424	540,424
Accounts payable	224,820	284,516
Accrued taxes (Note 5)	179,137	130,998
Accrued interest	47,392	48,351
Common dividends payable		62,528
Customer deposits	75,999	76,101
Liabilities from risk management activities (Note 7)	19,907	31,892
Deferred fuel and purchased power regulatory liability (Note 3)	18,897
Other regulatory liabilities (Note 3)	116,903	99,273
Other current liabilities	136,128	158,540
Total current liabilities	1,394,643	1,618,644
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,359,689	2,351,882
Regulatory liabilities (Note 3)	783,702	801,297
Liabilities for asset retirements	344,708	313,833
Liabilities for pension and other postretirement benefits (Note 4)	442,136	513,628
Liabilities from risk management activities (Note 7)	29,106	70,315
Customer advances	115,033	114,480
Coal mine reclamation	208,183	207,453
Deferred investment tax credit	152,114	152,361
Unrecognized tax benefits (Note 5)	13,502	42,209
Other	184,666	185,659
Total deferred credits and other	4,632,839	4,753,117
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	13,450,797	13,508,686
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,253,694	15,196,598
Accumulated depreciation and amortization	(5,357,699)	(5,296,501)
Net	9,895,995	9,900,097
Construction work in progress	646,236	581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	124,157	125,125
Intangible assets, net of accumulated amortization	144,291	157,534
Nuclear fuel, net of accumulated amortization	144,048	124,557
Total property, plant and equipment	10,954,727	10,888,682
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	657,862	642,007
Assets from risk management activities (Note 7)	21,626	23,815
Other assets	34,411	33,709
Total investments and other assets	713,899	699,531
CURRENT ASSETS
Cash and cash equivalents	103,400	3,725
Customer and other receivables	245,272	299,055
Accrued unbilled revenues	88,907	96,796
Allowance for doubtful accounts	(2,504)	(3,203)
Materials and supplies (at average cost)	223,401	221,682
Fossil fuel (at average cost)	36,496	38,028
Income tax receivable	289	135,179
Assets from risk management activities (Note 7)	16,951	17,169
Deferred fuel and purchased power regulatory asset (Note 3)		20,755
Other regulatory assets (Note 3)	76,317	76,388
Other current assets	45,176	39,153
Total current assets	833,705	944,727
DEFERRED DEBITS
Regulatory assets (Note 3)	719,596	711,712
Unamortized debt issue costs	22,686	21,860
Other	114,437	114,865
Total deferred debits	856,719	848,437
TOTAL ASSETS	13,359,050	13,381,377
CAPITALIZATION
Common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,823,914	1,804,398
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(29,747)	(30,313)
Derivative instruments	(20,364)	(23,059)
Total shareholders' equity	4,331,661	4,308,884
Noncontrolling interests (Note 6)	154,915	145,990
Total equity	4,486,576	4,454,874
Long-term debt less current maturities (Note 2)	2,920,614	2,671,465
Total capitalization	7,407,190	7,126,339
CURRENT LIABILITIES
Short-term borrowings (Note 2)		153,125
Current maturities of long-term debt (Note 2)	540,424	540,424
Accounts payable	219,910	281,237
Accrued taxes (Note 5)	173,040	122,460
Accrued interest	47,207	48,132
Common dividends payable		62,500
Customer deposits	75,999	76,101
Deferred income taxes	21,951	2,033
Liabilities from risk management activities (Note 7)	19,907	31,892
Liabilities for asset retirements	25,536	32,896
Deferred fuel and purchased power regulatory liability (Note 3)	18,897
Other regulatory liabilities (Note 3)	116,903	99,273
Other current liabilities	118,934	130,774
Total current liabilities	1,378,708	1,580,847
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,355,237	2,347,724
Regulatory liabilities (Note 3)	783,702	801,297
Liabilities for asset retirements	344,708	313,833
Liabilities for pension and other postretirement benefits (Note 4)	405,597	476,017
Liabilities from risk management activities (Note 7)	29,106	70,315
Customer advances	115,033	114,480
Coal mine reclamation	208,183	207,453
Deferred investment tax credit	152,114	152,361
Unrecognized tax benefits (Note 5)	26,284	42,209
Other	153,188	148,502
Total deferred credits and other	4,573,152	4,674,191
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$ 13,359,050	$ 13,381,377

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Derivative Accounting (Details 4) (Commodity Contracts, USD $)	3 Months Ended
	Mar. 31, 2014 item
Commodity Contracts
Credit Risk and Credit-Related Contingent Features
Concentration of credit risk, number of counterparties	2
Concentration of risk with two counterparties, as a percentage of risk management assets	84.00%
Risk management activities-derivative instruments: Commodity Contracts	$ 39,000,000
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	108,000,000
Cash Collateral Posted	49,000,000
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	50,000,000
Additional collateral to counterparties for energy related non-derivative instrument contracts	$ 180,000,000

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Long-Term Debt and Liquidity Matters

3 Months Ended

Mar. 31, 2014

Long-Term Debt and Liquidity Matters

Long-Term Debt and Liquidity Matters

2.             Long-Term Debt and Liquidity Matters

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

Pinnacle West

Pinnacle West’s $200 million credit facility matures in November 2016.  At March 31, 2014, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At March 31, 2014, Pinnacle West had commercial paper borrowings of $10 million, no outstanding borrowings under its credit facility and no letters of credit outstanding.

APS

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. 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.  On January 15, 2014, these series of bonds were canceled.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of Southern California Edison’s (“SCE”) 48% ownership interest in each of Units 4 and 5 of the Four Corners Power Plant (“Four Corners”) and to replenish cash used in 2013 to re-acquire two series of tax-exempt indebtedness.

At March 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in November 2016 and a $500 million facility that matures in April 2018.  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2014, APS had no commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.

On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013.

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.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of March 31, 2014				As of December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,461		3,794		3,212		3,454
Total	$	3,586	$	3,919	$	3,337	$	3,579

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 March 31, 2014, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.8 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.1 billion, assuming APS’s total capitalization remains the same.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 24,691	$ 32,836
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	122,394	124,344
Deferred fuel and purchased power	31,630	31,194
Deferred fuel and purchased power amortization	8,022	1,122
Allowance for equity funds used during construction	(7,442)	(6,864)
Deferred income taxes	8,810	(9,265)
Deferred investment tax credit	(247)	21,428
Change in derivative instruments fair value	(13)	333
Changes in current assets and liabilities:
Customer and other receivables	25,986	3,931
Accrued unbilled revenues	7,889	4,698
Materials, supplies and fossil fuel	(187)	(9,386)
Income tax receivable	130,870	(433)
Other current assets	(10,669)	(2,525)
Accounts payable	(50,990)	11,925
Accrued taxes	48,139	39,615
Other current liabilities	(15,864)	(62,636)
Change in margin and collateral accounts - assets	(290)	933
Change in margin and collateral accounts - liabilities	(29,075)	24,205
Change in other long-term assets	(9,636)	(31,202)
Change in other long-term liabilities	(34,861)	37,904
Net cash flow provided by operating activities	249,157	212,157
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(207,459)	(182,859)
Contributions in aid of construction	7,736	14,912
Allowance for borrowed funds used during construction	(3,770)	(3,990)
Proceeds from nuclear decommissioning trust sales	103,157	135,240
Investment in nuclear decommissioning trust	(107,470)	(139,553)
Other	(702)	(470)
Net cash flow used for investing activities	(208,508)	(176,720)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000	104,307
Short-term borrowings - net	(143,625)	(92,175)
Dividends paid on common stock	(62,520)	(58,067)
Net cash flow provided by (used for) financing activities	53,246	(36,530)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	93,895	(1,093)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	9,526	26,202
CASH AND CASH EQUIVALENTS AT END OF PERIOD	103,421	25,109
Cash paid (received) during the period for:
Income taxes, net of refunds	(131,078)	425
Interest, net of amounts capitalized	49,147	49,038
Significant non-cash investing and financing activities:
Accrued capital expenditures	24,908	6,575
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	28,443	34,434
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	122,370	124,320
Deferred fuel and purchased power	31,630	31,194
Deferred fuel and purchased power amortization	8,022	1,122
Allowance for equity funds used during construction	(7,442)	(6,864)
Deferred income taxes	8,696	(8,670)
Deferred investment tax credit	(247)	21,426
Change in derivative instruments fair value	(13)	333
Changes in current assets and liabilities:
Customer and other receivables	25,749	2,464
Accrued unbilled revenues	7,889	4,698
Materials, supplies and fossil fuel	(187)	(9,386)
Income tax receivable	134,890	261
Other current assets	(10,807)	(2,526)
Accounts payable	(52,621)	12,892
Accrued taxes	50,580	43,062
Other current liabilities	(5,257)	(58,419)
Change in margin and collateral accounts - assets	(290)	933
Change in margin and collateral accounts - liabilities	(29,075)	24,205
Change in other long-term assets	(10,439)	(29,022)
Change in other long-term liabilities	(28,083)	41,760
Net cash flow provided by operating activities	273,808	228,217
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(207,459)	(182,859)
Contributions in aid of construction	7,736	14,912
Allowance for borrowed funds used during construction	(3,770)	(3,990)
Proceeds from nuclear decommissioning trust sales	103,157	135,240
Investment in nuclear decommissioning trust	(107,470)	(139,553)
Other	(702)	(470)
Net cash flow used for investing activities	(208,508)	(176,720)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000	104,307
Short-term borrowings - net	(153,125)	(92,175)
Dividends paid on common stock	(62,500)	(59,800)
Net cash flow provided by (used for) financing activities	34,375	(47,668)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	99,675	3,829
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,725	3,499
CASH AND CASH EQUIVALENTS AT END OF PERIOD	103,400	7,328
Cash paid (received) during the period for:
Income taxes, net of refunds	(134,323)
Interest, net of amounts capitalized	47,464	48,146
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 24,908	$ 6,575

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Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)	3 Months Ended			3 Months Ended				3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2014 ARIZONA PUBLIC SERVICE COMPANY item	Mar. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 1986 ARIZONA PUBLIC SERVICE COMPANY item	Mar. 31, 2014 ARIZONA PUBLIC SERVICE COMPANY Consolidation of VIEs item	Mar. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY Consolidation of VIEs	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts				3			3
Annual lease payments				$ 49,000,000
Annual lease payment if lease is extended										23,000,000
Number of options								2
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	8,925,000	8,392,000		8,925,000	8,392,000			9,000,000	8,000,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	124,157,000		125,125,000	124,157,000		125,125,000		124,000,000		125,000,000
Current maturities of long-term debt	540,424,000		540,424,000	540,424,000		540,424,000		26,000,000		26,000,000
Long-term debt excluding current maturities								13,000,000		13,000,000
Equity - Noncontrolling interests	154,915,000		145,990,000	154,915,000		145,990,000		155,000,000		146,000,000
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events								133,000,000
VIE debt to be assumed upon the occurrence of certain unlikely events								$ 39,000,000

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Changes in Equity (Tables)

3 Months Ended

Mar. 31, 2014

Changes in Equity

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

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014						Three Months Ended March 31, 2013
	Common Shareholders		Noncontrolling Interests		Total		Common Shareholders			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,194,470	$	145,990	$	4,340,460	$	3,972,806		$	129,483	$	4,102,289
Net income	15,766		8,925		24,691		24,444			8,392		32,836
Other comprehensive income	3,151		—		3,151		6,077			—		6,077
Total comprehensive income	18,917		8,925		27,842		30,521			8,392		38,913
Issuance of capital stock	2,592		—		2,592		2,574			—		2,574
Reissuance (purchase) of treasury stock — net	3,465		—		3,465		(6,271		)	—		(6,271		)
Other (primarily stock compensation)	3,342		—		3,342		14,825			—		14,825
Ending balance, March 31	$	4,222,786	$	154,915	$	4,377,701	$	4,014,455		$	137,875	$	4,152,330

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Derivative Accounting (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Accounting

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

As of March 31, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	5,503	GWh
Gas	107	Billion cubic feet

Gains and losses from derivative instruments in designated cash flow accounting hedges relationships

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2014			2013
Gain Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	177		$	96
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(4,439		)	(8,353		)

(a) During the three months ended March 31, 2014 and 2013, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

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

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2014			2013
Net Loss Recognized in Income	Operating revenues (a)	$	(92	)	$	(117	)
Net Gain Recognized in Income	Fuel and purchased power (a)	18,107			17,350
Total		$	18,015		$	17,233

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

Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts of offsetting

As of March 31, 2014:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset  (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
Current Assets	$	32,470		$	(15,816	)	$	16,654		$	297		$	16,951
Investments and Other Assets	23,913			(2,287		)	21,626			—			21,626
Total Assets	56,383			(18,103		)	38,280			297			38,577
Current Liabilities	(42,161		)	30,897			(11,264		)	(8,643		)	(19,907		)
Deferred Credits and Other	(65,511		)	36,405			(29,106		)	—			(29,106		)
Total Liabilities	(107,672		)	67,302			(40,370		)	(8,643		)	(49,013		)
Total	$	(51,289	)	$	49,199		$	(2,090	)	$	(8,346	)	$	(10,436	)

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

(b) Includes cash collateral provided to counterparties of $49,199.

(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 $8,643, and cash margin provided to counterparties of $297.

As of December 31, 2013:(dollars in thousands)	Gross Recognized Derivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			Amount Reported on Balance Sheet
Current Assets	$	24,587		$	(7,425	)	$	17,162		$	7		$	17,169
Investments and Other Assets	25,364			(1,549		)	23,815			—			23,815
Total Assets	49,951			(8,974		)	40,977			7			40,984
Current Liabilities	(50,540		)	26,166			(24,374		)	(7,518		)	(31,892		)
Deferred Credits and Other	(72,123		)	1,808			(70,315		)	—			(70,315		)
Total Liabilities	(122,663		)	27,974			(94,689		)	(7,518		)	(102,207		)
Total	$	(72,712	)	$	19,000		$	(53,712	)	$	(7,511	)	$	(61,223	)

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

(b) Includes cash collateral provided to counterparties of $19,000.

(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 $7,518, and cash margin provided to counterparties of $7.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2014 (dollars in millions):

	March 31, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	108
Cash Collateral Posted	49
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	50

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

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Nuclear Decommissioning Trusts (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Nuclear decommissioning trust fund assets
Fair Value	$ 657,862,000		$ 642,007,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities	103,157,000	135,240,000
Fair value of fixed income securities, summarized by contractual maturities
Total	657,862,000		642,007,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	657,862,000		642,007,000
Unrealized Gains	145,000,000		140,000,000
Unrealized Losses	(3,000,000)		(6,000,000)
Net payables for securities purchases	(5,000,000)		(3,000,000)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	1,000,000	2,000,000
Realized losses	(2,000,000)	(1,000,000)
Proceeds from the sale of securities	103,157,000	135,240,000
Fair value of fixed income securities, summarized by contractual maturities
Total	657,862,000		642,007,000
ARIZONA PUBLIC SERVICE COMPANY | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	277,000,000		272,000,000
Unrealized Gains	132,000,000		129,000,000
Fair value of fixed income securities, summarized by contractual maturities
Total	277,000,000		272,000,000
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	386,000,000		373,000,000
Unrealized Gains	13,000,000		11,000,000
Unrealized Losses	(3,000,000)		(6,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	17,000,000
1 year - 5 years	109,000,000
5 years - 10 years	111,000,000
Greater than 10 years	149,000,000
Total	$ 386,000,000		$ 373,000,000

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Derivative Accounting (Details)	Mar. 31, 2014
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%
Commodity - Power
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	5,503
Commodity - Gas
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	107
ARIZONA PUBLIC SERVICE COMPANY
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%

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Other Income and Other Expense (Tables)

3 Months Ended

Mar. 31, 2014

Other Income and Other Expense

Detail of other income and other expense

The following table provides detail of other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	251		$	76
Miscellaneous	2,116			682
Total other income	$	2,367		$	758
Other expense:
Non-operating costs	$	(2,372	)	$	(1,932	)
Investment losses — net	(140		)	(112		)
Miscellaneous	(2,172		)	(1,708		)
Total other expense	$	(4,684	)	$	(3,752	)

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share

Schedule of earnings per weighted average common share outstanding

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):

	Three Months Ended March 31,
	2014		2013
Net income attributable to common shareholders	$	15,766	$	24,444
Average common shares outstanding — basic	110,257		109,832
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	631		1,003
Average common shares outstanding — diluted	110,888		110,835
Earnings per average common share attributable to common shareholders — basic	$	0.14	$	0.22
Earnings per average common share attributable to common shareholders — diluted	$	0.14	$	0.22

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Consolidation and Nature of Operations

3 Months Ended

Mar. 31, 2014

Consolidation and Nature of Operations

Consolidation and Nature of Operations

1.             Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS and El Dorado Investment Company (“El Dorado”).  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 have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC).  Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading.

The following table shows more detail of previously reported amounts for the changes in deferred investment tax credit and income tax receivable. Previously reported amounts were netted in the Statement of Cash Flows (dollars in thousands):

Statement of Cash Flows for the Year Ended March 31, 2013	As previously reported		Changes to conform to current year presentation			Amount reported after changes to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	12,163	$	(21,428	)	$	(9,265	)
Deferred investment tax credit	—		21,428			21,428
Accrued taxes and income tax receivable	39,182		(39,182		)	—
Income tax receivable	—		(433		)	(433		)
Accrued taxes	—		39,615			39,615

Supplemental Cash Flow Information

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

	Three Months Ended March 31,
	2014			2013
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(131,078	)	$	425
Interest, net of amounts capitalized	49,147			49,038
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	24,908		$	6,575

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Measurements

Fair value of assets and liabilities that are measured at fair value on a recurring basis

The following table presents the fair value at March 31, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at March 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	36		$	(18)	(b)	$	39
Nuclear decommissioning trust:
U.S. commingled equity funds	—		277			—			—			277
Fixed income securities:
U.S. Treasury	120		—			—			—			120
Cash and cash equivalent funds	—		14			—			(5)		(c)	9
Corporate debt	—		96			—			—			96
Mortgage-backed securities	—		79			—			—			79
Municipality bonds	—		64			—			—			64
Other	—		13			—			—			13
Subtotal nuclear decommissioning trust	120		543			—			(5		)	658
Total	$	120	$	564		$	36		$	(23	)	$	697
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(23	)	$	(85	)	$	59	(b)	$	(49	)

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

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

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

The following table presents the fair value at December 31, 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 December 31, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	9		$	41		$	(9)	(b)	$	41
Nuclear decommissioning trust:
U.S. commingled equity funds	—		272			—			—			272
Fixed income securities:
U.S. Treasury	107		—			—			—			107
Cash and cash equivalent funds	—		11			—			(3)		(c)	8
Corporate debt	—		88			—			—			88
Mortgage-backed securities	—		85			—			—			85
Municipality bonds	—		71			—			—			71
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	107		538			—			(3		)	642
Total	$	107	$	547		$	41		$	(12	)	$	683
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(33	)	$	(90	)	$	21	(b)	$	(102	)

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

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

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

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

	March 31, 2014 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	34	$	60	Discounted cash flows	Electricity forward price (per MWh)	$23.13 — $67.47	$	42.28
Option Contracts (b)	—		22		Option model	Electricity forward price (per MWh)	$40.32 — $93.94	$	60.49
						Natural gas forward price (per MMbtu)	$3.64 — $3.84	$	3.76
						Electricity price volatilities	24% — 100%	52		%
						Natural gas price volatilities	23% — 44%	30		%
Natural Gas:
Forward Contracts (a)	2		3		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.60 — $4.40	$	3.91
Total	$	36	$	85

(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.

	December 31, 2013 Fair Value (millions)
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted- Average
Electricity:
Forward Contracts (a)	$	40	$	66	Discounted cash flows	Electricity forward price (per MWh)	$24.89 - $65.04	$	41.09
Option Contracts (b)	—		19		Option model	Electricity forward price (per MWh)	$39.91 - $85.41	$	58.70
						Natural gas forward price (per MMbtu)	$3.57 - $3.80	$	3.71
						Electricity price volatilities	35% - 94%	59		%
						Natural gas price volatilities	22% - 36%	27		%
Natural Gas:
Forward Contracts (a)	1		5		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.47 - $4.31	$	3.87
Total	$	41	$	90

(a) Includes swaps and physical and financial contracts.

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

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

The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2014 and 2013 (dollars in millions):

Commodity Contracts	Three Months Ended March 31,
	2014			2013
Net derivative balance at beginning of period	$	(49	)	$	(48	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	4			(1		)
Settlements	—			(2		)
Transfers into Level 3 from Level 2	(3		)	(1		)
Transfers from Level 3 into Level 2	(1		)	(1		)
Net derivative balance at end of period	$	(49	)	$	(53	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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Regulatory Matters (Details 4) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Detail of regulatory liabilities
Regulatory liabilities, current	$ 136,000,000	$ 99,000,000
Regulatory liabilities, non-current	783,702,000	801,297,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	28,000,000	28,000,000
Regulatory liabilities, non-current	298,000,000	303,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, non-current	253,000,000	266,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	35,000,000	33,000,000
Regulatory liabilities, non-current	16,000,000	15,000,000
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	1,000,000
Regulatory liabilities, non-current	73,000,000	74,000,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	5,000,000	6,000,000
Regulatory liabilities, non-current	37,000,000	36,000,000
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,000,000	2,000,000
Regulatory liabilities, non-current	9,000,000	10,000,000
Income taxes-deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	3,000,000	3,000,000
Regulatory liabilities, non-current	79,000,000	79,000,000
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	34,000,000	27,000,000
Deferred Fuel and Purchased Power Costs
Detail of regulatory liabilities
Regulatory liabilities, current	19,000,000
Deferred fuel and purchased power - mark-to-market
Detail of regulatory liabilities
Regulatory liabilities, current	9,000,000
Other
Detail of regulatory liabilities
Regulatory liabilities, non-current	$ 19,000,000	$ 18,000,000

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Earnings Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Earnings Per Share
Net income attributable to common shareholders	$ 15,766	$ 24,444
Average common shares outstanding - basic	110,257	109,832
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	631	1,003
Average common shares outstanding - diluted	110,888	110,835
Earnings per average common share attributable to common shareholders -basic (in dollars per share)	$ 0.14	$ 0.22
Earnings per average common share attributable to common shareholders -diluted (in dollars per share)	$ 0.14	$ 0.22

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
OPERATING REVENUES	$ 686,251	$ 686,652
OPERATING EXPENSES
Fuel and purchased power	249,786	230,679
Operations and maintenance	212,882	223,250
Depreciation and amortization	101,772	103,730
Taxes other than income taxes	45,845	40,021
Other expenses	796	2,049
Total	611,081	599,729
OPERATING INCOME	75,170	86,923
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,442	6,864
Other income (Note 10)	2,367	758
Other expense (Note 10)	(4,684)	(3,752)
Total	5,125	3,870
INTEREST EXPENSE
Interest charges	52,969	49,478
Allowance for borrowed funds used during construction	(3,770)	(3,990)
Total	49,199	45,488
INCOME BEFORE INCOME TAXES	31,096	45,305
INCOME TAXES	6,405	12,469
NET INCOME	24,691	32,836
Less: Net income attributable to noncontrolling interests (Note 6)	8,925	8,392
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 15,766	$ 24,444
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	110,257	109,832
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	110,888	110,835
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.14	$ 0.22
Net income attributable to common shareholders - diluted (in dollars per share)	$ 0.14	$ 0.22

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Derivative Accounting (Details 2) (Commodity Contracts, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain Recognized in OCI on Derivative Instruments (Effective Portion)	$ 177	$ 96
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(4,439)	(8,353)
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	0	0
Estimated net loss before income taxes to be reclassified from accumulated other comprehensive income	(19,000)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	18,015	17,233
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	(92)	(117)
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	$ 18,107	$ 17,350

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013
EQUITY (Note 8)
Common stock, par value (in dollars per share)
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	110,389,065	110,280,703
Treasury stock at cost, shares	34,828	98,944

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
NET INCOME	$ 24,691	$ 32,836
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(599) and $(38)	(422)	58
Reclassification of net realized loss, net of tax benefit of $1,323 and $3,300	3,116	5,053
Pension and other postretirement benefits activity, net of tax expense of $606 and $576	457	966
Total other comprehensive income	3,151	6,077
COMPREHENSIVE INCOME	27,842	38,913
Less: Comprehensive income attributable to noncontrolling interests	8,925	8,392
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	18,917	30,521
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	28,443	34,434
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(599) and $(38)	(421)	58
Reclassification of net realized loss, net of tax benefit of $1,323 and $3,300	3,116	5,052
Pension and other postretirement benefits activity, net of tax expense of $606 and $576	566	882
Total other comprehensive income	3,261	5,992
COMPREHENSIVE INCOME	31,704	40,426
Less: Comprehensive income attributable to noncontrolling interests	8,925	8,392
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 22,779	$ 32,034

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Consolidation and Nature of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Cash Flows from Operating Activities
Deferred income taxes	$ 8,810	$ (9,265)
Deferred investment tax credit	(247)	21,428
Income tax receivable	130,870	(433)
Accrued taxes	48,139	39,615
Cash paid (received) during the period for:
Income taxes, net of refunds	(131,078)	425
Interest, net of amounts capitalized	49,147	49,038
Significant non-cash investing and financing activities:
Accrued capital expenditures	24,908	6,575
As previously reported
Cash Flows from Operating Activities
Deferred income taxes		12,163
Accrued taxes and income tax receivable		39,182
Changes to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes		(21,428)
Deferred investment tax credit		21,428
Accrued taxes and income tax receivable		(39,182)
Income tax receivable		(433)
Accrued taxes		$ 39,615

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Changes in Accumulated Other Comprehensive Loss (APSC)

3 Months Ended

Mar. 31, 2014

Changes in Accumulated Other Comprehensive Loss

15. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three-months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,058	)	$	(54,995	)	$	(78,053	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(422		)	—			(422		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	457		(b)	3,573			5,053		(a)	966		(b)	6,019
Net current period OCI	2,694			457			3,151			5,111			966			6,077
Ending balance, March 31	$	(20,364	)	$	(54,538	)	$	(74,902	)	$	(44,481	)	$	(63,450	)	$	(107,931	)

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

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

ARIZONA PUBLIC SERVICE COMPANY

Changes in Accumulated Other Comprehensive Loss

S-3. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive income (loss), including reclassification adjustments, net of tax, by component for the three-month periods ended March 31, 2014 and March 31, 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,059	)	$	(30,313	)	$	(53,372	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
OCI (loss) before reclassifications	(421		)	—			(421		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	566		(b)	3,682			5,052		(a)	882		(b)	5,934
Net current period OCI	2,695			566			3,261			5,110			882			5,992
Ending balance, March 31	$	(20,364	)	$	(29,747	)	$	(50,111	)	$	(44,482	)	$	(38,621	)	$	(83,103	)

(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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Changes in Accumulated Other Comprehensive Loss

3 Months Ended

Mar. 31, 2014

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss

15. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three-months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,058	)	$	(54,995	)	$	(78,053	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(422		)	—			(422		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	457		(b)	3,573			5,053		(a)	966		(b)	6,019
Net current period OCI	2,694			457			3,151			5,111			966			6,077
Ending balance, March 31	$	(20,364	)	$	(54,538	)	$	(74,902	)	$	(44,481	)	$	(63,450	)	$	(107,931	)

(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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Long-Term Debt and Liquidity Matters (Details) (USD $)							3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Pinnacle West	Dec. 31, 2013 Pinnacle West	Mar. 31, 2014 APS	Dec. 31, 2013 APS	Mar. 31, 2014 APS SCE Four Corners Units 4 and 5 item	Dec. 30, 2013 APS SCE Four Corners Units 4 and 5	Mar. 31, 2014 APS ACC	Mar. 31, 2014 APS ACC Minimum	Mar. 31, 2014 Long term debt APS item	Jul. 12, 2013 Pollution Control Revenue Refunding Bonds, 1994 Series A APS	Oct. 11, 2013 Pollution Control Revenue Refunding Bonds, 1994 Series C APS	Mar. 31, 2014 Revolving credit facility maturing in 2016 Pinnacle West	Mar. 31, 2014 Revolving credit facility maturing in 2016 APS	Mar. 31, 2014 Revolving credit facility maturing in 2018 APS	Jan. 10, 2014 4.70% unsecured senior notes that mature on January 15, 2044 APS	May 01, 2014 Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E Subsequent event
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility											$ 1,000,000,000			$ 200,000,000	$ 500,000,000	$ 500,000,000
Maximum commercial paper support available under credit facility											250,000,000			200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders														300,000,000	700,000,000	700,000,000
Outstanding borrowings											0			0
Outstanding letters of credit											0			0
Commercial paper borrowings outstanding											0			10,000,000
Outstanding amount of debt												33,000,000	32,000,000					100,000,000
Notes issued																	250,000,000
Interest rate (as a percent)																	4.70%
Ownership interest acquired							48.00%	48.00%
Number of tax-exempt indebtedness series re-acquired							2
Estimated fair value of long-term debt, including current maturities
Carrying Amount	3,586,000,000	3,337,000,000	125,000,000	125,000,000	3,461,000,000	3,212,000,000
Fair Value	3,919,000,000	3,579,000,000	125,000,000	125,000,000	3,794,000,000	3,454,000,000
Debt Provisions
Required common equity ratio ordered by ACC (as a percent)										40.00%
Total shareholder equity	4,222,786,000	4,194,470,000			4,331,661,000	4,308,884,000			4,300,000,000
Total capitalization									7,800,000,000
Dividend restrictions, shareholder equity required									$ 3,100,000,000
Number of line of credit facilities											2

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Long-Term Debt and Liquidity Matters (Tables)

3 Months Ended

Mar. 31, 2014

Long-Term Debt and Liquidity Matters

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

The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of March 31, 2014				As of December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,461		3,794		3,212		3,454
Total	$	3,586	$	3,919	$	3,337	$	3,579

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

3 Months Ended

Mar. 31, 2014

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three-months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,058	)	$	(54,995	)	$	(78,053	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(422		)	—			(422		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	457		(b)	3,573			5,053		(a)	966		(b)	6,019
Net current period OCI	2,694			457			3,151			5,111			966			6,077
Ending balance, March 31	$	(20,364	)	$	(54,538	)	$	(74,902	)	$	(44,481	)	$	(63,450	)	$	(107,931	)

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

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

ARIZONA PUBLIC SERVICE COMPANY

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component

The following table shows the changes in accumulated other comprehensive income (loss), including reclassification adjustments, net of tax, by component for the three-month periods ended March 31, 2014 and March 31, 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,059	)	$	(30,313	)	$	(53,372	)	$	(49,592	)	$	(39,503	)	$	(89,095	)
OCI (loss) before reclassifications	(421		)	—			(421		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	566		(b)	3,682			5,052		(a)	882		(b)	5,934
Net current period OCI	2,695			566			3,261			5,110			882			5,992
Ending balance, March 31	$	(20,364	)	$	(29,747	)	$	(50,111	)	$	(44,482	)	$	(38,621	)	$	(83,103	)

(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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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 24,691	$ 32,836
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	122,394	124,344
Deferred fuel and purchased power	31,630	31,194
Deferred fuel and purchased power amortization	8,022	1,122
Allowance for equity funds used during construction	(7,442)	(6,864)
Deferred income taxes	8,810	(9,265)
Deferred investment tax credit	(247)	21,428
Change in derivative instruments fair value	(13)	333
Changes in current assets and liabilities:
Customer and other receivables	25,986	3,931
Accrued unbilled revenues	7,889	4,698
Materials, supplies and fossil fuel	(187)	(9,386)
Income tax receivable	130,870	(433)
Other current assets	(10,669)	(2,525)
Accounts payable	(50,990)	11,925
Accrued taxes	48,139	39,615
Other current liabilities	(15,864)	(62,636)
Change in margin and collateral accounts - assets	(290)	933
Change in margin and collateral accounts - liabilities	(29,075)	24,205
Change in other long-term assets	(9,636)	(31,202)
Change in other long-term liabilities	(34,861)	37,904
Net cash flow provided by operating activities	249,157	212,157
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(207,459)	(182,859)
Contributions in aid of construction	7,736	14,912
Allowance for borrowed funds used during construction	(3,770)	(3,990)
Proceeds from nuclear decommissioning trust sales	103,157	135,240
Investment in nuclear decommissioning trust	(107,470)	(139,553)
Other	(702)	(470)
Net cash flow used for investing activities	(208,508)	(176,720)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000	104,307
Short-term borrowings and payments - net	(143,625)	(92,175)
Dividends paid on common stock	(62,520)	(58,067)
Common stock equity issuance	9,390	9,441
Other	1	(36)
Net cash flow provided by (used for) financing activities	53,246	(36,530)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	93,895	(1,093)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	9,526	26,202
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 103,421	$ 25,109

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$ 24,691	$ 32,836
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(599) and $(38)	(422)	58
Reclassification of net realized loss, net of tax benefit of $1,323 and $3,300	3,116	5,053
Pension and other postretirement benefits activity, net of tax expense of $718 and $631	457	966
Total other comprehensive income	3,151	6,077
COMPREHENSIVE INCOME	27,842	38,913
Less: Comprehensive income attributable to noncontrolling interests	8,925	8,392
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 18,917	$ 30,521

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Other Income and Other Expense

3 Months Ended

Mar. 31, 2014

Other Income and Other Expense

Other Income and Other Expense

10.          Other Income and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	251		$	76
Miscellaneous	2,116			682
Total other income	$	2,367		$	758
Other expense:
Non-operating costs	$	(2,372	)	$	(1,932	)
Investment losses — net	(140		)	(112		)
Miscellaneous	(2,172		)	(1,708		)
Total other expense	$	(4,684	)	$	(3,752	)

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 25, 2014
Document and Entity Information
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	0000764622
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		110,357,309
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1

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Earnings Per Share

3 Months Ended

Mar. 31, 2014

Earnings Per Share

Earnings Per Share

11.          Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):

	Three Months Ended March 31,
	2014		2013
Net income attributable to common shareholders	$	15,766	$	24,444
Average common shares outstanding — basic	110,257		109,832
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	631		1,003
Average common shares outstanding — diluted	110,888		110,835
Earnings per average common share attributable to common shareholders — basic	$	0.14	$	0.22
Earnings per average common share attributable to common shareholders — diluted	$	0.14	$	0.22

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net unrealized loss, tax benefit (expense)	$ (599)	$ (38)
Reclassification of net realized loss, tax benefit	1,323	3,300
Pension and other postretirement benefits activity, tax expense	$ 718	$ 631

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Income Taxes

3 Months Ended

Mar. 31, 2014

Income Taxes

Income Taxes

5. Income Taxes

During the first quarter of 2014, a $135 million cash refund was received from the IRS related to tax returns for the years ended December 31, 2008 and 2009.  This refund was classified as a current income tax receivable at December 31, 2013.

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.

In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  As a result of this guidance, $29 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Condensed Consolidated Balance Sheets and $16 million were recorded as an increase to net current deferred income tax liabilities on the APS Condensed Consolidated Balance Sheets as of March 31, 2014.

As of March 31, 2014, the tax year ended December 31, 2010 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 2010.

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Retirement Plans and Other Benefits

3 Months Ended

Mar. 31, 2014

Retirement Plans and Other Benefits

Retirement Plans and Other Benefits

4. Retirement Plans and Other Benefits

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

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We amortized approximately $2 million for the three months ended March 31, 2014 and 2013, 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):

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
	2014			2013			2014			2013
Service cost — benefits earned during the period	$	15		$	17		$	5		$	6
Interest cost on benefit obligation	32			29			11			10
Expected return on plan assets	(40		)	(37		)	(12		)	(11		)
Amortization of net actuarial loss	2			9			—			3
Net periodic benefit cost	$	9		$	18		$	4		$	8
Portion of cost charged to expense	$	5		$	10		$	3		$	5

Contributions

The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016).  Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $105 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016).  The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

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Consolidation and Nature of Operations (Tables)

3 Months Ended

Mar. 31, 2014

Consolidation and Nature of Operations

Schedule of previously reported amounts

Previously reported amounts were netted in the Statement of Cash Flows (dollars in thousands):

Statement of Cash Flows for the Year Ended March 31, 2013	As previously reported		Changes to conform to current year presentation			Amount reported after changes to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	12,163	$	(21,428	)	$	(9,265	)
Deferred investment tax credit	—		21,428			21,428
Accrued taxes and income tax receivable	39,182		(39,182		)	—
Income tax receivable	—		(433		)	(433		)
Accrued taxes	—		39,615			39,615

Summary of supplemental cash flow information

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

	Three Months Ended March 31,
	2014			2013
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(131,078	)	$	425
Interest, net of amounts capitalized	49,147			49,038
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	24,908		$	6,575

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Fair Value Measurements

3 Months Ended

Mar. 31, 2014

Fair Value Measurements

Fair Value Measurements

12.          Fair Value Measurements

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

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

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

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

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

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 8 in the 2013 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 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 the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

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

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

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

Investments Held in our Nuclear Decommissioning Trusts

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 U.S. government fixed income securities.  We may transact in this commingled fund on a daily basis at the NAV.

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield 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.

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

Fair Value Tables

The following table presents the fair value at March 31, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at March 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	36		$	(18)	(b)	$	39
Nuclear decommissioning trust:
U.S. commingled equity funds	—		277			—			—			277
Fixed income securities:
U.S. Treasury	120		—			—			—			120
Cash and cash equivalent funds	—		14			—			(5)		(c)	9
Corporate debt	—		96			—			—			96
Mortgage-backed securities	—		79			—			—			79
Municipality bonds	—		64			—			—			64
Other	—		13			—			—			13
Subtotal nuclear decommissioning trust	120		543			—			(5		)	658
Total	$	120	$	564		$	36		$	(23	)	$	697
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(23	)	$	(85	)	$	59	(b)	$	(49	)

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

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

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

The following table presents the fair value at December 31, 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 December 31, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	9		$	41		$	(9)	(b)	$	41
Nuclear decommissioning trust:
U.S. commingled equity funds	—		272			—			—			272
Fixed income securities:
U.S. Treasury	107		—			—			—			107
Cash and cash equivalent funds	—		11			—			(3)		(c)	8
Corporate debt	—		88			—			—			88
Mortgage-backed securities	—		85			—			—			85
Municipality bonds	—		71			—			—			71
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	107		538			—			(3		)	642
Total	$	107	$	547		$	41		$	(12	)	$	683
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(33	)	$	(90	)	$	21	(b)	$	(102	)

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

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

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

Fair Value Measurements Classified as Level 3

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

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Our option contracts classified as Level 3 primarily relate to purchase heat rate options.  The significant unobservable inputs for these instruments include electricity prices, gas prices and volatilities.  If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease.  If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase.  The commodity prices and 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 risk management derivative Level 3 instruments at March 31, 2014 and December 31, 2013:

	March 31, 2014 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	34	$	60	Discounted cash flows	Electricity forward price (per MWh)	$23.13 — $67.47	$	42.28
Option Contracts (b)	—		22		Option model	Electricity forward price (per MWh)	$40.32 — $93.94	$	60.49
						Natural gas forward price (per MMbtu)	$3.64 — $3.84	$	3.76
						Electricity price volatilities	24% — 100%	52		%
						Natural gas price volatilities	23% — 44%	30		%
Natural Gas:
Forward Contracts (a)	2		3		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.60 — $4.40	$	3.91
Total	$	36	$	85

(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.

	December 31, 2013 Fair Value (millions)
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted- Average
Electricity:
Forward Contracts (a)	$	40	$	66	Discounted cash flows	Electricity forward price (per MWh)	$24.89 - $65.04	$	41.09
Option Contracts (b)	—		19		Option model	Electricity forward price (per MWh)	$39.91 - $85.41	$	58.70
						Natural gas forward price (per MMbtu)	$3.57 - $3.80	$	3.71
						Electricity price volatilities	35% - 94%	59		%
						Natural gas price volatilities	22% - 36%	27		%
Natural Gas:
Forward Contracts (a)	1		5		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.47 - $4.31	$	3.87
Total	$	41	$	90

(a) Includes swaps and physical and financial contracts.

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

The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2014 and 2013 (dollars in millions):

Commodity Contracts	Three Months Ended March 31,
	2014			2013
Net derivative balance at beginning of period	$	(49	)	$	(48	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	4			(1		)
Settlements	—			(2		)
Transfers into Level 3 from Level 2	(3		)	(1		)
Transfers from Level 3 into Level 2	(1		)	(1		)
Net derivative balance at end of period	$	(49	)	$	(53	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no significant Level 1 transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our heat rate options and long-dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value

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

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Changes in Equity

3 Months Ended

Mar. 31, 2014

Changes in Equity

Changes in Equity

8.             Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014						Three Months Ended March 31, 2013
	Common Shareholders		Noncontrolling Interests		Total		Common Shareholders			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,194,470	$	145,990	$	4,340,460	$	3,972,806		$	129,483	$	4,102,289
Net income	15,766		8,925		24,691		24,444			8,392		32,836
Other comprehensive income	3,151		—		3,151		6,077			—		6,077
Total comprehensive income	18,917		8,925		27,842		30,521			8,392		38,913
Issuance of capital stock	2,592		—		2,592		2,574			—		2,574
Reissuance (purchase) of treasury stock — net	3,465		—		3,465		(6,271		)	—		(6,271		)
Other (primarily stock compensation)	3,342		—		3,342		14,825			—		14,825
Ending balance, March 31	$	4,222,786	$	154,915	$	4,377,701	$	4,014,455		$	137,875	$	4,152,330

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net unrealized gain (loss), tax benefit	$ (599)	$ (38)
Reclassification of net realized loss, tax benefit	1,323	3,300
Pension and other postretirement benefits activity, tax expense	718	631
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized gain (loss), tax benefit	(599)	(38)
Reclassification of net realized loss, tax benefit	1,323	3,300
Pension and other postretirement benefits activity, tax expense	$ 606	$ 576

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Palo Verde Sale Leaseback Variable Interest Entities

3 Months Ended

Mar. 31, 2014

Palo Verde Sale Leaseback Variable Interest Entities

Palo Verde Sale Leaseback Variable Interest Entities

6. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  APS will pay approximately $49 million per year during 2014 and 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 determined through an appraisal process.  During 2014, APS must notify the lessor trust which of these two options (lease renewal or purchasing the assets) it will exercise.

As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2014 of $9 million and for the three months ended March 31, 2013 of $8 million, entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders remains the same.  Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):

	March 31, 2014		December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	124	$	125
Current maturities of long-term debt	26		26
Long-term debt excluding current maturities	13		13
Equity — Noncontrolling interests	155		146

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 leases.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of March 31, 2014, APS would have been required to pay the noncontrolling equity participants approximately $133 million and assume $39 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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

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Derivative Accounting

3 Months Ended

Mar. 31, 2014

Derivative Accounting

Derivative Accounting

7. Derivative Accounting

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

On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow 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 OCI, but are deferred through the PSA.  The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur.  When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA.  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 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.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of March 31, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	5,503	GWh
Gas	107	Billion cubic feet

Gains and Losses from Derivative Instruments

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2014			2013
Gain Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	177		$	96
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(4,439		)	(8,353		)

(a) During the three months ended March 31, 2014 and 2013, we had no amounts reclassified from accumulated OCI 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 $19 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended March 31,
Commodity Contracts	Location	2014			2013
Net Loss Recognized in Income	Operating revenues (a)	$	(92	)	$	(117	)
Net Gain Recognized in Income	Fuel and purchased power (a)	18,107			17,350
Total		$	18,015		$	17,233

(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 a 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 March 31, 2014 and December 31, 2013, include gross liabilities of $4 million and $5 million, respectively, of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, 2014 and December 31, 2013.  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 March 31, 2014:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset  (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
Current Assets	$	32,470		$	(15,816	)	$	16,654		$	297		$	16,951
Investments and Other Assets	23,913			(2,287		)	21,626			—			21,626
Total Assets	56,383			(18,103		)	38,280			297			38,577
Current Liabilities	(42,161		)	30,897			(11,264		)	(8,643		)	(19,907		)
Deferred Credits and Other	(65,511		)	36,405			(29,106		)	—			(29,106		)
Total Liabilities	(107,672		)	67,302			(40,370		)	(8,643		)	(49,013		)
Total	$	(51,289	)	$	49,199		$	(2,090	)	$	(8,346	)	$	(10,436	)

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

(b) Includes cash collateral provided to counterparties of $49,199.

(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 $8,643, and cash margin provided to counterparties of $297.

As of December 31, 2013:(dollars in thousands)	Gross Recognized Derivatives(a)			Amounts Offset (b)			NetRecognizedDerivatives			Other(c)			Amount Reported on Balance Sheet
Current Assets	$	24,587		$	(7,425	)	$	17,162		$	7		$	17,169
Investments and Other Assets	25,364			(1,549		)	23,815			—			23,815
Total Assets	49,951			(8,974		)	40,977			7			40,984
Current Liabilities	(50,540		)	26,166			(24,374		)	(7,518		)	(31,892		)
Deferred Credits and Other	(72,123		)	1,808			(70,315		)	—			(70,315		)
Total Liabilities	(122,663		)	27,974			(94,689		)	(7,518		)	(102,207		)
Total	$	(72,712	)	$	19,000		$	(53,712	)	$	(7,511	)	$	(61,223	)

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

(b) Includes cash collateral provided to counterparties of $19,000.

(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 $7,518, and cash margin provided to counterparties of $7.

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 84% of Pinnacle West’s $39 million of risk management assets as of March 31, 2014.  This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2014 (dollars in millions):

	March 31, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	108
Cash Collateral Posted	49
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	50

(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 $180 million if our debt credit ratings were to fall below investment grade.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies.

Commitments and Contingencies

9.             Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy (“DOE”) in the United States Court of Federal Claims (“Court of Federal Claims”).  The lawsuit seeks to recover 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 Protection Act.  This lawsuit is currently pending in the Court of Federal Claims.

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 retrospective premium 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 million, with an annual payment limitation of approximately $16.5 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 replacement 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, 2014, a sublimit of $2.25 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies.  Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations.  APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds.  The maximum amount APS could incur under the current NEIL policies totals approximately $20 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 $54 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

There have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2013 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.

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.

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.

On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS.  FERC Staff alleges that each of the named entities violated varying numbers of NERC Reliability Standards.  APS is alleged to have violated seven Reliability Standard Requirements.  The allegations of violations are preliminary determinations by FERC Staff and do not constitute findings by FERC itself that any violations have occurred.

APS intends to work with FERC Staff to resolve the matter.  If violations of the 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.  APS cannot predict the timing or financial or operational impacts that may result from the Staff’s Notice of Alleged Violations, including any payments that may result from a settlement if one is reached, or any claims that may be made as a result of the outages.

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 filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.  The appeal is now pending before the Ninth Circuit Court of Appeals.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Clean Air Act Citizen 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 environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS.  The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project.  On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCRs”).  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 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $350 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 $130 million for Cholla Units 2 and 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, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Regional Haze Rules — Cholla

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan (“SIP”) and promulgating a FIP that is inconsistent with the state’s considered 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.  Briefing in the case was completed in February 2014, and the parties are waiting for the court to schedule oral argument.

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.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed 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 March 31, 2014, 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 $24 million at March 31, 2014.  Additionally, APS has issued a letter of credit to support collateral obligations under a natural gas tolling contract entered into with third parties.  At March 31, 2014, that letter of credit totaled $5 million and will expire in 2014.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

Pinnacle West has issued parental guarantees and surety bonds for APS which were not material at March 31, 2014.

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Other Income and Other Expense (APSC)

3 Months Ended

Mar. 31, 2014

Other Income and Other Expense

10.          Other Income and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	251		$	76
Miscellaneous	2,116			682
Total other income	$	2,367		$	758
Other expense:
Non-operating costs	$	(2,372	)	$	(1,932	)
Investment losses — net	(140		)	(112		)
Miscellaneous	(2,172		)	(1,708		)
Total other expense	$	(4,684	)	$	(3,752	)

ARIZONA PUBLIC SERVICE COMPANY

Other Income and Other Expense

S-2. Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Other income:
Interest income	$	138		$	23
Miscellaneous	2,624			1,320
Total other income	$	2,762		$	1,343
Other expense:
Non-operating costs (a)	$	(2,587	)	$	(2,320	)
Asset dispositions	(183		)	(1,264		)
Miscellaneous	(2,286		)	(2,712		)
Total other expense	$	(5,056	)	$	(6,296	)

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

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Changes in Equity (APSC) (Tables)

3 Months Ended

Mar. 31, 2014

Changes in equity

Schedule of changes in shareholder equity and changes in equity of noncontrolling interests

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014						Three Months Ended March 31, 2013
	Common Shareholders		Noncontrolling Interests		Total		Common Shareholders			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,194,470	$	145,990	$	4,340,460	$	3,972,806		$	129,483	$	4,102,289
Net income	15,766		8,925		24,691		24,444			8,392		32,836
Other comprehensive income	3,151		—		3,151		6,077			—		6,077
Total comprehensive income	18,917		8,925		27,842		30,521			8,392		38,913
Issuance of capital stock	2,592		—		2,592		2,574			—		2,574
Reissuance (purchase) of treasury stock — net	3,465		—		3,465		(6,271		)	—		(6,271		)
Other (primarily stock compensation)	3,342		—		3,342		14,825			—		14,825
Ending balance, March 31	$	4,222,786	$	154,915	$	4,377,701	$	4,014,455		$	137,875	$	4,152,330

ARIZONA PUBLIC SERVICE COMPANY

Changes in equity

Schedule of changes in shareholder equity and changes in equity of noncontrolling interests

The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014								Three Months Ended March 31, 2013
	Shareholder Equity			Noncontrolling Interests		Total			Shareholder Equity			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,308,884		$	145,990	$	4,454,874		$	4,093,000		$	129,483	$	4,222,483
Net income	19,518			8,925		28,443			26,042			8,392		34,434
OCI	3,261			—		3,261			5,992			—		5,992
Total comprehensive income	22,779			8,925		31,704			32,034			8,392		40,426
Other	(2		)	—		(2		)	(2		)	—		(2		)
Ending balance, March 31	$	4,331,661		$	154,915	$	4,486,576		$	4,125,032		$	137,875	$	4,262,907

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Changes in Equity (APSC)

3 Months Ended

Mar. 31, 2014

Changes in equity

Changes in Equity

8.             Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014						Three Months Ended March 31, 2013
	Common Shareholders		Noncontrolling Interests		Total		Common Shareholders			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,194,470	$	145,990	$	4,340,460	$	3,972,806		$	129,483	$	4,102,289
Net income	15,766		8,925		24,691		24,444			8,392		32,836
Other comprehensive income	3,151		—		3,151		6,077			—		6,077
Total comprehensive income	18,917		8,925		27,842		30,521			8,392		38,913
Issuance of capital stock	2,592		—		2,592		2,574			—		2,574
Reissuance (purchase) of treasury stock — net	3,465		—		3,465		(6,271		)	—		(6,271		)
Other (primarily stock compensation)	3,342		—		3,342		14,825			—		14,825
Ending balance, March 31	$	4,222,786	$	154,915	$	4,377,701	$	4,014,455		$	137,875	$	4,152,330

ARIZONA PUBLIC SERVICE COMPANY

Changes in equity

Changes in Equity

S-1. Changes in Equity

The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014								Three Months Ended March 31, 2013
	Shareholder Equity			Noncontrolling Interests		Total			Shareholder Equity			Noncontrolling Interests		Total
Beginning balance, January 1	$	4,308,884		$	145,990	$	4,454,874		$	4,093,000		$	129,483	$	4,222,483
Net income	19,518			8,925		28,443			26,042			8,392		34,434
OCI	3,261			—		3,261			5,992			—		5,992
Total comprehensive income	22,779			8,925		31,704			32,034			8,392		40,426
Other	(2		)	—		(2		)	(2		)	—		(2		)
Ending balance, March 31	$	4,331,661		$	154,915	$	4,486,576		$	4,125,032		$	137,875	$	4,262,907

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Changes in Accumulated Other Comprehensive Loss (Tables)

3 Months Ended

Mar. 31, 2014

Changes in Accumulated Other Comprehensive Loss

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three-months ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total
Beginning balance, January 1	$	(23,058	)	$	(54,995	)	$	(78,053	)	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(422		)	—			(422		)	58			—			58
Amounts reclassified from accumulated other comprehensive loss	3,116		(a)	457		(b)	3,573			5,053		(a)	966		(b)	6,019
Net current period OCI	2,694			457			3,151			5,111			966			6,077
Ending balance, March 31	$	(20,364	)	$	(54,538	)	$	(74,902	)	$	(44,481	)	$	(63,450	)	$	(107,931	)

(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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Commitments and Contingencies (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended	0 Months Ended	3 Months Ended
	Mar. 31, 2014 ARIZONA PUBLIC SERVICE COMPANY Four Corners Units 4 and 5	May 23, 2013 Four Corners New Mexico Tax Matter	Mar. 31, 2014 Four Corners ARIZONA PUBLIC SERVICE COMPANY New Mexico Tax Matter	Mar. 31, 2014 Navajo Plant ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 2014 Cholla ARIZONA PUBLIC SERVICE COMPANY	Mar. 31, 2014 Cholla Units 2 And 3 ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters
Expected environmental cost	$ 350			$ 200	$ 200	$ 130
Share of Cost of Control of Four Corners Units 4 and 5	63.00%
Coal severance surtax, penalty, and interest		30
Share of the assessment			$ 12

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New Accounting Standards

3 Months Ended

Mar. 31, 2014

New Accounting Standards

New Accounting Standards

14. New Accounting Standards

During 2014, we adopted, on a prospective basis, new guidance relating to the presentation of unrecognized tax benefits.  This guidance generally requires 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.  Prior to adopting this guidance, we presented unrecognized tax benefits on a gross basis.  The adoption of this new guidance changed our balance sheet presentation of unrecognized tax benefits, but did not impact our operating results or cash flows.  See Note 5 for details regarding the impacts of adopting this guidance.

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Retirement Plans and Other Benefits (Tables)

3 Months Ended

Mar. 31, 2014

Retirement Plans and Other Benefits

Schedule of 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)

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
	2014			2013			2014			2013
Service cost — benefits earned during the period	$	15		$	17		$	5		$	6
Interest cost on benefit obligation	32			29			11			10
Expected return on plan assets	(40		)	(37		)	(12		)	(11		)
Amortization of net actuarial loss	2			9			—			3
Net periodic benefit cost	$	9		$	18		$	4		$	8
Portion of cost charged to expense	$	5		$	10		$	3		$	5

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Commitments and Contingencies (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	0 Months Ended	3 Months Ended		0 Months Ended
	Apr. 02, 2013	Mar. 31, 2014 item	Dec. 31, 1986 item	Apr. 02, 2014 Subsequent event
Palo Verde Nuclear Generating Station
Maximum insurance against public liability per occurrence for a nuclear incident		$ 13,600,000,000
Maximum available nuclear liability insurance		375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program		13,200,000,000
Maximum retrospective premium assessment per reactor for each nuclear incident		127,300,000
Annual limit per incident with respect to maximum retrospective premium assessment		19,000,000
Number of VIE lessor trusts		3	3
Maximum potential retrospective assessment per incident of APS		111,000,000
Annual payment limitation with respect to maximum potential retrospective assessment		16,500,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde		2,750,000,000
Sublimit for non-nuclear property damage losses which has been imposed to the primary policy offered				2,250,000,000
Sublimit for non-nuclear losses which has been imposed to the accidental outage policy	327,600,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment		20,000,000
Collateral assurance provided based on rating triggers		$ 54,000,000
Period to provide collateral assurance based on rating triggers		20 days

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Retirement Plans and Other Benefits (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		1 Months Ended	3 Months Ended
	Jul. 31, 2012	Mar. 31, 2014	Mar. 31, 2013	Jan. 31, 2014 Pension Benefits	Mar. 31, 2014 Pension Benefits	Mar. 31, 2013 Pension Benefits	Mar. 31, 2014 Pension Benefits Expected contributions	Mar. 31, 2014 Pension Benefits Expected contributions Maximum	Mar. 31, 2014 Other Benefits	Mar. 31, 2013 Other Benefits	Mar. 31, 2014 Other Benefits Expected contributions
Retirement Plans and Other Benefits
Regulatory asset amortization period	3 years
Amortization of regulatory assets		$ 2	$ 2
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period					15	17			5	6
Interest cost on benefit obligation					32	29			11	10
Expected return on plan assets					(40)	(37)			(12)	(11)
Amortization of net actuarial loss					2	9				3
Net periodic benefit cost					9	18			4	8
Portion of cost charged to expense					5	10			3	5
Contributions
Employer's contributions under the plan				105
Minimum Contributions under MAP-21
Minimum contributions under MAP-21					141
2014					0
2015					19
2016					122
Expected employer's contributions
Expected employer's contributions							300
2014							175				10
2015								100			10
2016								$ 25			$ 10

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$ 103,421	$ 9,526
Customer and other receivables	245,884	299,904
Accrued unbilled revenues	88,907	96,796
Allowance for doubtful accounts	(2,504)	(3,203)
Materials and supplies (at average cost)	223,401	221,682
Fossil fuel (at average cost)	36,496	38,028
Deferred income taxes	58,630	91,152
Income tax receivable (Note 5)	4,647	135,517
Assets from risk management activities (Note 7)	16,951	17,169
Deferred fuel and purchased power regulatory asset (Note 3)		20,755
Other regulatory assets (Note 3)	76,317	76,388
Other current assets	45,780	39,895
Total current assets	897,930	1,043,609
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	21,626	23,815
Nuclear decommissioning trust (Note 13)	657,862	642,007
Other assets	60,753	60,875
Total investments and other assets	740,241	726,697
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,256,945	15,200,464
Accumulated depreciation and amortization	(5,360,781)	(5,300,219)
Net	9,896,164	9,900,245
Construction work in progress	646,236	581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	124,157	125,125
Intangible assets, net of accumulated amortization	144,446	157,689
Nuclear fuel, net of accumulated amortization	144,048	124,557
Total property, plant and equipment	10,955,051	10,888,985
DEFERRED DEBITS
Regulatory assets (Note 3)	719,596	711,712
Other	137,979	137,683
Total deferred debits	857,575	849,395
TOTAL ASSETS	13,450,797	13,508,686
CURRENT LIABILITIES
Accounts payable	224,820	284,516
Accrued taxes (Note 5)	179,137	130,998
Accrued interest	47,392	48,351
Common dividends payable		62,528
Short-term borrowings (Note 2)	9,500	153,125
Current maturities of long-term debt (Note 2)	540,424	540,424
Customer deposits	75,999	76,101
Liabilities from risk management activities (Note 7)	19,907	31,892
Liabilities for asset retirements	25,536	32,896
Deferred fuel and purchased power regulatory liability (Note 3)	18,897
Other regulatory liabilities (Note 3)	116,903	99,273
Other current liabilities	136,128	158,540
Total current liabilities	1,394,643	1,618,644
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	3,045,614	2,796,465
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,359,689	2,351,882
Regulatory liabilities (Note 3)	783,702	801,297
Liabilities for asset retirements	344,708	313,833
Liabilities for pension and other postretirement benefits (Note 4)	442,136	513,628
Liabilities from risk management activities (Note 7)	29,106	70,315
Customer advances	115,033	114,480
Coal mine reclamation	208,183	207,453
Deferred investment tax credit	152,114	152,361
Unrecognized tax benefits (Note 5)	13,502	42,209
Other	184,666	185,659
Total deferred credits and other	4,632,839	4,753,117
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 8)
Common stock, no par value; authorized 150,000,000 shares, 110,389,065 and 110,280,703 issued at respective dates	2,497,485	2,491,558
Treasury stock at cost; 34,828 and 98,944 shares at respective dates	(844)	(4,308)
Total common stock	2,496,641	2,487,250
Retained earnings	1,801,047	1,785,273
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(54,538)	(54,995)
Derivative instruments	(20,364)	(23,058)
Total accumulated other comprehensive loss	(74,902)	(78,053)
Total shareholders' equity	4,222,786	4,194,470
Noncontrolling interests (Note 6)	154,915	145,990
Total equity	4,377,701	4,340,460
TOTAL LIABILITIES AND EQUITY	$ 13,450,797	$ 13,508,686

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Regulatory Matters

3 Months Ended

Mar. 31, 2014

Regulatory Matters

Regulatory Matters

3.             Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

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

Settlement Agreement

The 2012 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 2012 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 2012 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 2012 Settlement Agreement.

Other key provisions of the 2012 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 increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

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

· A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

· 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 APS’s 2009 retail rate case settlement agreement (the “2009 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 2012 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 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.

Cost Recovery Mechanisms

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

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

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, 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.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits.  On April 4, 2014, ACC staff submitted a proposal outlining various options which could be used to determine compliance with the renewable energy rules.  APS filed comments on the proposal and is awaiting the ACC’s selection of a proposal and modification of the rules to implement such proposal.

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

On June 1, 2012, APS filed its 2013 DSM 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.

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2014 and 2013 (dollars in millions):

	Three Months Ended March 31,
	2014			2013
Beginning balance	$	21		$	73
Deferred fuel and purchased power costs — current period	(32		)	(31		)
Amounts charged to customers	(8		)	(1		)
Ending balance	$	(19	)	$	41

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the United States Federal 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 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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

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.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.

Lost Fixed Cost Recovery 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 rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement 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 a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014.

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.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are being held in 2014.

Net Metering

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.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.

Beginning in May 2014, the ACC will conduct a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.

Four Corners

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  If approved, these adjustments would result in an average bill impact to residential customers of approximately 2%.  This includes the deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $47 million as of March 31, 2014.  A hearing on this matter is scheduled to begin August 4, 2014 and we anticipate a decision by the end of 2014.  APS cannot predict the outcome of this matter.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  We are unable to predict the timing or outcome of these requests.  Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.

Regulatory Assets and Liabilities

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

	Remaining Amortization	March 31, 2014				December 31, 2013
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)	$	—	$	313	$	—	$	314
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2043	4		104		4		105
Deferred fuel and purchased power — mark-to-market (Note 7)	2016	—		26		5		29
Transmission vegetation management	2016	9		12		9		14
Coal reclamation	2038	8		16		8		18
Palo Verde VIEs (Note 6)	2046	—		42		—		41
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		21		—
Tax expense of Medicare subsidy	2023	2		15		2		15
Loss on reacquired debt	2034	1		18		1		17
Income taxes — investment tax credit basis adjustment	2043	1		39		1		39
Pension and other postretirement benefits deferral	2015	8		2		8		4
Four Corners cost deferral	2024	—		47		—		37
Lost fixed cost recovery (b)	2015	32		—		25		—
Transmission cost adjustor (b)	2016	6		2		8		2
Retired power plant costs	2020	3		17		3		18
Other	Various	2		31		2		25
Total regulatory assets (d)		$	76	$	720	$	97	$	712

(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.  See Note 4 for further discussion.

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

(c) Subject to a carrying charge.

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

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

	Remaining Amortization	March 31, 2014				December 31, 2013
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	28	$	298	$	28	$	303
Asset retirement obligations	(a)	—		253		—		266
Renewable energy standard (b)	2015	35		16		33		15
Income taxes — change in rates	2043	1		73		—		74
Spent nuclear fuel	2047	5		37		6		36
Deferred gains on utility property	2019	2		9		2		10
Income taxes — deferred investment tax credit	2043	3		79		3		79
Demand side management (b)	2015	34		—		27		—
Deferred fuel and purchased power (b) (c)	2015	19		—		—		—
Deferred fuel and purchased power — mark to market	2015	9		—		—		—
Other	Various	—		19		—		18
Total regulatory liabilities		$	136	$	784	$	99	$	801

(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.

(c) Subject to carrying charge.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (APSC) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
OPERATING EXPENSES
Fuel and purchased power	$ 249,786	$ 230,679
Operations and maintenance	212,882	223,250
Depreciation and amortization	101,772	103,730
Taxes other than income taxes	45,845	40,021
Total	611,081	599,729
OPERATING INCOME	75,170	86,923
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,442	6,864
Other income (Note S-2)	2,367	758
Other expense (Note S-2)	(4,684)	(3,752)
Total	5,125	3,870
INTEREST EXPENSE
Allowance for borrowed funds used during construction	(3,770)	(3,990)
Total	49,199	45,488
NET INCOME	24,691	32,836
Less: Net income attributable to noncontrolling interests (Note 6)	8,925	8,392
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	15,766	24,444
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	685,545	685,827
OPERATING EXPENSES
Fuel and purchased power	249,786	230,679
Operations and maintenance	208,285	220,752
Depreciation and amortization	101,748	103,706
Income taxes	10,478	16,060
Taxes other than income taxes	45,613	39,768
Total	615,910	610,965
OPERATING INCOME	69,635	74,862
OTHER INCOME (DEDUCTIONS)
Income taxes	1,210	2,332
Allowance for equity funds used during construction	7,442	6,864
Other income (Note S-2)	2,762	1,343
Other expense (Note S-2)	(5,056)	(6,296)
Total	6,358	4,243
INTEREST EXPENSE
Interest on long-term debt	48,896	46,221
Interest on short-term borrowings	1,413	1,429
Debt discount, premium and expense	1,011	1,011
Allowance for borrowed funds used during construction	(3,770)	(3,990)
Total	47,550	44,671
NET INCOME	28,443	34,434
Less: Net income attributable to noncontrolling interests (Note 6)	8,925	8,392
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 19,518	$ 26,042

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Changes in Equity (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Changes in equity
Balance	$ 4,340,460	$ 4,102,289
Net income	24,691	32,836
Other comprehensive income	3,151	6,077
COMPREHENSIVE INCOME	27,842	38,913
Other	(3,342)	(14,825)
Balance	4,377,701	4,152,330
Shareholder equity
Changes in equity
Balance	4,194,470	3,972,806
Net income	15,766	24,444
Other comprehensive income	3,151	6,077
COMPREHENSIVE INCOME	18,917	30,521
Other	(3,342)	(14,825)
Balance	4,222,786	4,014,455
Noncontrolling Interests
Changes in equity
Balance	145,990	129,483
Net income	8,925	8,392
COMPREHENSIVE INCOME	8,925	8,392
Balance	154,915	137,875
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Balance	4,454,874	4,222,483
Net income	28,443	34,434
Other comprehensive income	3,261	5,992
COMPREHENSIVE INCOME	31,704	40,426
Other	(2)	(2)
Balance	4,486,576
ARIZONA PUBLIC SERVICE COMPANY | Shareholder equity
Changes in equity
Balance	4,308,884	4,093,000
Net income	19,518	26,042
Other comprehensive income	3,261	5,992
COMPREHENSIVE INCOME	22,779	32,034
Other	(2)	(2)
Balance	4,331,661	4,125,032
ARIZONA PUBLIC SERVICE COMPANY | Noncontrolling Interests
Changes in equity
Balance	145,990	129,483
Net income	8,925	8,392
COMPREHENSIVE INCOME	8,925	8,392
Balance	$ 154,915	$ 137,875

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2014

Palo Verde Sale Leaseback Variable Interest Entities

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

Our Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):

	March 31, 2014		December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	124	$	125
Current maturities of long-term debt	26		26
Long-term debt excluding current maturities	13		13
Equity — Noncontrolling interests	155		146

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Regulatory Matters (Details 2) (SCE, USD $) In Millions, unless otherwise specified	0 Months Ended
	Dec. 30, 2013 MW	Mar. 31, 2014
APS | Four Corners Units 4 and 5
Acquisition
Ownership interest acquired	48.00%	48.00%
Percentage of possible impact on average bill to residential customers	2.00%
Net receipt due to negotiation of alternate arrangement	$ 40
Capacity rights over the Arizona Transmission System assign to third-parties	1,555
Capacity rights related to marketing and trading group for transmission of the additional power received assign to third-parties	300
Four Corners
Acquisition
Deferral balance related to the acquisition of SCE's interest in Units 4 and 5 and the closure of Four Corners Units 1-3		$ 47

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Nuclear Decommissioning Trusts

3 Months Ended

Mar. 31, 2014

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts

13. Nuclear Decommissioning Trusts

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities.  APS classifies investments in decommissioning trust funds as available for sale.  As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets.  See Note 12 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities.  The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at March 31, 2014 and December 31, 2013 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2014
Equity securities	$	277		$	132	$	—
Fixed income securities	386			13		(3		)
Net payables (a)	(5		)	—		—
Total	$	658		$	145	$	(3	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2013
Equity securities	$	272		$	129	$	—
Fixed income securities	373			11		(6		)
Net payables (a)	(3		)	—		—
Total	$	642		$	140	$	(6	)

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

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

	Three Months Ended March 31,
	2014			2013
Realized gains	$	1		$	2
Realized losses	(2		)	(1		)
Proceeds from the sale of securities (a)	103			135

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2014 is as follows (dollars in millions):

	Fair Value
Less than one year	$	17
1 year — 5 years	109
5 years — 10 years	111
Greater than 10 years	149
Total	$	386