10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2015

OR

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

For the transition period from              to          

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

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

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION

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

ARIZONA PUBLIC SERVICE COMPANY

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

Indicate by check mark whether each registrant is a shell company (as defined in 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 24, 2015: 110,748,842
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of April 24, 2015: 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		72

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.

1

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, 2014 ("2014 Form 10-K") 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 development of new technologies which may affect electric sales or delivery;

• 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 trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

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

• potential shortfalls in insurance coverage;

• new accounting requirements or new interpretations of existing requirements;

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

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

• the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations; 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 2014 Form 10-K, 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,
	2015			2014
OPERATING REVENUES	$	671,219		$	686,251
OPERATING EXPENSES
Fuel and purchased power	223,237			249,786
Operations and maintenance	214,944			212,882
Depreciation and amortization	120,949			101,772
Taxes other than income taxes	43,216			45,845
Other expenses	1,189			796
Total	603,535			611,081
OPERATING INCOME	67,684			75,170
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	9,224			7,442
Other income (Note 9)	235			2,367
Other expense (Note 9)	(4,286		)	(4,684		)
Total	5,173			5,125
INTEREST EXPENSE
Interest charges	48,399			52,969
Allowance for borrowed funds used during construction	(4,216		)	(3,770		)
Total	44,183			49,199
INCOME BEFORE INCOME TAXES	28,674			31,096
INCOME TAXES	7,947			6,405
NET INCOME	20,727			24,691
Less: Net income attributable to noncontrolling interests (Note 6)	4,605			8,925
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	16,122		$	15,766
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	110,916			110,257
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	111,377			110,888
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	0.15		$	0.14
Net income attributable to common shareholders — diluted	$	0.14		$	0.14

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,
	2015			2014
NET INCOME	$	20,727		$	24,691
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $473 and $599	(800		)	(422		)
Reclassification of net realized loss, net of tax benefit of $367 and $1,323	1,976			3,116
Pension and other postretirement benefits activity, net of tax expense of $867 and $718	583			457
Total other comprehensive income	1,759			3,151
COMPREHENSIVE INCOME	22,486			27,842
Less: Comprehensive income attributable to noncontrolling interests	4,605			8,925
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	17,881		$	18,917

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, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	11,664		$	7,604
Customer and other receivables	242,457			297,740
Accrued unbilled revenues	94,400			100,533
Allowance for doubtful accounts	(2,560		)	(3,094		)
Materials and supplies (at average cost)	221,276			218,889
Fossil fuel (at average cost)	44,705			37,097
Deferred income taxes	113,521			122,232
Income tax receivable (Note 5)	3,317			3,098
Assets from risk management activities (Note 7)	13,658			13,785
Deferred fuel and purchased power regulatory asset (Note 3)	—			6,926
Other regulatory assets (Note 3)	147,869			129,808
Other current assets	45,135			38,817
Total current assets	935,442			973,435
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	18,444			17,620
Nuclear decommissioning trust (Note 12)	727,342			713,866
Other assets	51,449			54,047
Total investments and other assets	797,235			785,533
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,551,726			15,543,063
Accumulated depreciation and amortization	(5,452,860		)	(5,397,751		)
Net	10,098,866			10,145,312
Construction work in progress	841,426			682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	120,287			121,255
Intangible assets, net of accumulated amortization	127,620			119,755
Nuclear fuel, net of accumulated amortization	136,557			125,201
Total property, plant and equipment	11,324,756			11,194,330
DEFERRED DEBITS
Regulatory assets (Note 3)	1,067,830			1,054,087
Assets for other postretirement benefits (Note 4)	156,192			152,290
Other	154,248			153,857
Total deferred debits	1,378,270			1,360,234
TOTAL ASSETS	$	14,435,703		$	14,313,532

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, 2015			December 31, 2014
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	271,489		$	295,211
Accrued taxes (Note 5)	188,724			140,613
Accrued interest	42,096			52,603
Common dividends payable	—			65,790
Short-term borrowings (Note 2)	44,500			147,400
Current maturities of long-term debt (Note 2)	383,570			383,570
Customer deposits	72,561			72,307
Liabilities from risk management activities (Note 7)	62,303			59,676
Deferred fuel and purchased power regulatory liability (Note 3)	16,359			—
Liabilities for asset retirements (Note 15)	28,918			32,462
Other regulatory liabilities (Note 3)	113,024			130,549
Other current liabilities	150,432			178,962
Total current liabilities	1,373,976			1,559,143
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	3,281,319			3,031,215
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,586,180			2,582,636
Regulatory liabilities (Note 3)	1,070,106			1,051,196
Liabilities for asset retirements (Note 15)	379,263			358,288
Liabilities for pension benefits (Note 4)	412,552			453,736
Liabilities from risk management activities (Note 7)	73,827			50,602
Customer advances	122,259			123,052
Coal mine reclamation	199,218			198,292
Deferred investment tax credit	178,313			178,607
Unrecognized tax benefits (Note 5)	14,196			19,377
Other	191,487			188,286
Total deferred credits and other	5,227,401			5,204,072
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 110,809,492 and 110,649,762 issued at respective dates	2,523,247			2,512,970
Treasury stock at cost; 61,784 and 78,400 shares at respective dates	(2,266		)	(3,401		)
Total common stock	2,520,981			2,509,569
Retained earnings	1,942,194			1,926,065
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(57,173		)	(57,756		)
Derivative instruments	(9,209		)	(10,385		)
Total accumulated other comprehensive loss	(66,382		)	(68,141		)
Total shareholders’ equity	4,396,793			4,367,493
Noncontrolling interests (Note 6)	156,214			151,609
Total equity	4,553,007			4,519,102
TOTAL LIABILITIES AND EQUITY	$	14,435,703		$	14,313,532

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

6

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Three Months Ended   March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	20,727		$	24,691
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	141,494			122,394
Deferred fuel and purchased power	17,671			31,630
Deferred fuel and purchased power amortization	5,614			8,022
Allowance for equity funds used during construction	(9,224		)	(7,442		)
Deferred income taxes	6,978			8,810
Deferred investment tax credit	(294		)	(247		)
Change in derivative instruments fair value	(104		)	(13		)
Changes in current assets and liabilities:
Customer and other receivables	39,174			25,986
Accrued unbilled revenues	6,133			7,889
Materials, supplies and fossil fuel	(9,995		)	(187		)
Income tax receivable	(219		)	130,870
Other current assets	(9,631		)	(10,669		)
Accounts payable	(35,673		)	(50,990		)
Accrued taxes	48,111			48,139
Other current liabilities	(56,747		)	(15,864		)
Change in margin and collateral accounts — assets	(276		)	(290		)
Change in margin and collateral accounts — liabilities	(13,420		)	(29,075		)
Change in other long-term assets	(14,432		)	(9,636		)
Change in other long-term liabilities	8,261			(34,861		)
Net cash flow provided by operating activities	144,148			249,157
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(251,041		)	(207,459		)
Contributions in aid of construction	27,222			7,736
Allowance for borrowed funds used during construction	(4,216		)	(3,770		)
Proceeds from nuclear decommissioning trust sales	115,282			103,157
Investment in nuclear decommissioning trust	(119,594		)	(107,470		)
Other	(470		)	(702		)
Net cash flow used for investing activities	(232,817		)	(208,508		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000			250,000
Short-term borrowings and payments — net	(102,900		)	(143,625		)
Dividends paid on common stock	(64,061		)	(62,520		)
Common stock equity issuance	9,690			9,390
Other	—			1
Net cash flow provided by financing activities	92,729			53,246
NET INCREASE IN CASH AND CASH EQUIVALENTS	4,060			93,895
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	7,604			9,526
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	11,664		$	103,421

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

7

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands, except per share amounts)

	Common Stock			Treasury Stock					Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total
	Shares	Amount		Shares		Amount
Balance, January 1, 2014	110,280,703	$	2,491,558	(98,944	)	$	(4,308	)	$	1,785,273	$	(78,053	)	$	145,990	$	4,340,460
Net income									15,766					8,925		24,691
Other comprehensive income											3,151					3,151
Issuance of common stock	108,362	5,927														5,927
Purchase of treasury stock (a)				(82,474	)	(4,535		)								(4,535		)
Stock-based compensation and other				146,590		7,999			8							8,007
Balance, March 31, 2014	110,389,065	$	2,497,485	(34,828	)	$	(844	)	$	1,801,047	$	(74,902	)	$	154,915	$	4,377,701
Balance, January 1, 2015	110,649,762	$	2,512,970	(78,400	)	$	(3,401	)	$	1,926,065	$	(68,141	)	$	151,609	$	4,519,102
Net income									16,122					4,605		20,727
Other comprehensive income											1,759					1,759
Issuance of common stock	159,730	10,277														10,277
Purchase of treasury stock (a)				(93,280	)	(6,095		)								(6,095		)
Stock-based compensation and other				109,896		7,230			7							7,237
Balance, March 31, 2015	110,809,492	$	2,523,247	(61,784	)	$	(2,266	)	$	1,942,194	$	(66,382	)	$	156,214	$	4,553,007

(a)    Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

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

8

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, Bright Canyon Energy Corporation ("BCE") 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.

Supplemental Cash Flow Information

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

	Three Months Ended   March 31,
	2015		2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$	1,832	$	(131,078	)
Interest, net of amounts capitalized	53,555		49,147
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	56,165	$	24,908

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 revolving credit facility matures in May 2019.  At March 31, 2015, 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

9

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

increase the size 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, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020.  The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash used to fund capital expenditures.

At March 31, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and the $500 million facility that matures in May 2019.  APS may increase the size 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, 2015, APS had $45 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.

See "Financial Assurances" in Note 8 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, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,540		4,045		3,290		3,714
Total	$	3,665	$	4,170	$	3,415	$	3,839

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, 2015, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.3 billion, assuming APS’s total capitalization remains the same.

10

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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of the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);

• Implementation of a Lost Fixed Cost Recovery ("LFCR") 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

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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 September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules are expected to become effective in the second quarter of 2015.

In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.

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 required 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.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system.

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.

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On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rule making has not been initiated and there has been no additional action on the draft to date.

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 2015 and 2014 (dollars in millions):

	Three Months Ended   March 31,
	2015			2014
Beginning balance	$	7		$	21
Deferred fuel and purchased power costs — current period	(18		)	(32		)
Amounts charged to customers	(5		)	(8		)
Ending balance	$	(16	)	$	(19	)

The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh.  Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the United States Federal Energy Regulatory Commission ("FERC") approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, 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, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in

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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, 2014.

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 LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  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. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March.

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 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.  A series of workshops in this docket were held in 2014 and early 2015.

Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address 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. 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 fixed charge does not increase APS's revenue because it is credited to the LFCR.

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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.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. 

On April 2, 2015, APS filed an application with the ACC seeking to increase the fixed grid access charge to $3.00 per kilowatt, or approximately $21 per month for a typical new residential solar customer, effective August 1. Customers who installed rooftop solar panels prior to January 1, 2014 would continue to be grandfathered and would not pay a grid access charge, and those who installed panels between January 1, 2014 and the effective date of the requested change would continue paying a charge of $0.70 per kilowatt. Solar customers that take electric service under APS’s demand-based ECT-2 residential rate, an existing rate that includes time-of-use rates with a demand charge, are not subject to the grid access charge.

APS cannot predict the outcome of this filing. The proposed grid access charge adjustment is designed to moderate the cost shift discussed above on an interim basis until the issue is further addressed in APS’s next general rate case or another proceeding.

On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.

Four Corners

On December 30, 2013, APS purchased Southern California Edison Company's ("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. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs 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 through its inclusion in rates.  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 $75 million as of March 31, 2015 and is being amortized in rates over 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS intends to intervene and actively participate in the proceeding. We cannot predict when or how this appeal will be resolved.

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

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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.  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 are 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.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Cholla

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Unit 2 of the Cholla Power Plant ("Cholla") by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. On April 14, 2015, the ACC approved APS's proposed retirement of Cholla Unit 2 in accordance with the ACC's Integrated Resource Planning rules. The ACC expressly stated that this approval does not imply any specific treatment or recommendation for rate making purposes.

If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($127 million as of March 31, 2015), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

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Regulatory Assets and Liabilities

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

	Remaining Amortization Period	March 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Pension benefits	(a)	$	—	$	479	$	—	$	485
Income taxes — allowance for funds used during construction ("AFUDC") equity	2044	5		117		5		118
Deferred fuel and purchased power — mark-to-market (Note 7)	2018	66		72		51		46
Transmission vegetation management	2016	9		2		9		5
Coal reclamation	2026	—		6		—		7
Palo Verde VIEs (Note 6)	2046	—		30		—		35
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		7		—
Tax expense of Medicare subsidy	2024	2		14		2		14
Loss on reacquired debt	2034	1		16		1		16
Income taxes — investment tax credit basis adjustment	2044	2		46		2		46
Pension and other postretirement benefits deferral	2015	2		—		4		—
Four Corners cost deferral	2024	7		68		7		70
Lost fixed cost recovery (b)	2016	43		—		38		—
Retired power plant costs	2033	10		134		10		136
Deferred property taxes	(d)	—		36		—		30
Other	Various	1		12		2		12
Total regulatory assets (e)		$	148	$	1,068	$	138	$	1,054

(a) This asset represents the future recovery of 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) Per the provision of the 2012 Settlement Agreement.

(e) 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, Transmission Cost Adjustor and Other Transmission Matters."

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

	Remaining Amortization Period	March 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	37	$	264	$	31	$	273
Asset retirement obligations	2044	—		302		—		296
Renewable energy standard (b)	2017	25		25		25		23
Income taxes — change in rates	2043	1		71		—		72
Spent nuclear fuel	2047	5		66		5		66
Deferred gains on utility property	2019	2		8		2		8
Income taxes — deferred investment tax credit	2043	3		93		4		93
Deferred fuel and purchased power (b) (c)	2016	16		—		—		—
Demand side management (b)	2017	5		27		31		—
Other postretirement benefits	(d)	32		191		32		199
Other	Various	3		23		1		21
Total regulatory liabilities		$	129	$	1,070	$	131	$	1,051

(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 a carrying charge.

(d) See Note 4.

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 an other postretirement benefit plan 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 dates. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of these plan changes in 2014, the Company is currently in the process of seeking IRS and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new account to pay for active union employee medical costs.

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, 2015 and 2014, 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,
	2015			2014			2015			2014
Service cost — benefits earned during the period	$	16		$	15		$	4		$	5
Interest cost on benefit obligation	31			32			7			11
Expected return on plan assets	(45		)	(40		)	(9		)	(12		)
Amortization of:
Prior service cost	—			—			(10		)	—
Net actuarial loss	8			2			2			—
Net periodic benefit cost	$	10		$	9		$	(6	)	$	4
Portion of cost charged to expense	$	6		$	5		$	(2	)	$	3

Contributions

We have made voluntary contributions of $60 million to our pension plan in 2015. The minimum contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

5. Income Taxes

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations were accounted for in the Condensed Consolidated Balance Sheets as of December 31, 2014.

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.

As of March 31, 2015, the tax year ended December 31, 2011 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 2009.

6. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lease agreements include fixed rate renewal periods. On July 7, 2014, APS notified the lessor trust entities of APS's intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $49 million in 2015, $23 million annually for the period 2016 through

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2023, and $16 million annually for the period 2024 through 2033. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to 2 years, or return the assets to the lessors.

The fixed rate renewal periods give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2015 of $5 million and for the three months ended March 31, 2014 of $9 million, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased because of lower rent income resulting from the July 7, 2014 lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. 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, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):

	March 31, 2015		December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	120	$	121
Current maturities of long-term debt	13		13
Equity — Noncontrolling interests	156		152

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

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of March 31, 2015, APS would have been required to pay the noncontrolling equity participants approximately $123 million and assume $13 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 agreements 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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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 11 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.

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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, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	4,186	GWh
Gas	157	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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   March 31,
Commodity Contracts		2015			2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	(327	)	$	177
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(2,343		)	(4,439		)

(a) During the three months ended March 31, 2015 and 2014, 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 $5 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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   March 31,
Commodity Contracts		2015			2014
Net loss recognized in income	Operating revenues (a)	$	(48	)	$	(92	)
Net gain (loss) recognized in income	Fuel and purchased power (a)	(44,803		)	18,107
Total		$	(44,851	)	$	18,015

(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, 2015 and December 31, 2014, each include gross liabilities of $4 million 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, 2015 and December 31, 2014.  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, 2015: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance  Sheet
Current assets	$	26,414		$	(13,382	)	$	13,032		$	626		$	13,658
Investments and other assets	23,035			(4,591		)	18,444			—			18,444
Total assets	49,449			(17,973		)	31,476			626			32,102
Current liabilities	(97,349		)	42,069			(55,280		)	(7,023		)	(62,303		)
Deferred credits and other	(106,631		)	32,804			(73,827		)	—			(73,827		)
Total liabilities	(203,980		)	74,873			(129,107		)	(7,023		)	(136,130		)
Total	$	(154,531	)	$	56,900		$	(97,631	)	$	(6,397	)	$	(104,028	)

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

(b) Includes cash collateral provided to counterparties of $56,900.

(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 $7,023 and cash margin provided to counterparties of $626.

As of December 31, 2014: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance  Sheet
Current assets	$	28,562		$	(15,127	)	$	13,435		$	350		$	13,785
Investments and other assets	24,810			(7,190		)	17,620			—			17,620
Total assets	53,372			(22,317		)	31,055			350			31,405
Current liabilities	(86,062		)	33,829			(52,233		)	(7,443		)	(59,676		)
Deferred credits and other	(82,990		)	32,388			(50,602		)	—			(50,602		)
Total liabilities	(169,052		)	66,217			(102,835		)	(7,443		)	(110,278		)
Total	$	(115,680	)	$	43,900		$	(71,780	)	$	(7,093	)	$	(78,873	)

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

(b) Includes cash collateral provided to counterparties of $43,900.

(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 $7,443, and cash margin provided to counterparties of $350.

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 one counterparty for which our exposure represents approximately 94% of Pinnacle West’s $32 million of risk management assets as of March 31, 2015.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a 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

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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, 2015 (dollars in millions):

	March 31, 2015
Aggregate fair value of derivative instruments in a net liability position	$	204
Cash collateral posted	57
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	104

(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 $166 million if our debt credit ratings were to fall below investment grade.

8. 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 Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this

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amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

On March 11, 2015, the DOE notified APS that it had approved APS’s claim for damages incurred due to DOE’s breach of the Standard Contract for the period July 1, 2011 through June 30, 2014. The claim for this period was the first claim made pursuant to the terms of the August 18, 2014 settlement agreement. The amount claimed was $42.0 million; APS’s share of this amount is $12.2 million. The settlement payment will be received in the second quarter of 2015. APS’s $12.2 million share will be recorded as an adjustment to a regulatory liability and will have no impact on income.

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 American Nuclear Insurers ("ANI").  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 liability 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 ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment 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").  APS is subject to retrospective premium 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 $23 million for each retrospective premium 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 $62 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 2014 Form 10-K.

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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 52^nd 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.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Southwest Power Outage

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.

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 fully briefed and pending before the United States Court of Appeals for the Ninth Circuit.  We are unable to predict the outcome of this matter.

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

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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.  We do not expect the outcome of this matter to have a material impact on our financial position, results of operations or cash flows.

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, Cholla and the Navajo Generating Station ("Navajo Plant").  EPA and 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. 

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $400 million.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. The cost of the controls related to the 7% interest is approximately $45 million.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million.  In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process.

Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million, 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. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and

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will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015.

Mercury and Air Toxic Standards.  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, which would be avoided if EPA approves APS's compromise proposal discussed above. 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.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million.

Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, greenhouse gas ("GHG") emissions (such as the EPA’s proposed "Clean Power Plan" rule), 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

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plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

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.  We cannot predict the timing or outcome of this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At March 31, 2015, approximately $109 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, two expire in 2016, and one expires in 2017.  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 $20 million at March 31, 2015.  Additionally, APS has issued a letter of credit to support collateral obligations under a natural gas tolling contract entered into with a third party.  At March 31, 2015, that letter of credit totaled $5 million and will expire in 2015.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification 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 has provided indemnification under certain surety bonds for APS which were not material at March 31, 2015.

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9. Other Income and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended   March 31,
	2015			2014
Other income:
Interest income	$	110		$	251
Miscellaneous	125			2,116
Total other income	$	235		$	2,367
Other expense:
Non-operating costs	$	(2,249	)	$	(2,372	)
Investment losses — net	(495		)	(140		)
Miscellaneous	(1,542		)	(2,172		)
Total other expense	$	(4,286	)	$	(4,684	)

10. Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three months ended March 31, 2015 and 2014 (in thousands, except per share amounts):

	Three Months Ended   March 31,
	2015		2014
Net income attributable to common shareholders	$	16,122	$	15,766
Weighted average common shares outstanding — basic	110,916		110,257
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	461		631
Weighted average common shares outstanding — diluted	111,377		110,888
Earnings per average common share attributable to common shareholders — basic	$	0.15	$	0.14
Earnings per average common share attributable to common shareholders — diluted	$	0.14	$	0.14

11. 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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 that are redeemable and valued based on NAV, such as common and collective trusts and commingled funds.

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 7 in the 2014 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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, 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 Trust

The nuclear decommissioning trust invests in fixed income securities and equity securities.  Equity securities are held indirectly through commingled funds.  The commingled funds are valued based on the concept of Net Asset Value ("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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 12 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at March 31, 2015, 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, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	16		$	33		$	(17	)	(b)	$	32
Nuclear decommissioning trust:
U.S. commingled equity funds	—		313			—			—				313
Fixed income securities:
U.S. Treasury	103		—			—			—				103
Cash and cash equivalent funds	—		10			—			(2		)	(c)	8
Corporate debt	—		115			—			—				115
Mortgage-backed securities	—		88			—			—				88
Municipality bonds	—		85			—			—				85
Other	—		15			—			—				15
Subtotal nuclear decommissioning trust	103		626			—			(2		)		727
Total	$	103	$	642		$	33		$	(19	)		$	759
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(122	)	$	(82	)	$	68		(b)	$	(136	)

(a) Primarily consists of heat rate options and other 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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 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 December 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	33		$	(23	)	(b)	$	31
Nuclear decommissioning trust:
U.S. commingled equity funds	—		310			—			—				310
Fixed income securities:
U.S. Treasury	119		—			—			—				119
Cash and cash equivalent funds	—		11			—			(7		)	(c)	4
Corporate debt	—		109			—			—				109
Mortgage-backed securities	—		89			—			—				89
Municipality bonds	—		69			—			—				69
Other	—		14			—			—				14
Subtotal nuclear decommissioning trust	119		602			—			(7		)		714
Total	$	119	$	623		$	33		$	(30	)		$	745
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(95	)	$	(74	)	$	59		(b)	$	(110	)

(a) Primarily consists of heat rate options and other 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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2015 and December 31, 2014:

	March 31, 2015 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	31	$	60	Discounted cash flows	Electricity forward price (per MWh)	$18.88 - $46.54	$	30.49
Option Contracts (b)	—		15		Option model	Electricity forward price (per MWh)	$30.24 - $60.45	$	41.81
						Natural gas forward price (per MMBtu)	$2.35 - $2.88	$	2.83
						Electricity price volatilities	27% - 86%	54		%
						Natural gas price volatilities	26% - 43%	32		%
Natural Gas:
Forward Contracts (a)	2		7		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.30 - $3.59	$	3.01
Total	$	33	$	82

(a) Includes swaps and physical and financial contracts.

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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2014 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	30	$	56	Discounted cash flows	Electricity forward price (per MWh)	$19.51 - $56.72	$	35.27
Option Contracts (b)	—		15		Option model	Electricity forward price (per MWh)	$32.14 - $66.09	$	45.83
						Natural gas forward price (per MMBtu)	$3.18 - $3.29	$	3.25
						Electricity price volatilities	23% - 63%	41		%
						Natural gas price volatilities	23% - 41%	31		%
Natural Gas:
Forward Contracts (a)	3		3		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.98 - $4.13	$	3.45
Total	$	33	$	74

(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.

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, 2015 and 2014 (dollars in millions):

	Three Months Ended   March 31,
Commodity Contracts	2015			2014
Net derivative balance at beginning of period	$	(41	)	$	(49	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(11		)	4
Settlements	—			—
Transfers into Level 3 from Level 2	(1		)	(3		)
Transfers from Level 3 into Level 2	4			(1		)
Net derivative balance at end of period	$	(49	)	$	(49	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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 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.

12. 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 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 11 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, 2015 and December 31, 2014 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2015
Equity securities	$	313		$	161	$	—
Fixed income securities	416			20		(1		)
Net payables (a)	(2		)	—		—
Total	$	727		$	181	$	(1	)

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2014
Equity securities	$	310		$	159	$	—
Fixed income securities	411			17		(1		)
Net payables (a)	(7		)	—		—
Total	$	714		$	176	$	(1	)

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

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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 gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Three Months Ended   March 31,
	2015			2014
Realized gains	$	1		$	1
Realized losses	(1		)	(2		)
Proceeds from the sale of securities (a)	115			103

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2015 is as follows (dollars in millions):

	Fair Value
Less than one year	$	16
1 year – 5 years	113
5 years – 10 years	118
Greater than 10 years	169
Total	$	416

13. New Accounting Standards

In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The guidance may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. As originally issued, the new revenue standard would be effective for us on January 1, 2017; however, the FASB has recently proposed a one year deferral of the effective date, which if finalized will result in the new guidance being effective for us on January 1, 2018. We are currently evaluating this new guidance and the impacts it may have on our financial statements.

In February 2015, new guidance was issued that amends the consolidation accounting guidance. The amendments modify many aspects of the guidance relating to the analysis and consolidation of variable interest entities. These changes include impacts on the following: limited partnerships, fees paid to decision makers, related parties, and the determination of whether an entity qualifies as a variable interest entity. The new guidance is effective for us on January 1, 2016, and may be adopted using either a full retrospective or modified retrospective approach. We are currently evaluating this amended guidance and the impacts it may have on our financial statements.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(57,756	)		$	(68,141	)	$	(23,058	)		$	(54,995	)		$	(78,053	)
OCI (loss) before reclassifications	(800		)		—				(800		)	(422		)		—				(422		)
Amounts reclassified from accumulated other comprehensive loss	1,976			(a)	583			(b)	2,559			3,116			(a)	457			(b)	3,573
Net current period OCI	1,176				583				1,759			2,694				457				3,151
Ending balance, March 31,	$	(9,209	)		$	(57,173	)		$	(66,382	)	$	(20,364	)		$	(54,538	)		$	(74,902	)

(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.

15. Asset Retirement Obligations

In the first quarter of 2015, an updated decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the ARO in the amount of $18 million. The following schedule shows the change in our asset retirement obligations for the three months ended March 31, 2015 (dollars in millions): 

Asset retirement obligations at January 1, 2015	$	391
Changes attributable to:
Accretion expense	6
Settlements	(7		)
Estimated cash flow revisions	18
Asset retirement obligations at March 31, 2015	$	408

Decommissioning activities for Four Corners Units 1-3 began in January 2014; thus, $29 million of the total asset retirement obligation of $408 million at March 31, 2015, is classified as a current liability on the balance sheet.

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 3.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   March 31,
	2015			2014
ELECTRIC OPERATING REVENUES	$	670,668		$	685,545
OPERATING EXPENSES
Fuel and purchased power	223,237			249,786
Operations and maintenance	209,947			208,285
Depreciation and amortization	120,926			101,748
Income taxes	12,239			10,478
Taxes other than income taxes	42,986			45,613
Total	609,335			615,910
OPERATING INCOME	61,333			69,635
OTHER INCOME (DEDUCTIONS)
Income taxes	2,151			1,210
Allowance for equity funds used during construction	9,224			7,442
Other income (Note S-1)	639			2,762
Other expense (Note S-1)	(5,354		)	(5,056		)
Total	6,660			6,358
INTEREST EXPENSE
Interest on long-term debt	45,428			48,896
Interest on short-term borrowings	1,174			1,413
Debt discount, premium and expense	1,134			1,011
Allowance for borrowed funds used during construction	(4,216		)	(3,770		)
Total	43,520			47,550
NET INCOME	24,473			28,443
Less: Net income attributable to noncontrolling interests (Note 6)	4,605			8,925
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	19,868		$	19,518

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   March 31,
	2015			2014
NET INCOME	$	24,473		$	28,443
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $473 and $599	(800		)	(421		)
Reclassification of net realized loss, net of tax benefit of $367 and $1,323	1,976			3,116
Pension and other postretirement benefits activity, net of tax expense of $769 and $606	681			566
Total other comprehensive income	1,857			3,261
COMPREHENSIVE INCOME	26,330			31,704
Less: Comprehensive income attributable to noncontrolling interests	4,605			8,925
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	21,725		$	22,779

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	March 31, 2015			December 31, 2014
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	15,548,474		$	15,539,811
Accumulated depreciation and amortization	(5,449,753		)	(5,394,650		)
Net	10,098,721			10,145,161
Construction work in progress	840,928			682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	120,287			121,255
Intangible assets, net of accumulated amortization	127,465			119,600
Nuclear fuel, net of accumulated amortization	136,557			125,201
Total property, plant and equipment	11,323,958			11,194,024
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 12)	727,342			713,866
Assets from risk management activities (Note 7)	18,444			17,620
Other assets	33,832			33,362
Total investments and other assets	779,618			764,848
CURRENT ASSETS
Cash and cash equivalents	6,083			4,515
Customer and other receivables	238,863			297,712
Accrued unbilled revenues	94,400			100,533
Allowance for doubtful accounts	(2,560		)	(3,094		)
Materials and supplies (at average cost)	221,276			218,889
Fossil fuel (at average cost)	44,705			37,097
Assets from risk management activities (Note 7)	13,658			13,785
Deferred fuel and purchased power regulatory asset (Note 3)	—			6,926
Other regulatory assets (Note 3)	147,869			129,808
Deferred income taxes	54,789			55,253
Other current assets	44,496			38,693
Total current assets	863,579			900,117
DEFERRED DEBITS
Regulatory assets (Note 3)	1,067,830			1,054,087
Assets for other postretirement benefits (Note 4)	153,156			149,260
Unamortized debt issue costs	25,948			24,642
Other	127,190			128,026
Total deferred debits	1,374,124			1,356,015
TOTAL ASSETS	$	14,341,279		$	14,215,004

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands) 

	March 31, 2015			December 31, 2014
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,988,587			1,968,718
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(37,267		)	(37,948		)
Derivative instruments	(9,209		)	(10,385		)
Total shareholder equity	4,499,969			4,478,243
Noncontrolling interests (Note 6)	156,214			151,609
Total equity	4,656,183			4,629,852
Long-term debt less current maturities (Note 2)	3,156,319			2,906,215
Total capitalization	7,812,502			7,536,067
CURRENT LIABILITIES
Short-term borrowings (Note 2)	44,500			147,400
Current maturities of long-term debt (Note 2)	383,570			383,570
Accounts payable	265,779			289,930
Accrued taxes (Note 5)	190,167			131,110
Accrued interest	41,919			52,358
Common dividends payable	—			65,800
Customer deposits	72,561			72,307
Liabilities from risk management activities (Note 7)	62,303			59,676
Liabilities for asset retirements (Note 15)	28,918			32,462
Deferred fuel and purchased power regulatory liability (Note 3)	16,359			—
Other regulatory liabilities (Note 3)	113,024			130,549
Other current liabilities	130,161			167,302
Total current liabilities	1,349,261			1,532,464
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,573,876			2,571,365
Regulatory liabilities (Note 3)	1,070,106			1,051,196
Liabilities for asset retirements (Note 15)	379,263			358,288
Liabilities for pension benefits (Note 4)	384,215			424,508
Liabilities from risk management activities (Note 7)	73,827			50,602
Customer advances	122,259			123,052
Coal mine reclamation	199,218			198,292
Deferred investment tax credit	178,313			178,607
Unrecognized tax benefits (Note 5)	45,190			45,740
Other	153,249			144,823
Total deferred credits and other	5,179,516			5,146,473
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	14,341,279		$	14,215,004

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Three Months Ended   March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	24,473		$	28,443
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	141,471			122,370
Deferred fuel and purchased power	17,671			31,630
Deferred fuel and purchased power amortization	5,614			8,022
Allowance for equity funds used during construction	(9,224		)	(7,442		)
Deferred income taxes	2,427			8,696
Deferred investment tax credit	(294		)	(247		)
Change in derivative instruments fair value	(104		)	(13		)
Changes in current assets and liabilities:
Customer and other receivables	43,070			25,749
Accrued unbilled revenues	6,133			7,889
Materials, supplies and fossil fuel	(9,995		)	(187		)
Income tax receivable	—			134,890
Other current assets	(9,116		)	(10,807		)
Accounts payable	(35,604		)	(52,621		)
Accrued taxes	59,057			50,580
Other current liabilities	(65,290		)	(5,257		)
Change in margin and collateral accounts — assets	(276		)	(290		)
Change in margin and collateral accounts — liabilities	(13,421		)	(29,075		)
Change in other long-term assets	(17,559		)	(10,439		)
Change in other long-term liabilities	13,941			(28,083		)
Net cash flow provided by operating activities	152,974			273,808
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(250,930		)	(207,459		)
Contributions in aid of construction	27,222			7,736
Allowance for borrowed funds used during construction	(4,216		)	(3,770		)
Proceeds from nuclear decommissioning trust sales	115,282			103,157
Investment in nuclear decommissioning trust	(119,594		)	(107,470		)
Other	(470		)	(702		)
Net cash flow used for investing activities	(232,706		)	(208,508		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000			250,000
Short-term borrowings — net	(102,900		)	(153,125		)
Dividends paid on common stock	(65,800		)	(62,500		)
Net cash flow provided by financing activities	81,300			34,375
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,568			99,675
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	4,515			3,725
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	6,083		$	103,400
Supplemental disclosure of cash flow information
Cash paid (received) during the period for:
Income taxes, net of refunds	$	184		$	(134,323	)
Interest, net of amounts capitalized	$	52,825		$	47,464
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	56,165		$	24,908

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)

	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total
	Shares	Amount
Balance, January 1, 2014	71,264,947	$	178,162	$	2,379,696	$	1,804,398		$	(53,372	)	$	145,990	$	4,454,874
Net income						19,518						8,925		28,443
Other comprehensive income									3,261					3,261
Other						(2		)						(2		)
Balance, March 31, 2014	71,264,947	$	178,162	$	2,379,696	$	1,823,914		$	(50,111	)	$	154,915	$	4,486,576
Balance, January 1, 2015	71,264,947	$	178,162	$	2,379,696	$	1,968,718		$	(48,333	)	$	151,609	$	4,629,852
Net income						19,868						4,605		24,473
Other comprehensive income									1,857					1,857
Other						1								1
Balance, March 31, 2015	71,264,947	$	178,162	$	2,379,696	$	1,988,587		$	(46,476	)	$	156,214	$	4,656,183

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

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

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

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. 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, 2015 and 2014 (dollars in thousands):

	Three Months Ended   March 31,
	2015			2014
Other income:
Interest income	$	67		$	138
Miscellaneous	572			2,624
Total other income	$	639		$	2,762
Other expense:
Non-operating costs (a)	$	(2,517	)	$	(2,587	)
Asset dispositions	(643		)	(183		)
Miscellaneous	(2,194		)	(2,286		)
Total other expense	$	(5,354	)	$	(5,056	)

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

S-2. Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(37,948	)		$	(48,333	)	$	(23,059	)		$	(30,313	)		$	(53,372	)
OCI (loss) before reclassifications	(800		)		—				(800		)	(421		)		—				(421		)
Amounts reclassified from accumulated other comprehensive loss	1,976			(a)	681			(b)	2,657			3,116			(a)	566			(b)	3,682
Net current period OCI	1,176				681				1,857			2,695				566				3,261
Ending balance, March 31,	$	(9,209	)		$	(37,267	)		$	(46,476	)	$	(20,364	)		$	(29,747	)		$	(50,111	)

(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 FINANCIALCONDITION 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 2014 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 address lessons learned from the Fukushima events. The independent assessment, named the "Near Term Task Force," recommended a number of proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans. The NRC has directed nuclear power plants to begin implementing some of the Near Term Task Force’s recommendations. To implement these recommendations, Palo Verde expects to spend approximately $32 million for capital enhancements to the plant through 2016 in addition to the approximate $99 million that has already been spent on capital enhancements as of March 31, 2015 (APS’s share is 29.1%).

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 GHG emissions.  On June 2, 2014, EPA proposed a rule to limit carbon dioxide emissions from existing power plants.  EPA expects to finalize the proposal in summer 2015.  EPA’s proposal for Arizona would result in a shift in in-state generation from coal to natural gas and renewable generation.  Such a substantial change in APS’s generation portfolio could require additional capital investments and increased operating costs, and thus have a significant financial impact on the Company.  APS continually analyzes its long-range capital management plans to assess the potential effects of these changes, 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 continue participation in such plants.

Cholla

On September 11, 2014, APS announced that it will close its 260 megawatt Unit 2 at Cholla by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and

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rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2. (See Note 3 for details related to the resulting regulatory asset and Note 8 for details of the proposal.) APS believes that the environmental benefits of this proposal are greater in the long term than the benefits that would have resulted from adding the emissions control equipment.

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. 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 23, 2014, the ACC approved rate adjustments related to APS’s acquisition of SCE’s interest in Four Corners resulting in a revenue increase of $57.1 million on an annual basis. On February 23, 2015, the ACC decision approving the rate adjustments was appealed. APS intends to intervene and actively participate in the proceeding. We cannot predict when or how this appeal will be resolved.

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, 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. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. The cash purchase price, which will be subject to certain adjustments at closing, is immaterial in amount, and the purchaser will assume El Paso's reclamation and decommissioning obligations associated with the 7% interest. Completion of the purchase is subject to the receipt of certain regulatory approvals and is expected to occur in July 2016.

When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, 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 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 the Navajo Mine Energy Project, APS, along with other members of the public, submitted comments on the draft impact statement. APS cannot predict whether these federal approvals will be granted,

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and, if so, on a timely basis, or whether any conditions that may be attached to them will be acceptable to the owners of Four Corners. On December 19, 2014, APS obtained a PSD permit from EPA allowing APS to install SCR control technology at Four Corners.

Natural Gas.  APS has six natural gas power plants located throughout Arizona, including Ocotillo.  Ocotillo is a 330 MW 4-unit gas plant located in Tempe, Arizona.  In early 2014, APS announced a project to modernize the plant, which involves retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines.  In total, this increases the capacity of the site by 290 MW, to 620 MW. During the ACC's Integrated Resource Planning meeting in the fall of 2014, there was clear understanding of the need to replace the existing steam units, but questions were raised on the cost effectiveness of the additional three units.  To address these matters, APS issued a request for proposal ("RFP") in late January 2015 for the incremental capacity, equivalent to 3 of the 5 units. Bids were due in March and have been analyzed by APS. An independent monitor was involved throughout the entire RFP process. The RFP affirmed that APS's bid at the existing Ocotillo site was the most cost effective while it also demonstrated that a target completion date of 2019 was most appropriate (instead of 2018 as originally planned).

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 APS transmission projects through 2017, 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 5% of retail electric sales in 2015 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 gigawatt-hour ("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 September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules are expected to become effective in the second quarter of 2015.

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On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.

The following table summarizes renewable energy sources in APS's renewable portfolio that are in operation and under development as of May 1, 2015.

	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar (a)	169	29
Purchased Power Agreements:
Solar	310	—
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	629	—
Total Distributed Energy: Solar (b)	409	26
Total Renewable Portfolio	1,207	55

(a) Included in the 169 MW number is 150 MW of solar resources procured through the AZ Sun Program.

(b) 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 $675 million.  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.

In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.

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 Energy Efficiency Standard ("EES") of 22% cumulative annual energy savings by 2020.  The 22% figure represents the cumulative reduction in future

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energy usage through 2020 attributable to energy efficiency initiatives.  This standard became effective on January 1, 2011.

On June 1, 2012, APS filed its 2013 DSM Plan.  In 2013, the standards required 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.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system.

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.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rule making has not been initiated and there has been no additional action on the draft to date.

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.  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

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APS of its obligations under that agreement.  If APS and SCE are 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.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

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 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.  A series of workshops in this docket were held in 2014 and early 2015.

Net Metering.  On July 12, 2013, APS filed an application with the ACC proposing a solution to address 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.  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 fixed charge does not increase APS's revenue because it is credited to the LFCR.

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.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.

On April 2, 2015, APS filed an application with the ACC seeking to increase the fixed grid access charge to $3.00 per kilowatt, or approximately $21 per month for a typical new residential solar customer, effective August 1. Customers who installed rooftop solar panels prior to January 1, 2014 would continue to be grandfathered and would not pay a grid access charge, and those who installed panels between January 1, 2014 and the effective date of the requested change would continue paying a charge of $0.70 per kilowatt. Solar customers that take electric service under APS’s demand-based ECT-2 residential rate, an existing rate that includes time-of-use rates with a demand charge, are not subject to the grid access charge.

APS cannot predict the outcome of this filing. The proposed grid access charge adjustment is designed to moderate the cost shift discussed above on an interim basis until the issue is further addressed in APS’s next general rate case or another proceeding.

On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.

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

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

Other Subsidiaries.

Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE will focus on new growth opportunities that leverage the Company’s core expertise in the electric energy industry.  BCE’s first initiative is a 50/50 joint venture with BHE U.S. Transmission LLC, formerly MidAmerican Transmission, LLC.  The joint venture, named TransCanyon, intends to focus on transmission opportunities within the Western Electricity Coordinating Council, excluding the retail service territories of the venture partners’ utility affiliates.  The joint venture submitted a bid into California Independent System Operator’s ("CAISO") competitive solicitation process to design, build and own a new 500 kV transmission line between Arizona and California, the Delaney to Colorado River Transmission Line.  In February, TransCanyon collaborated with SCE to submit a joint proposal, replacing the original bids by each of TransCanyon and SCE. The winner of the bidding process is expected to be announced in 2015.  This transmission line will connect a planned Delaney substation near Palo Verde in Arizona to the existing Colorado River substation located just west of Blythe, California.

El Dorado. The operations of El Dorado are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

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 2012 through 2014, retail electric revenues comprised approximately 93% of our total electric operating revenues.  Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.  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 1.2% for the three-month period ended March 31, 2015 compared with the prior-year period.  For the three years 2012 through 2014, APS’s customer growth averaged 1.3% per year. We currently expect annual customer growth to average in the range of 2.0-3.0% for 2015 through 2017 based on our assessment of modestly improving economic conditions in Arizona. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.8% for the three-month period ended March 31, 2015 compared with the prior-year period, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, partially offset by improving economic conditions and customer growth.  For the three years 2012 through 2014, APS experienced annual decreases in retail electricity sales averaging 0.2%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average in the range of 0.5-1.5% during 2015 through 2017, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  A slower recovery of the Arizona economy could further impact these estimates.

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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 projections 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.  On September 30, 2014, Pinnacle West announced plan design changes to the group life and medical postretirement benefit plan, which reduced net periodic benefit costs. See Note 4.

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 10.7% of the assessed value for 2014 and 10.5% for 2013.  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.

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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, 2015 compared with three-month period ended March 31, 2014.

Our consolidated net income attributable to common shareholders for the three months ended March 31, 2015 was $16 million, compared with consolidated net income of $16 million for the prior-year period.  The results reflect an increase of approximately $1 million for the regulated electricity segment primarily due to the Four Corners related rate change, the effects of weather, and lower interest charges, offset by higher depreciation and amortization.

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

	Three Months Ended March 31,
	2015			2014			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	448		$	436		$	12
Operations and maintenance	(215		)	(213		)	(2		)
Depreciation and amortization	(121		)	(102		)	(19		)
Taxes other than income taxes	(43		)	(46		)	3
All other income and expenses, net	5			5			—
Interest charges, net of allowance for borrowed funds used during construction	(44		)	(49		)	5
Income taxes	(8		)	(6		)	(2		)
Less income related to noncontrolling interests (Note 6)	(5		)	(9		)	4
Regulated electricity segment net income	17			16			1
All other	(1		)	—			(1		)
Net Income Attributable to Common Shareholders	$	16		$	16		$	—

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Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $12 million higher for the three months ended March 31, 2015 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)
Four Corners related rate change	$	11		$	—		$	11
Effects of weather	11			4			7
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(26		)	(23		)	(3		)
Long-term traditional wholesale contracts	(8		)	(5		)	(3		)
Miscellaneous items, net	(3		)	(3		)	—
Total	$	(15	)	$	(27	)	$	12

Operations and maintenance.  Operations and maintenance expenses increased $2 million for the three months ended March 31, 2015 compared with the prior-year period primarily because of:

• An increase of $5 million in generation costs, primarily due to higher fossil plant maintenance costs as a result of more work being completed in the first quarter of 2015 compared with the first quarter of 2014;

• A decrease of $4 million related to costs for demand-side management, renewable energy and similar regulatory programs which were offset in operating revenues; and

• An increase of $1 million related to other miscellaneous factors.

Depreciation and amortization.  Depreciation and amortization expenses were $19 million higher for the three months ended March 31, 2015 compared with the prior-year period primarily related to:

• An increase of $9 million related to the absence of 2014 Four Corners cost deferrals;

• An increase of $6 million related to the 2015 amortization of the Four Corners cost deferrals and acquisition adjustment; and

• An increase of $4 million due to increased plant in service.

Interest charges, net of allowance for borrowed funds used during construction.  Interest charges, net of allowance for borrowed funds used during construction, decreased $5 million for the three months ended March 31, 2015 compared with the prior-year period, primarily because of lower interest rates in the current year.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness.  The level of our common stock dividends and future dividend growth will be dependent on declaration 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 related ACC order, the common equity ratio is defined as 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, 2015, APS’s common equity ratio, as defined, was 55%.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.3 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, 2015 and 2014 (dollars in millions):

Pinnacle West Consolidated

	Three Months Ended March 31,						Net
	2015			2014			Change
Net cash flow provided by operating activities	$	144		$	249		$	(105	)
Net cash flow used for investing activities	(233		)	(208		)	(25		)
Net cash flow provided by financing activities	93			53			40
Net increase in cash and cash equivalents	$	4		$	94		$	(90	)

Arizona Public Service Company

	Three Months Ended March 31,						Net
	2015			2014			Change
Net cash flow provided by operating activities	$	153		$	274		$	(121	)
Net cash flow used for investing activities	(232		)	(208		)	(24		)
Net cash flow provided by financing activities	81			34			47
Net increase in cash and cash equivalents	$	2		$	100		$	(98	)

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Operating Cash Flows

Three-month period ended March 31, 2015 compared with three-month period ended March 31, 2014.  Pinnacle West’s consolidated net cash provided by operating activities was $144 million in 2015 compared to $249 million in 2014, a decrease of $105 million in net cash provided.  The decrease is primarily related to a $135 million income tax refund received in the first quarter of 2014. The decrease is partially offset by a $16 million change in cash collateral posted, 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 118% funded as of January 1, 2014 and is estimated to be approximately 118% funded as of January 1, 2015.  Under GAAP, the qualified pension plan was 90% funded as of January 1, 2014 and is estimated to be approximately 90% funded as of January 1, 2015. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.  Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We have made voluntary contributions of $60 million to our pension plan in 2015. The minimum contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

Investing Cash Flows

Three-month period ended March 31, 2015 compared with three-month period ended March 31, 2014.  Pinnacle West’s consolidated net cash used for investing activities was $233 million in 2015, compared to $208 million in 2014, an increase of $25 million in net cash used primarily related to increased capital expenditures.

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

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2015		2016		2017
APS
Generation:
Nuclear Fuel	$	78	$	87	$	79
Renewables	87		1		2
Environmental	35		181		173
New Gas Generation	60		155		181
Other Generation	184		155		197
Distribution	323		316		439
Transmission	207		101		191
Other (a)	82		68		70
Total APS	$	1,056	$	1,064	$	1,332

(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 and the residential rooftop solar program.  We have not included estimated costs for Cholla’s compliance with MATS or EPA’s regional haze rule since we have challenged the regional haze rule judicially and we have proposed a compromise strategy to EPA, which, if approved, would allow us to avoid expenditures related to environmental control equipment. The portion of estimated costs through 2017 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.  The portion of estimated costs through 2017 for incremental costs to comply with the CCR rule for Four Corners and Cholla have also been included in the table above. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. The table above does not include capital expenditures related to El Paso's 7% interest in Four Corners Units 4 and 5 of $2 million in 2015, $24 million in 2016 and $24 million in 2017. We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

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

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

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Financing Cash Flows and Liquidity

Three-month period ended March 31, 2015 compared with three-month period ended March 31, 2014.  Pinnacle West’s consolidated net cash provided by financing activities was $93 million in 2015, compared to $53 million in 2014, an increase of $40 million in net cash provided.  The increase in net cash provided by financing activities is primarily due to a $41 million net change in short-term borrowings.

Significant Financing Activities.  On April 22, 2015, the Pinnacle West Board of Directors declared a dividend of $0.595 per share of common stock, payable on June 1, 2015 to shareholders of record on May 4, 2015.

On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash used to fund capital expenditures.

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 revolving credit facility matures in May 2019.  At March 31, 2015, 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 size 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, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

At March 31, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million facility that matures in May 2019.  APS may increase the size 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, 2015, APS had $45 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.

See "Financial Assurances" in Note 8 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, 2015, the ratio was approximately 47% for Pinnacle West and 45% 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.

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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 24, 2015 are shown below.  We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt.  The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained.  There is no assurance that these ratings will continue for any given period of time.  The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant.  Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital.  Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts.  At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	Baa1	A-	BBB+
Commercial paper	P-2	A-2	F2
Outlook	Positive	Stable	Positive
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	Positive	Stable	Positive

Off-Balance Sheet Arrangements

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

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Contractual Obligations

There have been no material changes, as of March 31, 2015, outside the normal course of business in contractual obligations from the information provided in our 2014 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

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 2014 Form 10-K.  See "Critical Accounting Policies" in Item 7 of the 2014 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

We are currently evaluating the impacts of adopting two new accounting standards: consolidation analysis guidance that will be adopted on January 1, 2016, and revenue recognition guidance that will be effective for us on January 1, 2017. Guidance has recently been proposed that would provide a one year deferral in the revenue standard's effective date. If this proposed guidance is approved we will adopt the revenue recognition guidance on January 1, 2018. See Note 13.

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 11 and Note 12) 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.

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The following table shows the net pretax changes in mark-to-market of our derivative positions for the three months ended March 31, 2015 and 2014 (dollars in millions):

	Three Months Ended March 31,
	2015			2014
Mark-to-market of net positions at beginning of year	$	(115	)	$	(73	)
Decrease in regulatory asset/liability	(41		)	17
Recognized in OCI:
Mark-to-market losses realized during the period	1			5
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(155	)	$	(51	)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at March 31, 2015 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 2014 Form 10-K and Note 11 for more discussion of our valuation methods.

Source of Fair Value	2015			2016			2017			2018			2019			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(48	)	$	(34	)	$	(20	)	$	(4	)	$	—		$	—		$	(106	)
Prices based on unobservable inputs	(16		)	(13		)	(7		)	(6		)	(5		)	(2		)	(49		)
Total by maturity	$	(64	)	$	(47	)	$	(27	)	$	(10	)	$	(5	)	$	(2	)	$	(155	)

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, 2015 and December 31, 2014 (dollars in millions):

	March 31, 2015 Gain (Loss)					December 31, 2014 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) or OCI (a)
Electricity	$	2	$	(2	)	$	3	$	(3	)
Natural gas	31		(31		)	29		(29		)
Total	$	33	$	(33	)	$	32	$	(32	)

(a) 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.

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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.

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 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, 2015.  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, 2015.  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, 2015 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 2014 Form 10-K with regard to pending or threatened litigation and other disputes.

See Note 3 for ACC and FERC-related matters.

See Note 8 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 2014 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 2014 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 2015.

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, 2015	--	--
February 1 - February 28, 2015	93,280	$65.34
March 1 - March 31, 2015	--	--
Total	93,280	$65.34	--	--

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

68

Item 5.                OTHER INFORMATION

Four Corners Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the Office of Surface Mining Reclamation and Enforcement ("OSM") of the U.S. Department of the Interior challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners ("Area IV North"). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. NTEC, the owner of the mine and supplier of coal to Four Corners, has indicated that it does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. We cannot predict the time period that will be required for OSM’s further permitting process to be completed or whether the outcome of the process will be sufficient to allow the permit to be reinstated.

Union Contract

As previously disclosed in Part I, Item 1 "Business - Other Information" in the 2014 Form 10-K, APS and union representatives from the International Brotherhood of Electrical Workers Local 387 ("IBEW") were engaged in negotiations over the terms of a renewed collective bargaining agreement.  On April 21, 2015, the union membership ratified a three-year contract, which will expire on March 31, 2018.  The contract provides an average wage increase of 2.0% for the first year, 2.25% for the second year and 3.0% for the third year. 

69

Item 6.                EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1*	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	Pinnacle West APS	XBRL Instance Document
101.SCH	Pinnacle West APS	XBRL Taxonomy Extension Schema Document
101.CAL	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Pinnacle West APS	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Pinnacle West APS	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Pinnacle West APS	XBRL Taxonomy Definition Linkbase Document

_________________________________

*Furnished herewith as an Exhibit.

70

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	8/3/2010
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	8/7/2008
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	9/29/1993
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	5/22/2012
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	2/20/2009

_______________________________

(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.

71

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 1, 2015	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 1, 2015	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)

72

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,
	2015		2014		2013		2012		2011		2010
Earnings:
Income from continuing operations attributable to common shareholders	$	16,122	$	397,595	$	406,074	$	387,380	$	328,110	$	324,688
Income taxes	7,947		220,705		230,591		237,317		183,604		160,869
Fixed charges	50,371		208,226		206,089		219,437		246,462		248,664
Total earnings	$	74,440	$	826,526	$	842,754	$	844,134	$	758,176	$	734,221
Fixed Charges:
Interest expense	$	48,399	$	200,950	$	201,888	$	214,616	$	241,995	$	244,174
Estimated interest portion of annual rents	1,972		7,276		4,201		4,821		4,467		4,490
Total fixed charges	$	50,371	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Ratio of Earnings to Fixed Charges (rounded down)	1.47		3.96		4.08		3.84		3.07		2.95

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,
	2015		2014		2013		2012		2011		2010
Earnings:
Income from continuing operations attributable to common shareholders	$	19,868	$	421,219	$	424,969	$	395,497	$	336,249	$	335,663
Income taxes	10,088		237,360		245,095		244,396		192,542		170,465
Fixed charges	49,627		204,198		202,457		214,227		238,286		234,184
Total earnings	$	79,583	$	862,777	$	872,521	$	854,120	$	767,077	$	740,312
Fixed Charges:
Interest charges	$	46,602	$	193,119	$	194,616	$	205,533	$	229,326	$	225,269
Amortization of debt discount	1,134		4,168		4,046		4,215		4,616		4,559
Estimated interest portion of annual rents	1,891		6,911		3,795		4,479		4,344		4,356
Total fixed charges	$	49,627	$	204,198	$	202,457	$	214,227	$	238,286	$	234,184
Ratio of Earnings to Fixed Charges (rounded down)	1.60		4.22		4.30		3.98		3.21		3.16

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,
	2015		2014		2013		2012		2011		2010
Earnings:
Income from continuing operations attributable to common shareholders	$	16,122	$	397,595	$	406,074	$	387,380	$	328,110	$	324,688
Income taxes	7,947		220,705		230,591		237,317		183,604		160,869
Fixed charges	50,371		208,226		206,089		219,437		246,462		248,664
Total earnings	$	74,440	$	826,526	$	842,754	$	844,134	$	758,176	$	734,221
Fixed Charges:
Interest expense	$	48,399	$	200,950	$	201,888	$	214,616	$	241,995	$	244,174
Estimated interest portion of annual rents	1,972		7,276		4,201		4,821		4,467		4,490
Total fixed charges	$	50,371	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	24,069	$	618,300	$	636,665	$	624,697	$	511,714	$	485,557
Net income from continuing operations attributable to common shareholders	16,122		397,595		406,074		387,380		328,110		324,688
Ratio of income before income taxes to net income	1.49		1.56		1.57		1.61		1.56		1.50
Preferred stock dividends	—		—		—		—		—		—
Preferred stock dividend requirements — ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	50,371	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Preferred stock dividend requirements	—		—		—		—		—		—
Total	$	50,371	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Ratio of Earnings to Fixed Charges (rounded down)	1.47		3.96		4.08		3.84		3.07		2.95

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 1, 2015

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James R. Hatfield, certify that:

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

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

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

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

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

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

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

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

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

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

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

Date:    May 1, 2015

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Donald E. Brandt, certify that:

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

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

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

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

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

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

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

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

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

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

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

Date:    May 1, 2015

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

1

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 1, 2015

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

1

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, 2015 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 1, 2015

/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, 2015 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 1, 2015

/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, 2015 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 1, 2015

/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, 2015 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 1, 2015

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

XML

Long-Term Debt and Liquidity Matters Estimated Fair Value of Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Estimated fair value of long-term debt, including current maturities
Debt and Capital Lease Obligations	$ 3,665	$ 3,415
Long-term Debt, Fair Value	4,170	3,839
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Debt and Capital Lease Obligations	125	125
Long-term Debt, Fair Value	125	125
Arizona Public Service Company
Estimated fair value of long-term debt, including current maturities
Debt and Capital Lease Obligations	3,540	3,290
Long-term Debt, Fair Value	$ 4,045	$ 3,714

XML

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) (USD $)	3 Months Ended	0 Months Ended		3 Months Ended
	Mar. 31, 2015 power_plant	Mar. 11, 2015	Aug. 18, 2014	Jun. 30, 2015	Dec. 31, 1986 Trust
Arizona Public Service Company
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 liability 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 premium 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
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment	23,000,000
Collateral assurance provided based on rating triggers	62,000,000
Period to provide collateral assurance based on rating triggers	20 days
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Palo Verde Nuclear Generating Station
Litigation settlement amount		42,000,000	57,400,000
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | Arizona Public Service Company
Palo Verde Nuclear Generating Station
Litigation settlement amount		12,200,000	16,700,000
Regulatory Liability | Forecast | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | Arizona Public Service Company
Palo Verde Nuclear Generating Station
Proceeds from legal settlements				$ 12,200,000

XML

Palo Verde Sale Leaseback Variable Interest Entities Narrative (Details) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Jul. 07, 2014 Lease	Dec. 31, 1986 Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,605,000	$ 8,925,000
Arizona Public Service Company
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts	3			3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	4,605,000	8,925,000
Arizona Public Service Company | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	5,000,000	9,000,000
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events	123,000,000
VIE debt to be assumed upon the occurrence of certain unlikely events	13,000,000
Arizona Public Service Company | Consolidation of VIEs | Through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained			1
Arizona Public Service Company | Consolidation of VIEs | Through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained			2
Arizona Public Service Company | Consolidation of VIEs | 2015
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments	49,000,000
Arizona Public Service Company | Consolidation of VIEs | Period 2016 through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments	23,000,000
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments	$ 16,000,000
Maximum | Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Lease period	2 years

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Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) (Arizona Public Service Company, USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended	0 Months Ended
	Sep. 08, 2011 Customer kV	Mar. 31, 2015	Aug. 06, 2013 Defendant
Superfund-Related Matters
Costs related to investigation and study under Superfund site		$ 2
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
Contaminated groundwater wells
Superfund-Related Matters
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit			24

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Income Taxes (Details) (USD $)	0 Months Ended	3 Months Ended
	Sep. 13, 2013	Mar. 31, 2015
Income Taxes
Increase (decrease) in deferred income taxes due to adoption of regulations	$ 82,000,000
Consolidation of VIEs
Income Taxes
Income tax expense associates with the VIE's		$ 0

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

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, 2015, 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, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	16		$	33		$	(17	)	(b)	$	32
Nuclear decommissioning trust:
U.S. commingled equity funds	—		313			—			—				313
Fixed income securities:
U.S. Treasury	103		—			—			—				103
Cash and cash equivalent funds	—		10			—			(2		)	(c)	8
Corporate debt	—		115			—			—				115
Mortgage-backed securities	—		88			—			—				88
Municipality bonds	—		85			—			—				85
Other	—		15			—			—				15
Subtotal nuclear decommissioning trust	103		626			—			(2		)		727
Total	$	103	$	642		$	33		$	(19	)		$	759
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(122	)	$	(82	)	$	68		(b)	$	(136	)

(a) Primarily consists of heat rate options and other 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.

The following table presents the fair value at December 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 December 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	33		$	(23	)	(b)	$	31
Nuclear decommissioning trust:
U.S. commingled equity funds	—		310			—			—				310
Fixed income securities:
U.S. Treasury	119		—			—			—				119
Cash and cash equivalent funds	—		11			—			(7		)	(c)	4
Corporate debt	—		109			—			—				109
Mortgage-backed securities	—		89			—			—				89
Municipality bonds	—		69			—			—				69
Other	—		14			—			—				14
Subtotal nuclear decommissioning trust	119		602			—			(7		)		714
Total	$	119	$	623		$	33		$	(30	)		$	745
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(95	)	$	(74	)	$	59		(b)	$	(110	)

(a) Primarily consists of heat rate options and other 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

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at March 31, 2015 and December 31, 2014:

	March 31, 2015 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	31	$	60	Discounted cash flows	Electricity forward price (per MWh)	$18.88 - $46.54	$	30.49
Option Contracts (b)	—		15		Option model	Electricity forward price (per MWh)	$30.24 - $60.45	$	41.81
						Natural gas forward price (per MMBtu)	$2.35 - $2.88	$	2.83
						Electricity price volatilities	27% - 86%	54		%
						Natural gas price volatilities	26% - 43%	32		%
Natural Gas:
Forward Contracts (a)	2		7		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.30 - $3.59	$	3.01
Total	$	33	$	82

(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, 2014 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	30	$	56	Discounted cash flows	Electricity forward price (per MWh)	$19.51 - $56.72	$	35.27
Option Contracts (b)	—		15		Option model	Electricity forward price (per MWh)	$32.14 - $66.09	$	45.83
						Natural gas forward price (per MMBtu)	$3.18 - $3.29	$	3.25
						Electricity price volatilities	23% - 63%	41		%
						Natural gas price volatilities	23% - 41%	31		%
Natural Gas:
Forward Contracts (a)	3		3		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.98 - $4.13	$	3.45
Total	$	33	$	74

(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.

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, 2015 and 2014 (dollars in millions):

	Three Months Ended   March 31,
Commodity Contracts	2015			2014
Net derivative balance at beginning of period	$	(41	)	$	(49	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(11		)	4
Settlements	—			—
Transfers into Level 3 from Level 2	(1		)	(3		)
Transfers from Level 3 into Level 2	4			(1		)
Net derivative balance at end of period	$	(49	)	$	(49	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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Other Income and Other Expense (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Other income:
Interest income	$ 110	$ 251
Miscellaneous	125	2,116
Total other income	235	2,367
Other expense:
Non-operating costs	(2,249)	(2,372)
Investment losses — net	(495)	(140)
Miscellaneous	(1,542)	(2,172)
Total other expense	(4,286)	(4,684)
Arizona Public Service Company
Other income:
Interest income	67	138
Miscellaneous	572	2,624
Total other income	639	2,762
Other expense:
Non-operating costs	(2,517)	(2,587)
Asset dispositions	(643)	(183)
Miscellaneous	(2,194)	(2,286)
Total other expense	$ (5,354)	$ (5,056)

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Consolidation and Nature of Operations (Tables)

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of supplemental cash flow information

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

	Three Months Ended   March 31,
	2015		2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$	1,832	$	(131,078	)
Interest, net of amounts capitalized	53,555		49,147
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	56,165	$	24,908

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Derivative Accounting Schedule of Gross Notional Amounts Outstanding (Details)	Mar. 31, 2015 GW
Commodity - Power
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	4,186
Commodity - Gas
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	157,000

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Regulatory Matters- Schedule of Regulatory Assets (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Detail of regulatory assets
Regulatory assets, current	$ 148,000,000	$ 138,000,000
Regulatory assets, non-current	1,067,830,000	1,054,087,000
Pension benefits
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	479,000,000	485,000,000
Income taxes — allowance for funds used during construction (“AFUDC”) equity
Detail of regulatory assets
Regulatory assets, current	5,000,000	5,000,000
Regulatory assets, non-current	117,000,000	118,000,000
Deferred fuel and purchased power — mark-to-market (Note 7)
Detail of regulatory assets
Regulatory assets, current	66,000,000	51,000,000
Regulatory assets, non-current	72,000,000	46,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	2,000,000	5,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	6,000,000	7,000,000
Palo Verde VIEs (Note 6)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	30,000,000	35,000,000
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	36,000,000	34,000,000
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	0	7,000,000
Regulatory assets, non-current	0	0
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	14,000,000	14,000,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	16,000,000	16,000,000
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	46,000,000	46,000,000
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	2,000,000	4,000,000
Regulatory assets, non-current	0	0
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	7,000,000	7,000,000
Regulatory assets, non-current	68,000,000	70,000,000
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	43,000,000	38,000,000
Regulatory assets, non-current	0	0
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	10,000,000	10,000,000
Regulatory assets, non-current	134,000,000	136,000,000
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	36,000,000	30,000,000
Other
Detail of regulatory assets
Regulatory assets, current	1,000,000	2,000,000
Regulatory assets, non-current	12,000,000	12,000,000
Arizona Public Service Company
Detail of regulatory assets
Regulatory assets, non-current	$ 1,067,830,000	$ 1,054,087,000

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Consolidation and Nature of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$ 1,832	$ (131,078)
Interest, net of amounts capitalized	53,555	49,147
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 56,165	$ 24,908

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Derivative Instruments in the Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Commodity Contracts
Assets
Gross Recognized Derivatives	$ 49,449	$ 53,372
Amounts Offset	(17,973)	(22,317)
Net Recognized Derivatives	31,476	31,055
Other	626	350
Amount Reported on Balance Sheet	32,102	31,405
Liabilities
Gross Recognized Derivatives	(203,980)	(169,052)
Amounts Offset	74,873	66,217
Net Recognized Derivatives	(129,107)	(102,835)
Other	(7,023)	(7,443)
Amount Reported on Balance Sheet	(136,130)	(110,278)
Assets and Liabilities
Gross Recognized Derivatives	(154,531)	(115,680)
Amounts Offset	56,900	43,900
Net Recognized Derivatives	(97,631)	(71,780)
Other	(6,397)	(7,093)
Amount Reported on Balance Sheet	(104,028)	(78,873)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	26,414	28,562
Amounts Offset	(13,382)	(15,127)
Net Recognized Derivatives	13,032	13,435
Other	626	350
Amount Reported on Balance Sheet	13,658	13,785
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	23,035	24,810
Amounts Offset	(4,591)	(7,190)
Net Recognized Derivatives	18,444	17,620
Other	0	0
Amount Reported on Balance Sheet	18,444	17,620
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(97,349)	(86,062)
Amounts Offset	42,069	33,829
Net Recognized Derivatives	(55,280)	(52,233)
Other	(7,023)	(7,443)
Amount Reported on Balance Sheet	(62,303)	(59,676)
Assets and Liabilities
Amounts Offset	56,900	43,900
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(106,631)	(82,990)
Amounts Offset	32,804	32,388
Net Recognized Derivatives	(73,827)	(50,602)
Other	0	0
Amount Reported on Balance Sheet	(73,827)	(50,602)
Designated as Hedging Instruments
Liabilities
Gross Recognized Derivatives	$ (4,000)	$ (4,000)

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Fair Value Measurements - Level 3 Rollforward Derivatives (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net derivative beginning balance	$ (41,000,000)	$ (49,000,000)
Deferred as a regulatory asset or liability	(11,000,000)	4,000,000
Settlements	0	0
Transfers into Level 3 from Level 2	(1,000,000)	(3,000,000)
Transfers from Level 3 into Level 2	4,000,000	(1,000,000)
Net derivative ending balance	(49,000,000)	(49,000,000)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0

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Palo Verde Sale Leaseback Variable Interest Entities Schedule of VIEs (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$ 120,287	$ 121,255
Current maturities of long-term debt	383,570	383,570
Equity — Noncontrolling interests	156,214	151,609
Arizona Public Service Company
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	120,287	121,255
Current maturities of long-term debt	383,570	383,570
Equity — Noncontrolling interests	156,214	151,609
Arizona Public Service Company | Consolidation of VIEs
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	120,000	121,000
Current maturities of long-term debt	13,000	13,000
Equity — Noncontrolling interests	$ 156,000	$ 152,000

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Consolidation and Nature of Operations

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation and Nature of Operations

Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, Bright Canyon Energy Corporation ("BCE") 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.

Supplemental Cash Flow Information

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

	Three Months Ended   March 31,
	2015		2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$	1,832	$	(131,078	)
Interest, net of amounts capitalized	53,555		49,147
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	56,165	$	24,908

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Nuclear Decommissioning Trusts (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Nuclear decommissioning trust fund assets
Fair Value	$ 727,342,000		$ 713,866,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities	115,282,000	103,157,000
Fair value of fixed income securities, summarized by contractual maturities
Total	727,342,000		713,866,000
Arizona Public Service Company
Nuclear decommissioning trust fund assets
Fair Value	727,342,000		713,866,000
Unrealized Gains	181,000,000		176,000,000
Unrealized Losses	(1,000,000)		(1,000,000)
Net payables for securities purchases	(2,000,000)		(7,000,000)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	1,000,000	1,000,000
Realized losses	(1,000,000)	(2,000,000)
Proceeds from the sale of securities	115,282,000	103,157,000
Fair value of fixed income securities, summarized by contractual maturities
Total	727,342,000		713,866,000
Arizona Public Service Company | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	313,000,000		310,000,000
Unrealized Gains	161,000,000		159,000,000
Fair value of fixed income securities, summarized by contractual maturities
Total	313,000,000		310,000,000
Arizona Public Service Company | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	416,000,000		411,000,000
Unrealized Gains	20,000,000		17,000,000
Unrealized Losses	(1,000,000)		(1,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	16,000,000
1 year - 5 years	113,000,000
5 years - 10 years	118,000,000
Greater than 10 years	169,000,000
Total	$ 416,000,000		$ 411,000,000

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Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Detail of regulatory liabilities
Regulatory liabilities, current	$ 129,000,000	$ 131,000,000
Regulatory liabilities, non-current	1,070,106,000	1,051,196,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	37,000,000	31,000,000
Regulatory liabilities, non-current	264,000,000	273,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	302,000,000	296,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	25,000,000	25,000,000
Regulatory liabilities, non-current	25,000,000	23,000,000
Income taxes — change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	1,000,000	0
Regulatory liabilities, non-current	71,000,000	72,000,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	5,000,000	5,000,000
Regulatory liabilities, non-current	66,000,000	66,000,000
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,000,000	2,000,000
Regulatory liabilities, non-current	8,000,000	8,000,000
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	3,000,000	4,000,000
Regulatory liabilities, non-current	93,000,000	93,000,000
Deferred fuel and purchased power
Detail of regulatory liabilities
Regulatory liabilities, current	16,000,000	0
Regulatory liabilities, non-current	0	0
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	5,000,000	31,000,000
Regulatory liabilities, non-current	27,000,000	0
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	32,000,000	32,000,000
Regulatory liabilities, non-current	191,000,000	199,000,000
Other
Detail of regulatory liabilities
Regulatory liabilities, current	3,000,000	1,000,000
Regulatory liabilities, non-current	$ 23,000,000	$ 21,000,000

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2015

Variable Interest Entities [Abstract]

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

Our Condensed Consolidated Balance Sheets at March 31, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):

	March 31, 2015		December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	120	$	121
Current maturities of long-term debt	13		13
Equity — Noncontrolling interests	156		152

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Retirement Plans and Other Benefits (Tables)

3 Months Ended

Mar. 31, 2015

Compensation and Retirement Disclosure [Abstract]

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,
	2015			2014			2015			2014
Service cost — benefits earned during the period	$	16		$	15		$	4		$	5
Interest cost on benefit obligation	31			32			7			11
Expected return on plan assets	(45		)	(40		)	(9		)	(12		)
Amortization of:
Prior service cost	—			—			(10		)	—
Net actuarial loss	8			2			2			—
Net periodic benefit cost	$	10		$	9		$	(6	)	$	4
Portion of cost charged to expense	$	6		$	5		$	(2	)	$	3

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Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	May 23, 2013
Arizona Public Service Company | Four Corners Units 4 and 5
Environmental Matters
Percentage of share of cost of control	63.00%
Expected environmental cost	$ 400,000,000
Cholla | Arizona Public Service Company
Environmental Matters
Expected environmental cost	200,000,000
Site contingency increase in loss exposure not accrued, best estimate	85,000,000
Four Corners | New Mexico Tax Matter
Environmental Matters
Coal severance surtax, penalty, and interest		30,000,000
Four Corners | Arizona Public Service Company
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate	15,000,000
Four Corners | Arizona Public Service Company | Four Corners Units 4 and 5
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate	45,000,000
Four Corners | Arizona Public Service Company | New Mexico Tax Matter
Environmental Matters
Share of the assessment		12,000,000
Navajo Plant | Arizona Public Service Company
Environmental Matters
Expected environmental cost	200,000,000
Site contingency increase in loss exposure not accrued, best estimate	1,000,000
Cholla Units 2 And 3 | Arizona Public Service Company
Environmental Matters
Expected environmental cost	130,000,000
Letter of Credit | Arizona Public Service Company
Financial Assurances
Outstanding letters of credit	109,000,000
Equity Lessors in Palo Verde sale leaseback transactions | Arizona Public Service Company
Financial Assurances
Outstanding letters of credit	20,000,000
Natural gas tolling contract obligations | Arizona Public Service Company
Financial Assurances
Outstanding letters of credit	$ 5,000,000
Natural gas tolling contract obligations | Arizona Public Service Company | Four Corners Units 4 and 5
Environmental Matters
Additional percentage share of cost of control	7.00%
Letters of Credit Expiring in 2015 | Arizona Public Service Company
Financial Assurances
Number of letters of credit expiring	1
Letters of Credit Expiring in 2016 | Arizona Public Service Company
Financial Assurances
Number of letters of credit expiring	2

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Retirement Plans and Other Benefits - Narrative (Details) (USD $)	1 Months Ended	3 Months Ended
	Jul. 31, 2012	Mar. 31, 2015	Mar. 31, 2014
Regulatory Assets
Regulatory asset amortization period	3 years
Amortization of regulatory asset		$ 2,000,000	$ 2,000,000
Pension Benefits
Contributions
Voluntary employer contributions to pension plan		60,000,000
Minimum employer contributions for the next three years		0
Maximum employer contributions for the next three years		300,000,000
Other Benefits
Other Postretirement Benefit Plan Remeasurement
Other postretirement plan benefit remeasurement, amount seeking approval to move to separate account to Pay Union employee medical costs		100,000,000
Contributions
2015		1,000,000
2016		100,000,000
2017		100,000,000
Maximum | Pension Benefits
Contributions
2015		100,000,000
2016		100,000,000
2017		$ 100,000,000

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Derivative Accounting (Tables)

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

As of March 31, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	4,186	GWh
Gas	157	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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   March 31,
Commodity Contracts		2015			2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	(327	)	$	177
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(2,343		)	(4,439		)

(a) During the three months ended March 31, 2015 and 2014, 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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   March 31,
Commodity Contracts		2015			2014
Net loss recognized in income	Operating revenues (a)	$	(48	)	$	(92	)
Net gain (loss) recognized in income	Fuel and purchased power (a)	(44,803		)	18,107
Total		$	(44,851	)	$	18,015

(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, 2015: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance  Sheet
Current assets	$	26,414		$	(13,382	)	$	13,032		$	626		$	13,658
Investments and other assets	23,035			(4,591		)	18,444			—			18,444
Total assets	49,449			(17,973		)	31,476			626			32,102
Current liabilities	(97,349		)	42,069			(55,280		)	(7,023		)	(62,303		)
Deferred credits and other	(106,631		)	32,804			(73,827		)	—			(73,827		)
Total liabilities	(203,980		)	74,873			(129,107		)	(7,023		)	(136,130		)
Total	$	(154,531	)	$	56,900		$	(97,631	)	$	(6,397	)	$	(104,028	)

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

(b) Includes cash collateral provided to counterparties of $56,900.

(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 $7,023 and cash margin provided to counterparties of $626.

As of December 31, 2014: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance  Sheet
Current assets	$	28,562		$	(15,127	)	$	13,435		$	350		$	13,785
Investments and other assets	24,810			(7,190		)	17,620			—			17,620
Total assets	53,372			(22,317		)	31,055			350			31,405
Current liabilities	(86,062		)	33,829			(52,233		)	(7,443		)	(59,676		)
Deferred credits and other	(82,990		)	32,388			(50,602		)	—			(50,602		)
Total liabilities	(169,052		)	66,217			(102,835		)	(7,443		)	(110,278		)
Total	$	(115,680	)	$	43,900		$	(71,780	)	$	(7,093	)	$	(78,873	)

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

(b) Includes cash collateral provided to counterparties of $43,900.

(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 $7,443, and cash margin provided to counterparties of $350.

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, 2015 (dollars in millions):

	March 31, 2015
Aggregate fair value of derivative instruments in a net liability position	$	204
Cash collateral posted	57
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	104

(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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Other Income and Other Expense (Tables)

3 Months Ended

Mar. 31, 2015

Component of Other Income and Other Expense Nonoperating [Line Items]

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, 2015 and 2014 (dollars in thousands):

	Three Months Ended   March 31,
	2015			2014
Other income:
Interest income	$	110		$	251
Miscellaneous	125			2,116
Total other income	$	235		$	2,367
Other expense:
Non-operating costs	$	(2,249	)	$	(2,372	)
Investment losses — net	(495		)	(140		)
Miscellaneous	(1,542		)	(2,172		)
Total other expense	$	(4,286	)	$	(4,684	)

Arizona Public Service Company

Component of Other Income and Other Expense Nonoperating [Line Items]

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, 2015 and 2014 (dollars in thousands):

	Three Months Ended   March 31,
	2015			2014
Other income:
Interest income	$	67		$	138
Miscellaneous	572			2,624
Total other income	$	639		$	2,762
Other expense:
Non-operating costs (a)	$	(2,517	)	$	(2,587	)
Asset dispositions	(643		)	(183		)
Miscellaneous	(2,194		)	(2,286		)
Total other expense	$	(5,354	)	$	(5,056	)

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

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) Statement (USD $) In Thousands, except Share data, unless otherwise specified		Total	Common Stock	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	Arizona Public Service Company	Arizona Public Service Company Common Stock	Arizona Public Service Company Additional Paid-in Capital	Arizona Public Service Company Retained Earnings	Arizona Public Service Company Accumulated Other Comprehensive Income (Loss)	Arizona Public Service Company Noncontrolling Interests
Beginning balance at Dec. 31, 2013		$ 4,340,460	$ 2,491,558	$ (4,308)	$ 1,785,273	$ (78,053)	$ 145,990	$ 4,454,874	$ 178,162	$ 2,379,696	$ 1,804,398	$ (53,372)	$ 145,990
Beginning balance (in shares) at Dec. 31, 2013			110,280,703	98,944					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		24,691			15,766		8,925	28,443			19,518		8,925
Other comprehensive income		3,151				3,151		3,261				3,261
Issuance of common stock (in shares)			108,362
Issuance of common stock		5,927	5,927
Purchase of treasury stock (in shares)	[1]			(82,474)
Purchase of treasury stock	[1]	(4,535)		(4,535)
Stock-based compensation and other (in shares)				146,590
Stock-based compensation and other		8,007		7,999	8
Other								(2)			(2)
Ending balance at Mar. 31, 2014		4,377,701	2,497,485	(844)	1,801,047	(74,902)	154,915	4,486,576	178,162	2,379,696	1,823,914	(50,111)	154,915
Ending balance (in shares) at Mar. 31, 2014			110,389,065	34,828					71,264,947
Beginning balance at Dec. 31, 2014		4,519,102	2,512,970	(3,401)	1,926,065	(68,141)	151,609	4,629,852	178,162	2,379,696	1,968,718	(48,333)	151,609
Beginning balance (in shares) at Dec. 31, 2014		110,649,762	110,649,762	78,400					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		20,727			16,122		4,605	24,473			19,868		4,605
Other comprehensive income		1,759				1,759		1,857				1,857
Issuance of common stock (in shares)			159,730
Issuance of common stock		10,277	10,277
Purchase of treasury stock (in shares)	[1]			(93,280)
Purchase of treasury stock	[1]	(6,095)		(6,095)
Stock-based compensation and other (in shares)				109,896
Stock-based compensation and other		7,237		7,230	7
Other								1			1
Ending balance at Mar. 31, 2015		$ 4,553,007	$ 2,523,247	$ (2,266)	$ 1,942,194	$ (66,382)	$ 156,214	$ 4,656,183	$ 178,162	$ 2,379,696	$ 1,988,587	$ (46,476)	$ 156,214
Ending balance (in shares) at Mar. 31, 2015		110,809,492	110,809,492	61,784					71,264,947

[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]

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 for the three months ended March 31, 2015 and 2014 (in thousands, except per share amounts):

	Three Months Ended   March 31,
	2015		2014
Net income attributable to common shareholders	$	16,122	$	15,766
Weighted average common shares outstanding — basic	110,916		110,257
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	461		631
Weighted average common shares outstanding — diluted	111,377		110,888
Earnings per average common share attributable to common shareholders — basic	$	0.15	$	0.14
Earnings per average common share attributable to common shareholders — diluted	$	0.14	$	0.14

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Regulatory Matters (Details) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Jan. 01, 2014	Jan. 06, 2012	Jun. 01, 2011	Jan. 15, 2015	Jan. 15, 2014	Feb. 12, 2013	Feb. 01, 2015	Feb. 01, 2014	Jun. 01, 2014	Apr. 02, 2015	Apr. 15, 2014 Customer MW	Dec. 31, 2012	Jun. 01, 2012	Dec. 31, 2014	Jul. 01, 2014	Jul. 12, 2013
Change in regulatory asset
Deferred fuel and purchased power costs-current period	$ 17,671,000	$ 31,630,000
Amounts charged to customers	5,614,000	8,022,000
APS
Change in regulatory asset
Deferred fuel and purchased power costs-current period	17,671,000	31,630,000
Amounts charged to customers	5,614,000	8,022,000
APS | Lost Fixed Cost Recovery Mechanism
Change in regulatory asset
Percentage of retail revenues	1.00%
APS | ACC | Net Metering
Change in regulatory asset
Charge on future customers who install rooftop solar panels (in dollars per kWh)	0.70		0.70
Estimated monthly collection due to charge on future customers who install rooftop solar panels			4.90
Filing with the Arizona Corporation Commission | APS | ACC | Retail rate case filing
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%
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
Filing with the Arizona Corporation Commission | APS | ACC | Retail rate case filing | Maximum
Settlement Agreement
Annual cost recovery due to modifications to the Environmental Improvement Surcharge				5,000,000
Cost Recovery Mechanisms | APS | 2013 DSMAC
Settlement Agreement
Amount of proposed budget														87,600,000
Amount of approved budget	68,900,000
Cost Recovery Mechanisms | APS | 2014 DSMAC
Settlement Agreement
Amount of approved budget	68,900,000
Cost Recovery Mechanisms | APS | 2015 DSMAC
Settlement Agreement
Amount of proposed budget	68,900,000
Cost Recovery Mechanisms | APS | Lost Fixed Cost Recovery Mechanism
Change in regulatory asset
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						38,500,000	25,300,000	5,100,000
Cost Recovery Mechanisms | APS | ACC | RES
Settlement Agreement
Plan term	5 years
Cost Recovery Mechanisms | APS | ACC | 2013 DSMAC
Settlement Agreement
Percentage of cumulative energy savings for current year															5.00%
Cost Recovery Mechanisms | APS | ACC | RES implementation plan covering 2014-2018 timeframe
Settlement Agreement
Amount of proposed budget																	154,000,000	143,000,000
Amount of approved budget																152,000,000
Cost Recovery Mechanisms | APS | ACC | Power Supply Adjustor (PSA)
Change in regulatory asset
Beginning balance	7,000,000	21,000,000	21,000,000
Deferred fuel and purchased power costs-current period	(18,000,000)	(32,000,000)
Amounts charged to customers	(5,000,000)	(8,000,000)
Ending balance	(16,000,000)	(19,000,000)
PSA rate (in dollars per kWh)									0.000887
PSA rate for prior year (in dollars per kWh)										0.001557
Forward component of increase in PSA (in dollars per kWh)									0.001131
Historical component of increase in PSA (in dollars per kWh)									(0.000244)
Cost Recovery Mechanisms | APS | FERC | Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters
Change in regulatory asset
Increase in annual wholesale transmission rates											5,900,000
Subsequent Event | APS | ACC | Net Metering
Change in regulatory asset
Charge on future customers who install rooftop solar panels (in dollars per kWh)												0.70
Proposed fixed grid access charge on new residential solar customers (in dollars per KWh)												3.00
Estimated monthly collection due to charge on new residential solar customers												$ 21
AZ Sun Program | Filing with the Arizona Corporation Commission | APS | 2014 RES
Settlement Agreement
Request to build additional utility scale solar, capacity													20
Alternative to AZ Sun Program | Filing with the Arizona Corporation Commission | APS | 2014 RES
Settlement Agreement
Request to build additional utility scale solar, capacity													10
Additional capacity from APS-owned non AZ Sun projects, impacted customers													1,500
Alternative to AZ Sun Program, Phase 1 | Filing with the Arizona Corporation Commission | APS | 2014 RES
Settlement Agreement
Request to build additional utility scale solar, capacity													8
Alternative to AZ Sun Program Phase 2 | Filing with the Arizona Corporation Commission | APS | 2014 RES
Settlement Agreement
Request to build additional utility scale solar, capacity													2

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Credit Risk and Credit Related Contingent Features (Details) (Commodity Contracts, USD $) In Millions, unless otherwise specified	Mar. 31, 2015
Commodity Contracts
Credit Risk and Credit-Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	$ 204
Cash collateral posted	57
Additional cash collateral in the event credit-risk-related contingent features were fully triggered	$ 104

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
OPERATING REVENUES	$ 671,219	$ 686,251
OPERATING EXPENSES
Fuel and purchased power	223,237	249,786
Operations and maintenance	214,944	212,882
Depreciation and amortization	120,949	101,772
Taxes other than income taxes	43,216	45,845
Other expenses	1,189	796
Total	603,535	611,081
OPERATING INCOME	67,684	75,170
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	9,224	7,442
Other income	235	2,367
Other expense	(4,286)	(4,684)
Total	5,173	5,125
INTEREST EXPENSE
Interest charges	48,399	52,969
Allowance for borrowed funds used during construction	(4,216)	(3,770)
Total	44,183	49,199
INCOME BEFORE INCOME TAXES	28,674	31,096
INCOME TAXES	7,947	6,405
NET INCOME	20,727	24,691
Less: Net income attributable to noncontrolling interests (Note 6)	4,605	8,925
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	16,122	15,766
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	110,916	110,257
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	111,377	110,888
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.15	$ 0.14
Net income attributable to common shareholders - diluted (in dollars per share)	$ 0.14	$ 0.14
Arizona Public Service Company
ELECTRIC OPERATING REVENUES	670,668	685,545
OPERATING EXPENSES
Fuel and purchased power	223,237	249,786
Operations and maintenance	209,947	208,285
Depreciation and amortization	120,926	101,748
Income taxes	12,239	10,478
Taxes other than income taxes	42,986	45,613
Total	609,335	615,910
OPERATING INCOME	61,333	69,635
OTHER INCOME (DEDUCTIONS)
Income taxes	2,151	1,210
Allowance for equity funds used during construction	9,224	7,442
Other income	639	2,762
Other expense	(5,354)	(5,056)
Total	6,660	6,358
INTEREST EXPENSE
Interest on long-term debt	45,428	48,896
Interest on short-term borrowings	1,174	1,413
Debt discount, premium and expense	1,134	1,011
Allowance for borrowed funds used during construction	(4,216)	(3,770)
Total	43,520	47,550
NET INCOME	24,473	28,443
Less: Net income attributable to noncontrolling interests (Note 6)	4,605	8,925
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 19,868	$ 19,518

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Retirement Plans and Other Benefits - Schedule of Net Benefit Cost (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Pension Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	$ 16	$ 15
Interest cost on benefit obligation	31	32
Expected return on plan assets	(45)	(40)
Amortization of:
Prior service cost	0	0
Net actuarial loss	8	2
Net periodic benefit cost	10	9
Portion of cost charged to expense	6	5
Other postretirement benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	4	5
Interest cost on benefit obligation	7	11
Expected return on plan assets	(9)	(12)
Amortization of:
Prior service cost	(10)	0
Net actuarial loss	2	0
Net periodic benefit cost	(6)	4
Portion of cost charged to expense	$ (2)	$ 3

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common stock, par value (in dollars per share)
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	110,809,492	110,649,762
Treasury stock at cost, shares	61,784	78,400

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Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Assets
Nuclear decommissioning trust	$ 727,342,000	$ 713,866,000
Total assets	33,000,000	33,000,000
Recurring
Assets
Derivative instruments, other	(17,000,000)	(23,000,000)
Derivative assets	32,000,000	31,000,000
Nuclear decommissioning trust, other	(2,000,000)	(7,000,000)
Nuclear decommissioning trust	727,000,000	714,000,000
Total, other	(19,000,000)	(30,000,000)
Total assets	759,000,000	745,000,000
Liabilities
Derivative instruments, other	68,000,000	59,000,000
Derivative liability	(136,000,000)	(110,000,000)
Recurring | US commingled equity funds
Assets
Nuclear decommissioning trust	313,000,000	310,000,000
Recurring | U.S. Treasury
Assets
Nuclear decommissioning trust	103,000,000	119,000,000
Recurring | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust, other	(2,000,000)	(7,000,000)
Nuclear decommissioning trust	8,000,000	4,000,000
Recurring | Corporate debt
Assets
Nuclear decommissioning trust	115,000,000	109,000,000
Recurring | Mortgage-backed securities
Assets
Nuclear decommissioning trust	88,000,000	89,000,000
Recurring | Municipality bonds
Assets
Nuclear decommissioning trust	85,000,000	69,000,000
Recurring | Other
Assets
Nuclear decommissioning trust	15,000,000	14,000,000
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Decommissioning fund investments, gross fair value	103,000,000	119,000,000
Gross assets, fair value disclosure	103,000,000	119,000,000
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	103,000,000	119,000,000
Recurring | Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	16,000,000	21,000,000
Decommissioning fund investments, gross fair value	626,000,000	602,000,000
Gross assets, fair value disclosure	642,000,000	623,000,000
Liabilities
Gross derivative liability	(122,000,000)	(95,000,000)
Recurring | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Decommissioning fund investments, gross fair value	313,000,000	310,000,000
Recurring | Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds
Assets
Decommissioning fund investments, gross fair value	10,000,000	11,000,000
Recurring | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Decommissioning fund investments, gross fair value	115,000,000	109,000,000
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	88,000,000	89,000,000
Recurring | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Decommissioning fund investments, gross fair value	85,000,000	69,000,000
Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets
Decommissioning fund investments, gross fair value	15,000,000	14,000,000
Recurring | Significant Unobservable Inputs (Level 3)
Assets
Gross derivative assets	33,000,000	33,000,000
Gross assets, fair value disclosure	33,000,000	33,000,000
Liabilities
Gross derivative liability	$ (82,000,000)	$ (74,000,000)

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Changes in Accumulated Other Comprehensive Loss (Tables)

3 Months Ended

Mar. 31, 2015

Accumulated Other Comprehensive Income (Loss) [Line Items]

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

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(57,756	)		$	(68,141	)	$	(23,058	)		$	(54,995	)		$	(78,053	)
OCI (loss) before reclassifications	(800		)		—				(800		)	(422		)		—				(422		)
Amounts reclassified from accumulated other comprehensive loss	1,976			(a)	583			(b)	2,559			3,116			(a)	457			(b)	3,573
Net current period OCI	1,176				583				1,759			2,694				457				3,151
Ending balance, March 31,	$	(9,209	)		$	(57,173	)		$	(66,382	)	$	(20,364	)		$	(54,538	)		$	(74,902	)

(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

Accumulated Other Comprehensive Income (Loss) [Line Items]

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

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(37,948	)		$	(48,333	)	$	(23,059	)		$	(30,313	)		$	(53,372	)
OCI (loss) before reclassifications	(800		)		—				(800		)	(421		)		—				(421		)
Amounts reclassified from accumulated other comprehensive loss	1,976			(a)	681			(b)	2,657			3,116			(a)	566			(b)	3,682
Net current period OCI	1,176				681				1,857			2,695				566				3,261
Ending balance, March 31,	$	(9,209	)		$	(37,267	)		$	(46,476	)	$	(20,364	)		$	(29,747	)		$	(50,111	)

(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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Asset Retirement Obligations Roll-Forward (Details) (Arizona Public Service Company, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Arizona Public Service Company
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	$ 391
Changes attributable to:
Accretion expense	6
Settlements	(7)
Estimated cash flow revisions	18
Asset retirement obligations at the end of year	$ 408

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Changes in Accumulated Other Comprehensive Loss

3 Months Ended

Mar. 31, 2015

Accumulated Other Comprehensive Income (Loss) [Line Items]

Changes in Accumulated Other Comprehensive Loss

Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(57,756	)		$	(68,141	)	$	(23,058	)		$	(54,995	)		$	(78,053	)
OCI (loss) before reclassifications	(800		)		—				(800		)	(422		)		—				(422		)
Amounts reclassified from accumulated other comprehensive loss	1,976			(a)	583			(b)	2,559			3,116			(a)	457			(b)	3,573
Net current period OCI	1,176				583				1,759			2,694				457				3,151
Ending balance, March 31,	$	(9,209	)		$	(57,173	)		$	(66,382	)	$	(20,364	)		$	(54,538	)		$	(74,902	)

(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

Accumulated Other Comprehensive Income (Loss) [Line Items]

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(37,948	)		$	(48,333	)	$	(23,059	)		$	(30,313	)		$	(53,372	)
OCI (loss) before reclassifications	(800		)		—				(800		)	(421		)		—				(421		)
Amounts reclassified from accumulated other comprehensive loss	1,976			(a)	681			(b)	2,657			3,116			(a)	566			(b)	3,682
Net current period OCI	1,176				681				1,857			2,695				566				3,261
Ending balance, March 31,	$	(9,209	)		$	(37,267	)		$	(46,476	)	$	(20,364	)		$	(29,747	)		$	(50,111	)

(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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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Change in asset retirement obligations

The following schedule shows the change in our asset retirement obligations for the three months ended March 31, 2015 (dollars in millions): 

Asset retirement obligations at January 1, 2015	$	391
Changes attributable to:
Accretion expense	6
Settlements	(7		)
Estimated cash flow revisions	18
Asset retirement obligations at March 31, 2015	$	408

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New Accounting Standards (Policies)

3 Months Ended

Mar. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The guidance may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. As originally issued, the new revenue standard would be effective for us on January 1, 2017; however, the FASB has recently proposed a one year deferral of the effective date, which if finalized will result in the new guidance being effective for us on January 1, 2018. We are currently evaluating this new guidance and the impacts it may have on our financial statements.

In February 2015, new guidance was issued that amends the consolidation accounting guidance. The amendments modify many aspects of the guidance relating to the analysis and consolidation of variable interest entities. These changes include impacts on the following: limited partnerships, fees paid to decision makers, related parties, and the determination of whether an entity qualifies as a variable interest entity. The new guidance is effective for us on January 1, 2016, and may be adopted using either a full retrospective or modified retrospective approach. We are currently evaluating this amended guidance and the impacts it may have on our financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 20,727	$ 24,691
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	141,494	122,394
Deferred fuel and purchased power	17,671	31,630
Deferred fuel and purchased power amortization	5,614	8,022
Allowance for equity funds used during construction	(9,224)	(7,442)
Deferred income taxes	6,978	8,810
Deferred investment tax credit	(294)	(247)
Change in derivative instruments fair value	(104)	(13)
Changes in current assets and liabilities:
Customer and other receivables	39,174	25,986
Accrued unbilled revenues	6,133	7,889
Materials, supplies and fossil fuel	(9,995)	(187)
Income tax receivable	(219)	130,870
Other current assets	(9,631)	(10,669)
Accounts payable	(35,673)	(50,990)
Accrued taxes	48,111	48,139
Other current liabilities	(56,747)	(15,864)
Change in margin and collateral accounts — assets	(276)	(290)
Change in margin and collateral accounts — liabilities	(13,420)	(29,075)
Change in other long-term assets	(14,432)	(9,636)
Change in other long-term liabilities	8,261	(34,861)
Net cash flow provided by operating activities	144,148	249,157
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(251,041)	(207,459)
Contributions in aid of construction	27,222	7,736
Allowance for borrowed funds used during construction	(4,216)	(3,770)
Proceeds from nuclear decommissioning trust sales	115,282	103,157
Investment in nuclear decommissioning trust	(119,594)	(107,470)
Other	(470)	(702)
Net cash flow used for investing activities	(232,817)	(208,508)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000	250,000
Short-term borrowings and payments — net	(102,900)	(143,625)
Dividends paid on common stock	(64,061)	(62,520)
Dividends paid on common stock	9,690	9,390
Other	0	1
Net cash flow provided by financing activities	92,729	53,246
NET INCREASE IN CASH AND CASH EQUIVALENTS	4,060	93,895
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	7,604	9,526
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11,664	103,421
Cash paid (received) during the period for:
Income taxes, net of refunds	1,832	(131,078)
Interest, net of amounts capitalized	53,555	49,147
Significant non-cash investing and financing activities:
Accrued capital expenditures	56,165	24,908
Arizona Public Service Company
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	24,473	28,443
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	141,471	122,370
Deferred fuel and purchased power	17,671	31,630
Deferred fuel and purchased power amortization	5,614	8,022
Allowance for equity funds used during construction	(9,224)	(7,442)
Deferred income taxes	2,427	8,696
Deferred investment tax credit	(294)	(247)
Change in derivative instruments fair value	(104)	(13)
Changes in current assets and liabilities:
Customer and other receivables	43,070	25,749
Accrued unbilled revenues	6,133	7,889
Materials, supplies and fossil fuel	(9,995)	(187)
Income tax receivable	0	134,890
Other current assets	(9,116)	(10,807)
Accounts payable	(35,604)	(52,621)
Accrued taxes	59,057	50,580
Other current liabilities	(65,290)	(5,257)
Change in margin and collateral accounts — assets	(276)	(290)
Change in margin and collateral accounts — liabilities	(13,421)	(29,075)
Change in other long-term assets	(17,559)	(10,439)
Change in other long-term liabilities	13,941	(28,083)
Net cash flow provided by operating activities	152,974	273,808
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(250,930)	(207,459)
Contributions in aid of construction	27,222	7,736
Allowance for borrowed funds used during construction	(4,216)	(3,770)
Proceeds from nuclear decommissioning trust sales	115,282	103,157
Investment in nuclear decommissioning trust	(119,594)	(107,470)
Other	(470)	(702)
Net cash flow used for investing activities	(232,706)	(208,508)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	250,000	250,000
Short-term borrowings and payments — net	(102,900)	(153,125)
Dividends paid on common stock	(65,800)	(62,500)
Net cash flow provided by financing activities	81,300	34,375
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,568	99,675
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	4,515	3,725
CASH AND CASH EQUIVALENTS AT END OF PERIOD	6,083	103,400
Cash paid (received) during the period for:
Income taxes, net of refunds	184	(134,323)
Interest, net of amounts capitalized	52,825	47,464
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 56,165	$ 24,908

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
NET INCOME	$ 20,727	$ 24,691
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	(800)	(422)
Reclassification of net realized loss, net of tax benefit	1,976	3,116
Pension and other postretirement benefits activity, net of tax benefit (expense)	583	457
Total other comprehensive income	1,759	3,151
COMPREHENSIVE INCOME	22,486	27,842
Less: Comprehensive income attributable to noncontrolling interests	4,605	8,925
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	17,881	18,917
Arizona Public Service Company
NET INCOME	24,473	28,443
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	(800)	(421)
Reclassification of net realized loss, net of tax benefit	1,976	3,116
Pension and other postretirement benefits activity, net of tax benefit (expense)	681	566
Total other comprehensive income	1,857	3,261
COMPREHENSIVE INCOME	26,330	31,704
Less: Comprehensive income attributable to noncontrolling interests	4,605	8,925
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 21,725	$ 22,779

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Other Income and Other Expense

3 Months Ended

Mar. 31, 2015

Component of Other Income and Other Expense Nonoperating [Line Items]

Other Income and Other Expense

ome and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2015 and 2014 (dollars in thousands):

	Three Months Ended   March 31,
	2015			2014
Other income:
Interest income	$	110		$	251
Miscellaneous	125			2,116
Total other income	$	235		$	2,367
Other expense:
Non-operating costs	$	(2,249	)	$	(2,372	)
Investment losses — net	(495		)	(140		)
Miscellaneous	(1,542		)	(2,172		)
Total other expense	$	(4,286	)	$	(4,684	)

Arizona Public Service Company

Component of Other Income and Other Expense Nonoperating [Line Items]

Other Income and Other Expense

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, 2015 and 2014 (dollars in thousands):

	Three Months Ended   March 31,
	2015			2014
Other income:
Interest income	$	67		$	138
Miscellaneous	572			2,624
Total other income	$	639		$	2,762
Other expense:
Non-operating costs (a)	$	(2,517	)	$	(2,587	)
Asset dispositions	(643		)	(183		)
Miscellaneous	(2,194		)	(2,286		)
Total other expense	$	(5,354	)	$	(5,056	)

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

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Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 24, 2015
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	0000764622
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
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		110,748,842
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Arizona Public Service Company
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	0000007286
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		71,264,947
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

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Earnings Per Share

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three months ended March 31, 2015 and 2014 (in thousands, except per share amounts):

	Three Months Ended   March 31,
	2015		2014
Net income attributable to common shareholders	$	16,122	$	15,766
Weighted average common shares outstanding — basic	110,916		110,257
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	461		631
Weighted average common shares outstanding — diluted	111,377		110,888
Earnings per average common share attributable to common shareholders — basic	$	0.15	$	0.14
Earnings per average common share attributable to common shareholders — diluted	$	0.14	$	0.14

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Net unrealized gain (loss), tax benefit (expense)	$ (473)	$ (599)
Reclassification of net realized loss, tax benefit	367	1,323
Pension and other postretirement benefits activity, tax benefit (expense)	(867)	(718)
Arizona Public Service Company
Net unrealized gain (loss), tax benefit (expense)	(473)	(599)
Reclassification of net realized loss, tax benefit	367	1,323
Pension and other postretirement benefits activity, tax benefit (expense)	$ (769)	$ (606)

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Retirement Plans and Other Benefits

3 Months Ended

Mar. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Retirement Plans and Other Benefits

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 an other postretirement benefit plan 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 dates. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of these plan changes in 2014, the Company is currently in the process of seeking IRS and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new account to pay for active union employee medical costs.

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, 2015 and 2014, 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,
	2015			2014			2015			2014
Service cost — benefits earned during the period	$	16		$	15		$	4		$	5
Interest cost on benefit obligation	31			32			7			11
Expected return on plan assets	(45		)	(40		)	(9		)	(12		)
Amortization of:
Prior service cost	—			—			(10		)	—
Net actuarial loss	8			2			2			—
Net periodic benefit cost	$	10		$	9		$	(6	)	$	4
Portion of cost charged to expense	$	6		$	5		$	(2	)	$	3

Contributions

We have made voluntary contributions of $60 million to our pension plan in 2015. The minimum contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

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Regulatory Matters

3 Months Ended

Mar. 31, 2015

Regulated Operations [Abstract]

Regulatory Matters

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 the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);

• Implementation of a Lost Fixed Cost Recovery ("LFCR") 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 September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules are expected to become effective in the second quarter of 2015.

In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.

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 required 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.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system.

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.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rule making has not been initiated and there has been no additional action on the draft to date.

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 2015 and 2014 (dollars in millions):

	Three Months Ended   March 31,
	2015			2014
Beginning balance	$	7		$	21
Deferred fuel and purchased power costs — current period	(18		)	(32		)
Amounts charged to customers	(5		)	(8		)
Ending balance	$	(16	)	$	(19	)

The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh.  Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the United States Federal Energy Regulatory Commission ("FERC") approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement, 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, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 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, 2014.

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 LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  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. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March.

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 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.  A series of workshops in this docket were held in 2014 and early 2015.

Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address 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. 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 fixed charge does not increase APS's revenue because it is credited to the LFCR.

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.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. 

On April 2, 2015, APS filed an application with the ACC seeking to increase the fixed grid access charge to $3.00 per kilowatt, or approximately $21 per month for a typical new residential solar customer, effective August 1. Customers who installed rooftop solar panels prior to January 1, 2014 would continue to be grandfathered and would not pay a grid access charge, and those who installed panels between January 1, 2014 and the effective date of the requested change would continue paying a charge of $0.70 per kilowatt. Solar customers that take electric service under APS’s demand-based ECT-2 residential rate, an existing rate that includes time-of-use rates with a demand charge, are not subject to the grid access charge.

APS cannot predict the outcome of this filing. The proposed grid access charge adjustment is designed to moderate the cost shift discussed above on an interim basis until the issue is further addressed in APS’s next general rate case or another proceeding.

On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.

Four Corners

On December 30, 2013, APS purchased Southern California Edison Company's ("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. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs 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 through its inclusion in rates.  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 $75 million as of March 31, 2015 and is being amortized in rates over 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS intends to intervene and actively participate in the proceeding. We cannot predict when or how this appeal will be resolved.

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.  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 are 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.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Cholla

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Unit 2 of the Cholla Power Plant ("Cholla") by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. On April 14, 2015, the ACC approved APS's proposed retirement of Cholla Unit 2 in accordance with the ACC's Integrated Resource Planning rules. The ACC expressly stated that this approval does not imply any specific treatment or recommendation for rate making purposes.

If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($127 million as of March 31, 2015), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

Regulatory Assets and Liabilities

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

	Remaining Amortization Period	March 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Pension benefits	(a)	$	—	$	479	$	—	$	485
Income taxes — allowance for funds used during construction ("AFUDC") equity	2044	5		117		5		118
Deferred fuel and purchased power — mark-to-market (Note 7)	2018	66		72		51		46
Transmission vegetation management	2016	9		2		9		5
Coal reclamation	2026	—		6		—		7
Palo Verde VIEs (Note 6)	2046	—		30		—		35
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		7		—
Tax expense of Medicare subsidy	2024	2		14		2		14
Loss on reacquired debt	2034	1		16		1		16
Income taxes — investment tax credit basis adjustment	2044	2		46		2		46
Pension and other postretirement benefits deferral	2015	2		—		4		—
Four Corners cost deferral	2024	7		68		7		70
Lost fixed cost recovery (b)	2016	43		—		38		—
Retired power plant costs	2033	10		134		10		136
Deferred property taxes	(d)	—		36		—		30
Other	Various	1		12		2		12
Total regulatory assets (e)		$	148	$	1,068	$	138	$	1,054

(a) This asset represents the future recovery of 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) Per the provision of the 2012 Settlement Agreement.

(e) 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, Transmission Cost Adjustor and Other Transmission Matters."

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

	Remaining Amortization Period	March 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	37	$	264	$	31	$	273
Asset retirement obligations	2044	—		302		—		296
Renewable energy standard (b)	2017	25		25		25		23
Income taxes — change in rates	2043	1		71		—		72
Spent nuclear fuel	2047	5		66		5		66
Deferred gains on utility property	2019	2		8		2		8
Income taxes — deferred investment tax credit	2043	3		93		4		93
Deferred fuel and purchased power (b) (c)	2016	16		—		—		—
Demand side management (b)	2017	5		27		31		—
Other postretirement benefits	(d)	32		191		32		199
Other	Various	3		23		1		21
Total regulatory liabilities		$	129	$	1,070	$	131	$	1,051

(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 a carrying charge.

(d) See Note 4.

XML

Asset Retirement Obligations

3 Months Ended

Mar. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

In the first quarter of 2015, an updated decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the ARO in the amount of $18 million. The following schedule shows the change in our asset retirement obligations for the three months ended March 31, 2015 (dollars in millions): 

Asset retirement obligations at January 1, 2015	$	391
Changes attributable to:
Accretion expense	6
Settlements	(7		)
Estimated cash flow revisions	18
Asset retirement obligations at March 31, 2015	$	408

Decommissioning activities for Four Corners Units 1-3 began in January 2014; thus, $29 million of the total asset retirement obligation of $408 million at March 31, 2015, is classified as a current liability on the balance sheet.

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 3.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

ue 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 that are redeemable and valued based on NAV, such as common and collective trusts and commingled funds.

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 7 in the 2014 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, characteristics of the product, 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 Trust

The nuclear decommissioning trust invests in fixed income securities and equity securities.  Equity securities are held indirectly through commingled funds.  The commingled funds are valued based on the concept of Net Asset Value ("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 12 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at March 31, 2015, 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, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	16		$	33		$	(17	)	(b)	$	32
Nuclear decommissioning trust:
U.S. commingled equity funds	—		313			—			—				313
Fixed income securities:
U.S. Treasury	103		—			—			—				103
Cash and cash equivalent funds	—		10			—			(2		)	(c)	8
Corporate debt	—		115			—			—				115
Mortgage-backed securities	—		88			—			—				88
Municipality bonds	—		85			—			—				85
Other	—		15			—			—				15
Subtotal nuclear decommissioning trust	103		626			—			(2		)		727
Total	$	103	$	642		$	33		$	(19	)		$	759
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(122	)	$	(82	)	$	68		(b)	$	(136	)

(a) Primarily consists of heat rate options and other 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.

The following table presents the fair value at December 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 December 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	33		$	(23	)	(b)	$	31
Nuclear decommissioning trust:
U.S. commingled equity funds	—		310			—			—				310
Fixed income securities:
U.S. Treasury	119		—			—			—				119
Cash and cash equivalent funds	—		11			—			(7		)	(c)	4
Corporate debt	—		109			—			—				109
Mortgage-backed securities	—		89			—			—				89
Municipality bonds	—		69			—			—				69
Other	—		14			—			—				14
Subtotal nuclear decommissioning trust	119		602			—			(7		)		714
Total	$	119	$	623		$	33		$	(30	)		$	745
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(95	)	$	(74	)	$	59		(b)	$	(110	)

(a) Primarily consists of heat rate options and other 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, 2015 and December 31, 2014:

	March 31, 2015 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	31	$	60	Discounted cash flows	Electricity forward price (per MWh)	$18.88 - $46.54	$	30.49
Option Contracts (b)	—		15		Option model	Electricity forward price (per MWh)	$30.24 - $60.45	$	41.81
						Natural gas forward price (per MMBtu)	$2.35 - $2.88	$	2.83
						Electricity price volatilities	27% - 86%	54		%
						Natural gas price volatilities	26% - 43%	32		%
Natural Gas:
Forward Contracts (a)	2		7		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.30 - $3.59	$	3.01
Total	$	33	$	82

(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, 2014 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	30	$	56	Discounted cash flows	Electricity forward price (per MWh)	$19.51 - $56.72	$	35.27
Option Contracts (b)	—		15		Option model	Electricity forward price (per MWh)	$32.14 - $66.09	$	45.83
						Natural gas forward price (per MMBtu)	$3.18 - $3.29	$	3.25
						Electricity price volatilities	23% - 63%	41		%
						Natural gas price volatilities	23% - 41%	31		%
Natural Gas:
Forward Contracts (a)	3		3		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.98 - $4.13	$	3.45
Total	$	33	$	74

(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.

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, 2015 and 2014 (dollars in millions):

	Three Months Ended   March 31,
Commodity Contracts	2015			2014
Net derivative balance at beginning of period	$	(41	)	$	(49	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(11		)	4
Settlements	—			—
Transfers into Level 3 from Level 2	(1		)	(3		)
Transfers from Level 3 into Level 2	4			(1		)
Net derivative balance at end of period	$	(49	)	$	(49	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no significant Level 1 transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our 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 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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Derivative Accounting

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Accounting

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 11 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, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	4,186	GWh
Gas	157	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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   March 31,
Commodity Contracts		2015			2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	(327	)	$	177
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(2,343		)	(4,439		)

(a) During the three months ended March 31, 2015 and 2014, 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 $5 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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   March 31,
Commodity Contracts		2015			2014
Net loss recognized in income	Operating revenues (a)	$	(48	)	$	(92	)
Net gain (loss) recognized in income	Fuel and purchased power (a)	(44,803		)	18,107
Total		$	(44,851	)	$	18,015

(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, 2015 and December 31, 2014, each include gross liabilities of $4 million 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, 2015 and December 31, 2014.  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, 2015: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance  Sheet
Current assets	$	26,414		$	(13,382	)	$	13,032		$	626		$	13,658
Investments and other assets	23,035			(4,591		)	18,444			—			18,444
Total assets	49,449			(17,973		)	31,476			626			32,102
Current liabilities	(97,349		)	42,069			(55,280		)	(7,023		)	(62,303		)
Deferred credits and other	(106,631		)	32,804			(73,827		)	—			(73,827		)
Total liabilities	(203,980		)	74,873			(129,107		)	(7,023		)	(136,130		)
Total	$	(154,531	)	$	56,900		$	(97,631	)	$	(6,397	)	$	(104,028	)

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

(b) Includes cash collateral provided to counterparties of $56,900.

(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 $7,023 and cash margin provided to counterparties of $626.

As of December 31, 2014: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance  Sheet
Current assets	$	28,562		$	(15,127	)	$	13,435		$	350		$	13,785
Investments and other assets	24,810			(7,190		)	17,620			—			17,620
Total assets	53,372			(22,317		)	31,055			350			31,405
Current liabilities	(86,062		)	33,829			(52,233		)	(7,443		)	(59,676		)
Deferred credits and other	(82,990		)	32,388			(50,602		)	—			(50,602		)
Total liabilities	(169,052		)	66,217			(102,835		)	(7,443		)	(110,278		)
Total	$	(115,680	)	$	43,900		$	(71,780	)	$	(7,093	)	$	(78,873	)

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

(b) Includes cash collateral provided to counterparties of $43,900.

(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 $7,443, and cash margin provided to counterparties of $350.

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 one counterparty for which our exposure represents approximately 94% of Pinnacle West’s $32 million of risk management assets as of March 31, 2015.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a 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, 2015 (dollars in millions):

	March 31, 2015
Aggregate fair value of derivative instruments in a net liability position	$	204
Cash collateral posted	57
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	104

(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 $166 million if our debt credit ratings were to fall below investment grade.

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Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 33	$ 33
Liabilities	82	74
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	31	30
Liabilities	60	56
Electricity forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	18.88	19.51
Electricity forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	46.54	56.72
Electricity forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	30.49	35.27
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	0	0
Liabilities	15	15
Option Contracts | Minimum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	30.24	32.14
Natural gas forward price (per MMbtu)	2.35	3.18
Electricity price volatilities (as a percent)	27.00%	23.00%
Natural gas price volatilities (as a percent)	26.00%	23.00%
Option Contracts | Maximum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	60.45	66.09
Natural gas forward price (per MMbtu)	2.88	3.29
Electricity price volatilities (as a percent)	86.00%	63.00%
Natural gas price volatilities (as a percent)	43.00%	41.00%
Option Contracts | Weighted Average | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	41.81	45.83
Natural gas forward price (per MMbtu)	2.83	3.25
Electricity price volatilities (as a percent)	54.00%	41.00%
Natural gas price volatilities (as a percent)	32.00%	31.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	2	3
Liabilities	$ 7	$ 3
Natural gas forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu)	2.30	2.98
Natural gas forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu)	3.59	4.13
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
Natural gas forward price (per MMbtu)	3.01	3.45

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Income Taxes

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million. The anticipated impact of these final regulations were accounted for in the Condensed Consolidated Balance Sheets as of December 31, 2014.

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.

As of March 31, 2015, the tax year ended December 31, 2011 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 2009.

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Palo Verde Sale Leaseback Variable Interest Entities

3 Months Ended

Mar. 31, 2015

Variable Interest Entities [Abstract]

Palo Verde Sale Leaseback Variable Interest Entities

Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lease agreements include fixed rate renewal periods. On July 7, 2014, APS notified the lessor trust entities of APS's intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $49 million in 2015, $23 million annually for the period 2016 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to 2 years, or return the assets to the lessors.

The fixed rate renewal periods give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2015 of $5 million and for the three months ended March 31, 2014 of $9 million, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased because of lower rent income resulting from the July 7, 2014 lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. 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, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):

	March 31, 2015		December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	120	$	121
Current maturities of long-term debt	13		13
Equity — Noncontrolling interests	156		152

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

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of March 31, 2015, APS would have been required to pay the noncontrolling equity participants approximately $123 million and assume $13 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 agreements 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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Commitments and Contingencies

3 Months Ended

Mar. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

On March 11, 2015, the DOE notified APS that it had approved APS’s claim for damages incurred due to DOE’s breach of the Standard Contract for the period July 1, 2011 through June 30, 2014. The claim for this period was the first claim made pursuant to the terms of the August 18, 2014 settlement agreement. The amount claimed was $42.0 million; APS’s share of this amount is $12.2 million. The settlement payment will be received in the second quarter of 2015. APS’s $12.2 million share will be recorded as an adjustment to a regulatory liability and will have no impact on income.

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 American Nuclear Insurers ("ANI").  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 liability 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 ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment 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").  APS is subject to retrospective premium 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 $23 million for each retrospective premium 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 $62 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 2014 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 52^nd 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.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Southwest Power Outage

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.

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 fully briefed and pending before the United States Court of Appeals for the Ninth Circuit.  We are unable to predict the outcome of this matter.

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.  We do not expect the outcome of this matter to have a material impact on our financial position, results of operations or cash flows.

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, Cholla and the Navajo Generating Station ("Navajo Plant").  EPA and 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. 

Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $400 million.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. The cost of the controls related to the 7% interest is approximately $45 million.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million.  In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process.

Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million, 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. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015.

Mercury and Air Toxic Standards.  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, which would be avoided if EPA approves APS's compromise proposal discussed above. 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.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million.

Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, greenhouse gas ("GHG") emissions (such as the EPA’s proposed "Clean Power Plan" rule), 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.

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.  We cannot predict the timing or outcome of this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At March 31, 2015, approximately $109 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, two expire in 2016, and one expires in 2017.  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 $20 million at March 31, 2015.  Additionally, APS has issued a letter of credit to support collateral obligations under a natural gas tolling contract entered into with a third party.  At March 31, 2015, that letter of credit totaled $5 million and will expire in 2015.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification 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 has provided indemnification under certain surety bonds for APS which were not material at March 31, 2015.

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Asset Retirement Obligations Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations
Asset retirement obligation, current	$ 28,918,000	$ 32,462,000
Arizona Public Service Company
Asset Retirement Obligations
Estimated cash flow revisions	18,000,000
Asset retirement obligation, current	28,918,000	32,462,000
Asset retirement obligation	408,000,000	391,000,000
Arizona Public Service Company | Four Corners
Asset Retirement Obligations
Estimated cash flow revisions	$ 18,000,000

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Changes in Accumulated Other Comprehensive Loss (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (68,141)	$ (78,053)
OCI (loss) before reclassifications	(800)	(422)
Amounts reclassified from accumulated other comprehensive loss	2,559	3,573
Total other comprehensive income	1,759	3,151
Ending balance	(66,382)	(74,902)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(10,385)	(23,058)
OCI (loss) before reclassifications	(800)	(422)
Amounts reclassified from accumulated other comprehensive loss	1,976	3,116
Total other comprehensive income	1,176	2,694
Ending balance	(9,209)	(20,364)
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(57,756)	(54,995)
OCI (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive loss	583	457
Total other comprehensive income	583	457
Ending balance	(57,173)	(54,538)
Arizona Public Service Company
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(48,333)	(53,372)
OCI (loss) before reclassifications	(800)	(421)
Amounts reclassified from accumulated other comprehensive loss	2,657	3,682
Total other comprehensive income	1,857	3,261
Ending balance	(46,476)	(50,111)
Arizona Public Service Company | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(10,385)	(23,059)
OCI (loss) before reclassifications	(800)	(421)
Amounts reclassified from accumulated other comprehensive loss	1,976	3,116
Total other comprehensive income	1,176	2,695
Ending balance	(9,209)	(20,364)
Arizona Public Service Company | Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(37,948)	(30,313)
OCI (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive loss	681	566
Total other comprehensive income	681	566
Ending balance	$ (37,267)	$ (29,747)

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Nuclear Decommissioning Trusts (Tables)

3 Months Ended

Mar. 31, 2015

Investments, Debt and Equity Securities [Abstract]

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, 2015 and December 31, 2014 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2015
Equity securities	$	313		$	161	$	—
Fixed income securities	416			20		(1		)
Net payables (a)	(2		)	—		—
Total	$	727		$	181	$	(1	)

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2014
Equity securities	$	310		$	159	$	—
Fixed income securities	411			17		(1		)
Net payables (a)	(7		)	—		—
Total	$	714		$	176	$	(1	)

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

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

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

	Three Months Ended   March 31,
	2015			2014
Realized gains	$	1		$	1
Realized losses	(1		)	(2		)
Proceeds from the sale of securities (a)	115			103

(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, 2015 is as follows (dollars in millions):

	Fair Value
Less than one year	$	16
1 year – 5 years	113
5 years – 10 years	118
Greater than 10 years	169
Total	$	416

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Gains and Losses from Derivative Instruments (Details) (Commodity Contracts, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)	$ (2,343)	$ (4,439)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	(44,851)	18,015
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	(48)	(92)
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	(44,803)	18,107
Other comprehensive income | Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain (loss) recognized in OCI on derivative instruments (effective portion)	$ (327)	$ 177

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New Accounting Standards

3 Months Ended

Mar. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The guidance may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. As originally issued, the new revenue standard would be effective for us on January 1, 2017; however, the FASB has recently proposed a one year deferral of the effective date, which if finalized will result in the new guidance being effective for us on January 1, 2018. We are currently evaluating this new guidance and the impacts it may have on our financial statements.

In February 2015, new guidance was issued that amends the consolidation accounting guidance. The amendments modify many aspects of the guidance relating to the analysis and consolidation of variable interest entities. These changes include impacts on the following: limited partnerships, fees paid to decision makers, related parties, and the determination of whether an entity qualifies as a variable interest entity. The new guidance is effective for us on January 1, 2016, and may be adopted using either a full retrospective or modified retrospective approach. We are currently evaluating this amended guidance and the impacts it may have on our financial statements.

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Long-Term Debt and Liquidity Matters (Tables)

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

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, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,540		4,045		3,290		3,714
Total	$	3,665	$	4,170	$	3,415	$	3,839

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Derivative Accounting Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015 Counterparty	Mar. 31, 2014	Dec. 31, 2014
Derivative Accounting
Percentage of deferred unrealized gains (losses) on contracts due to PSA recovery	100.00%
Arizona Public Service Company
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%
Designated as Hedging Instruments
Derivative Accounting
Gross recognized derivatives	$ 4,000,000		$ 4,000,000
Commodity Contracts
Derivative Accounting
Gross recognized derivatives	203,980,000		169,052,000
Amounts offset	(56,900,000)		(43,900,000)
Derivative liability, not subject to master netting arrangement	7,023,000		7,443,000
Other	626,000		350,000
Concentration of credit risk, number of counterparties	1
Concentration of risk with two counterparties, as a percentage of risk management assets	94.00%
Risk management activities-derivative instruments: Commodity Contracts	32,102,000		31,405,000
Additional collateral to counterparties for energy related non-derivative instrument contracts	166,000,000
Commodity Contracts | Designated as Hedging Instruments
Derivative Accounting
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	0	0
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income	(5,000,000)
Current Liabilities | Commodity Contracts
Derivative Accounting
Gross recognized derivatives	97,349,000		86,062,000
Amounts offset	(56,900,000)		(43,900,000)
Derivative liability, not subject to master netting arrangement	$ 7,023,000		$ 7,443,000

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Regulatory Matters - Four Corners and Cholla (Details) (APS, USD $) In Millions, unless otherwise specified	0 Months Ended		3 Months Ended
	Dec. 23, 2014	Dec. 30, 2013 MW	Mar. 31, 2015
SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Ownership interest acquired		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1
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 cost deferral | SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Regulatory assets, non-current			75
Regulatory noncurrent asset amortization period			10 years
Retired power plant costs
Business Acquisition [Line Items]
Net book value			$ 127

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 11,664	$ 7,604
Customer and other receivables	242,457	297,740
Accrued unbilled revenues	94,400	100,533
Allowance for doubtful accounts	(2,560)	(3,094)
Materials and supplies (at average cost)	221,276	218,889
Fossil fuel (at average cost)	44,705	37,097
Deferred income taxes	113,521	122,232
Income tax receivable (Note 5)	3,317	3,098
Assets from risk management activities (Note 7)	13,658	13,785
Deferred fuel and purchased power regulatory asset (Note 3)	0	6,926
Other regulatory assets (Note 3)	147,869	129,808
Other current assets	45,135	38,817
Total current assets	935,442	973,435
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	18,444	17,620
Nuclear decommissioning trust (Note 12)	727,342	713,866
Other assets	51,449	54,047
Total investments and other assets	797,235	785,533
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,551,726	15,543,063
Accumulated depreciation and amortization	(5,452,860)	(5,397,751)
Net	10,098,866	10,145,312
Construction work in progress	841,426	682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	120,287	121,255
Intangible assets, net of accumulated amortization	127,620	119,755
Nuclear fuel, net of accumulated amortization	136,557	125,201
Total property, plant and equipment	11,324,756	11,194,330
DEFERRED DEBITS
Regulatory assets (Note 3)	1,067,830	1,054,087
Assets for other postretirement benefits (Note 4)	156,192	152,290
Other	154,248	153,857
Total deferred debits	1,378,270	1,360,234
TOTAL ASSETS	14,435,703	14,313,532
CURRENT LIABILITIES
Accounts payable	271,489	295,211
Accrued taxes (Note 5)	188,724	140,613
Accrued interest	42,096	52,603
Common dividends payable	0	65,790
Short-term borrowings (Note 2)	44,500	147,400
Current maturities of long-term debt (Note 2)	383,570	383,570
Customer deposits	72,561	72,307
Liabilities from risk management activities (Note 7)	62,303	59,676
Deferred fuel and purchased power regulatory liability (Note 3)	16,359	0
Liabilities for asset retirements (Note 15)	28,918	32,462
Other regulatory liabilities (Note 3)	113,024	130,549
Other current liabilities	150,432	178,962
Total current liabilities	1,373,976	1,559,143
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	3,281,319	3,031,215
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,586,180	2,582,636
Regulatory liabilities (Note 3)	1,070,106	1,051,196
Liabilities for asset retirements (Note 15)	379,263	358,288
Liabilities for pension benefits (Note 4)	412,552	453,736
Liabilities from risk management activities (Note 7)	73,827	50,602
Customer advances	122,259	123,052
Coal mine reclamation	199,218	198,292
Deferred investment tax credit	178,313	178,607
Unrecognized tax benefits (Note 5)	14,196	19,377
Other	191,487	188,286
Total deferred credits and other	5,227,401	5,204,072
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 110,809,492 and 110,649,762 issued at respective dates	2,523,247	2,512,970
Treasury stock at cost; 61,784 and 78,400 shares at respective dates	(2,266)	(3,401)
Total common stock	2,520,981	2,509,569
Retained earnings	1,942,194	1,926,065
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(57,173)	(57,756)
Derivative instruments	(9,209)	(10,385)
Total accumulated other comprehensive loss	(66,382)	(68,141)
Total shareholders’ equity	4,396,793	4,367,493
Noncontrolling interests (Note 6)	156,214	151,609
Total equity	4,553,007	4,519,102
TOTAL LIABILITIES AND EQUITY	14,435,703	14,313,532
Arizona Public Service Company
CURRENT ASSETS
Cash and cash equivalents	6,083	4,515
Customer and other receivables	238,863	297,712
Accrued unbilled revenues	94,400	100,533
Allowance for doubtful accounts	(2,560)	(3,094)
Materials and supplies (at average cost)	221,276	218,889
Fossil fuel (at average cost)	44,705	37,097
Assets from risk management activities (Note 7)	13,658	13,785
Deferred fuel and purchased power regulatory asset (Note 3)	0	6,926
Other regulatory assets (Note 3)	147,869	129,808
Deferred income taxes	54,789	55,253
Other current assets	44,496	38,693
Total current assets	863,579	900,117
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	18,444	17,620
Nuclear decommissioning trust (Note 12)	727,342	713,866
Other assets	33,832	33,362
Total investments and other assets	779,618	764,848
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,548,474	15,539,811
Accumulated depreciation and amortization	(5,449,753)	(5,394,650)
Net	10,098,721	10,145,161
Construction work in progress	840,928	682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	120,287	121,255
Intangible assets, net of accumulated amortization	127,465	119,600
Nuclear fuel, net of accumulated amortization	136,557	125,201
Total property, plant and equipment	11,323,958	11,194,024
DEFERRED DEBITS
Regulatory assets (Note 3)	1,067,830	1,054,087
Assets for other postretirement benefits (Note 4)	153,156	149,260
Unamortized debt issue costs	25,948	24,642
Other	127,190	128,026
Total deferred debits	1,374,124	1,356,015
TOTAL ASSETS	14,341,279	14,215,004
CURRENT LIABILITIES
Accounts payable	265,779	289,930
Accrued taxes (Note 5)	190,167	131,110
Accrued interest	41,919	52,358
Common dividends payable	0	65,800
Short-term borrowings (Note 2)	44,500	147,400
Current maturities of long-term debt (Note 2)	383,570	383,570
Customer deposits	72,561	72,307
Liabilities from risk management activities (Note 7)	62,303	59,676
Deferred fuel and purchased power regulatory liability (Note 3)	16,359	0
Liabilities for asset retirements (Note 15)	28,918	32,462
Other regulatory liabilities (Note 3)	113,024	130,549
Other current liabilities	130,161	167,302
Total current liabilities	1,349,261	1,532,464
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,573,876	2,571,365
Regulatory liabilities (Note 3)	1,070,106	1,051,196
Liabilities for asset retirements (Note 15)	379,263	358,288
Liabilities for pension benefits (Note 4)	384,215	424,508
Liabilities from risk management activities (Note 7)	73,827	50,602
Customer advances	122,259	123,052
Coal mine reclamation	199,218	198,292
Deferred investment tax credit	178,313	178,607
Unrecognized tax benefits (Note 5)	45,190	45,740
Other	153,249	144,823
Total deferred credits and other	5,179,516	5,146,473
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Total common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,988,587	1,968,718
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(37,267)	(37,948)
Derivative instruments	(9,209)	(10,385)
Total accumulated other comprehensive loss	(46,476)	(48,333)
Total shareholders’ equity	4,499,969	4,478,243
Noncontrolling interests (Note 6)	156,214	151,609
Total equity	4,656,183	4,629,852
Long-term debt less current maturities (Note 2)	3,156,319	2,906,215
Total capitalization	7,812,502	7,536,067
TOTAL LIABILITIES AND EQUITY	$ 14,341,279	$ 14,215,004

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Long-Term Debt and Liquidity Matters

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Long-Term Debt and Liquidity Matters

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 revolving credit facility matures in May 2019.  At March 31, 2015, 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 size 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, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020.  The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash used to fund capital expenditures.

At March 31, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and the $500 million facility that matures in May 2019.  APS may increase the size 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, 2015, APS had $45 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.

See "Financial Assurances" in Note 8 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, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,540		4,045		3,290		3,714
Total	$	3,665	$	4,170	$	3,415	$	3,839

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, 2015, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.3 billion, assuming APS’s total capitalization remains the same.

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Earnings Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 16,122	$ 15,766
Weighted average common shares outstanding - basic	110,916	110,257
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	461	631
Weighted average common shares outstanding — diluted	111,377	110,888
Earnings per average common share attributable to common shareholders -basic (in dollars per share)	$ 0.15	$ 0.14
Earnings per average common share attributable to common shareholders -diluted (in dollars per share)	$ 0.14	$ 0.14

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Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2015

Regulated Operations [Abstract]

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

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2015 and 2014 (dollars in millions):

	Three Months Ended   March 31,
	2015			2014
Beginning balance	$	7		$	21
Deferred fuel and purchased power costs — current period	(18		)	(32		)
Amounts charged to customers	(5		)	(8		)
Ending balance	$	(16	)	$	(19	)

Schedule of regulatory assets

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

	Remaining Amortization Period	March 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Pension benefits	(a)	$	—	$	479	$	—	$	485
Income taxes — allowance for funds used during construction ("AFUDC") equity	2044	5		117		5		118
Deferred fuel and purchased power — mark-to-market (Note 7)	2018	66		72		51		46
Transmission vegetation management	2016	9		2		9		5
Coal reclamation	2026	—		6		—		7
Palo Verde VIEs (Note 6)	2046	—		30		—		35
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		7		—
Tax expense of Medicare subsidy	2024	2		14		2		14
Loss on reacquired debt	2034	1		16		1		16
Income taxes — investment tax credit basis adjustment	2044	2		46		2		46
Pension and other postretirement benefits deferral	2015	2		—		4		—
Four Corners cost deferral	2024	7		68		7		70
Lost fixed cost recovery (b)	2016	43		—		38		—
Retired power plant costs	2033	10		134		10		136
Deferred property taxes	(d)	—		36		—		30
Other	Various	1		12		2		12
Total regulatory assets (e)		$	148	$	1,068	$	138	$	1,054

(a) This asset represents the future recovery of 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) Per the provision of the 2012 Settlement Agreement.

(e) 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, Transmission Cost Adjustor and Other Transmission Matters.

Schedule of regulatory liabilities

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

	Remaining Amortization Period	March 31, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	37	$	264	$	31	$	273
Asset retirement obligations	2044	—		302		—		296
Renewable energy standard (b)	2017	25		25		25		23
Income taxes — change in rates	2043	1		71		—		72
Spent nuclear fuel	2047	5		66		5		66
Deferred gains on utility property	2019	2		8		2		8
Income taxes — deferred investment tax credit	2043	3		93		4		93
Deferred fuel and purchased power (b) (c)	2016	16		—		—		—
Demand side management (b)	2017	5		27		31		—
Other postretirement benefits	(d)	32		191		32		199
Other	Various	3		23		1		21
Total regulatory liabilities		$	129	$	1,070	$	131	$	1,051

(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 a carrying charge.

(d) See Note 4.

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Long-Term Debt and Liquidity Matters Narrative (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Jan. 12, 2015
Debt Provisions
Total shareholder equity	$ 4,396,793,000	$ 4,367,493,000
Pinnacle West | Line of Credit | New revolving credit facility maturing in 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility	200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	300,000,000
Outstanding borrowings	0
Pinnacle West | Commercial Paper | New revolving credit facility maturing in 2019
Long-Term Debt and Liquidity Matters
Maximum commercial paper support available under credit facility	200,000,000
Commercial Paper	0
Pinnacle West | Letter of Credit | New revolving credit facility maturing in 2019
Long-Term Debt and Liquidity Matters
Outstanding letters of credit	0
APS
Debt Provisions
Total shareholder equity	4,499,969,000	4,478,243,000
APS | ACC
Debt Provisions
Total shareholder equity	4,500,000,000
Total capitalization	8,200,000,000
Dividend restrictions, shareholder equity required	3,300,000,000
APS | ACC | Minimum
Debt Provisions
Required common equity ratio ordered by ACC (as a percent)	40.00%
APS | Commercial Paper
Long-Term Debt and Liquidity Matters
Commercial Paper	45,000,000
APS | Revolving Credit Facility
Long-Term Debt and Liquidity Matters
Outstanding borrowings	0
Outstanding letters of credit	0
APS | Revolving Credit Facility | Revolving credit facilities maturing 2018 & 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility	1,000,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	700,000,000
Number of line of credit facilities	2
APS | Revolving Credit Facility | Revolving credit facility maturing in 2018
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility	500,000,000
APS | Revolving Credit Facility | New revolving credit facility maturing in 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility	500,000,000
APS | Commercial Paper
Long-Term Debt and Liquidity Matters
Maximum commercial paper support available under credit facility	250,000,000
APS | Letter of Credit
Long-Term Debt and Liquidity Matters
Outstanding letters of credit	109,000,000
APS | Senior Notes | 4.70% unsecured senior notes that mature on January 15, 2044
Long-Term Debt and Liquidity Matters
Debt issued			$ 250,000,000
Interest rate (as a percent)			2.20%

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Nuclear Decommissioning Trusts

3 Months Ended

Mar. 31, 2015

Investments, Debt and Equity Securities [Abstract]

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 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 11 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, 2015 and December 31, 2014 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
March 31, 2015
Equity securities	$	313		$	161	$	—
Fixed income securities	416			20		(1		)
Net payables (a)	(2		)	—		—
Total	$	727		$	181	$	(1	)

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2014
Equity securities	$	310		$	159	$	—
Fixed income securities	411			17		(1		)
Net payables (a)	(7		)	—		—
Total	$	714		$	176	$	(1	)

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

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

	Three Months Ended   March 31,
	2015			2014
Realized gains	$	1		$	1
Realized losses	(1		)	(2		)
Proceeds from the sale of securities (a)	115			103

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2015 is as follows (dollars in millions):

	Fair Value
Less than one year	$	16
1 year – 5 years	113
5 years – 10 years	118
Greater than 10 years	169
Total	$	416