PINNACLE WEST CAPITAL CORP - Quarter Report: 2014 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2014

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 July 25, 2014: 110,408,854
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of July 25, 2014: 71,264,947

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

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TABLE OF CONTENTS

		Page

Forward-Looking Statements		2
Part I		3
Item 1.	Financial Statements	3
	Pinnacle West Capital Corporation	3
	Arizona Public Service Company	47
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	58
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	79
Item 4.	Controls and Procedures	79

Part II		80
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	80
Item 5.	Other Information	81
Item 6.	Exhibits	84
Signatures		87

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

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FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (“2013 Form 10-K”), Part II, Item 1A of this report and in Part I, Item 2 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, these factors include, but are not limited to:

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

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

· power plant and transmission system performance and outages;

· competition in retail and wholesale power markets;

· regulatory and judicial decisions, developments and proceedings;

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

· fuel and water supply availability;

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

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

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

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

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

· environmental and other concerns surrounding coal-fired generation;

· volatile fuel and purchased power costs;

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

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

· potential shortfalls in insurance coverage;

· new accounting requirements or new interpretations of existing requirements;

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

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

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

· technological developments affecting the electric industry; and

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

These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our 2013 Form 10-K and in Part II, Item 1A of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended June 30,
	2014			2013

OPERATING REVENUES	$	906,264		$	915,822

OPERATING EXPENSES
Fuel and purchased power	290,854			277,584
Operations and maintenance	211,222			229,300
Depreciation and amortization	105,150			106,292
Taxes other than income taxes	44,004			40,814
Other expenses	921			2,020
Total	652,151			656,010
OPERATING INCOME	254,113			259,812
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,499			6,265
Other income (Note 10)	2,781			469
Other expense (Note 10)	(508		)	(2,234		)
Total	9,772			4,500
INTEREST EXPENSE
Interest charges	51,751			51,307
Allowance for borrowed funds used during construction	(3,790		)	(3,636		)
Total	47,961			47,671
INCOME BEFORE INCOME TAXES	215,924			216,641
INCOME TAXES	74,540			77,043
NET INCOME	141,384			139,598
Less: Net income attributable to noncontrolling interests (Note 6)	8,926			8,391
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	132,458		$	131,207

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	110,565			109,962
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	111,002			110,932

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	1.20		$	1.19
Net income attributable to common shareholders — diluted	$	1.19		$	1.18

DIVIDENDS DECLARED PER SHARE	$	1.14		$	1.09

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,
	2014			2013

NET INCOME	$	141,384		$	139,598

OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(26) and $105	40			(160		)
Reclassification of net realized loss, net of tax benefit of $1,261 and $2,824	1,955			4,322
Pension and other postretirement benefits activity, net of tax benefit of $845 and $449	(1,310		)	(688		)
Total other comprehensive income	685			3,474

COMPREHENSIVE INCOME	142,069			143,072
Less: Comprehensive income attributable to noncontrolling interests	8,926			8,391

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	133,143		$	134,681

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Six Months Ended June 30,
	2014			2013

OPERATING REVENUES	$	1,592,515		$	1,602,474

OPERATING EXPENSES
Fuel and purchased power	540,640			508,263
Operations and maintenance	424,104			452,550
Depreciation and amortization	206,922			210,022
Taxes other than income taxes	89,849			80,835
Other expenses	1,717			4,069
Total	1,263,232			1,255,739
OPERATING INCOME	329,283			346,735
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	14,941			13,129
Other income (Note 10)	5,148			1,227
Other expense (Note 10)	(5,192		)	(5,986		)
Total	14,897			8,370
INTEREST EXPENSE
Interest charges	104,720			100,785
Allowance for borrowed funds used during construction	(7,560		)	(7,626		)
Total	97,160			93,159
INCOME BEFORE INCOME TAXES	247,020			261,946
INCOME TAXES	80,945			89,512
NET INCOME	166,075			172,434
Less: Net income attributable to noncontrolling interests (Note 6)	17,851			16,783
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	148,224		$	155,651

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	110,546			109,898
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,925			110,843

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	1.34		$	1.42
Net income attributable to common shareholders — diluted	$	1.34		$	1.40

DIVIDENDS DECLARED PER SHARE	$	1.14		$	1.09

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2014			2013

NET INCOME	$	166,075		$	172,434

OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $(624) and $67	(381		)	(102		)
Reclassification of net realized loss, net of tax benefit of $2,584 and $6,124	5,070			9,375
Pension and other postretirement benefits activity, net of tax benefit (expense) of $128 and $(182)	(853		)	278
Total other comprehensive income	3,836			9,551

COMPREHENSIVE INCOME	169,911			181,985
Less: Comprehensive income attributable to noncontrolling interests	17,851			16,783

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	152,060		$	165,202

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2014			December 31, 2013
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	9,161		$	9,526
Customer and other receivables	325,352			299,904
Accrued unbilled revenues	172,444			96,796
Allowance for doubtful accounts	(2,731		)	(3,203		)
Materials and supplies (at average cost)	230,310			221,682
Fossil fuel (at average cost)	38,835			38,028
Deferred income taxes	83,633			91,152
Income tax receivable (Note 5)	—			135,517
Assets from risk management activities (Note 7)	15,420			17,169
Deferred fuel and purchased power regulatory asset (Note 3)	1,043			20,755
Other regulatory assets (Note 3)	77,148			76,388
Other current assets	48,457			39,895
Total current assets	999,072			1,043,609

INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	21,581			23,815
Nuclear decommissioning trust (Note 13)	682,359			642,007
Other assets	61,380			60,875
Total investments and other assets	765,320			726,697

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,448,087			15,200,464
Accumulated depreciation and amortization	(5,388,667		)	(5,300,219		)
Net	10,059,420			9,900,245
Construction work in progress	584,152			581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	123,190			125,125
Intangible assets, net of accumulated amortization	137,037			157,689
Nuclear fuel, net of accumulated amortization	125,246			124,557
Total property, plant and equipment	11,029,045			10,888,985

DEFERRED DEBITS
Regulatory assets (Note 3)	755,174			711,712
Other	141,706			137,683
Total deferred debits	896,880			849,395

TOTAL ASSETS	$	13,690,317		$	13,508,686

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2014			December 31, 2013
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	320,779		$	284,516
Accrued taxes (Note 5)	161,707			130,998
Accrued interest	52,740			48,351
Common dividends payable	62,656			62,528
Short-term borrowings (Note 2)	176,650			153,125
Current maturities of long-term debt (Note 2)	368,841			540,424
Customer deposits	74,779			76,101
Liabilities from risk management activities (Note 7)	21,502			31,892
Liabilities for asset retirements	35,726			32,896
Regulatory liabilities (Note 3)	114,204			99,273
Other current liabilities	165,123			158,540
Total current liabilities	1,554,707			1,618,644

LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	2,999,513			2,796,465

DEFERRED CREDITS AND OTHER
Deferred income taxes	2,396,026			2,351,882
Regulatory liabilities (Note 3)	809,442			801,297
Liabilities for asset retirements (Note 16)	356,436			313,833
Liabilities for pension and other postretirement benefits (Note 4)	439,490			513,628
Liabilities from risk management activities (Note 7)	23,367			70,315
Customer advances	120,330			114,480
Coal mine reclamation	208,951			207,453
Deferred investment tax credit	181,236			152,361
Unrecognized tax benefits (Note 5)	22,814			42,209
Other	196,143			185,659
Total deferred credits and other	4,754,235			4,753,117

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

EQUITY (Note 8)
Common stock, no par value; authorized 150,000,000 shares, 110,430,456 and 110,280,703 issued at respective dates	2,500,064			2,491,558
Treasury stock at cost; 23,824 and 98,944 shares at respective dates	(189		)	(4,308		)
Total common stock	2,499,875			2,487,250
Retained earnings	1,808,232			1,785,273
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(55,848		)	(54,995		)
Derivative instruments	(18,369		)	(23,058		)
Total accumulated other comprehensive loss	(74,217		)	(78,053		)
Total shareholders’ equity	4,233,890			4,194,470
Noncontrolling interests (Note 6)	147,972			145,990
Total equity	4,381,862			4,340,460

TOTAL LIABILITIES AND EQUITY	$	13,690,317		$	13,508,686

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

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	166,075		$	172,434
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	246,371			249,482
Deferred fuel and purchased power	1,315			36,183
Deferred fuel and purchased power amortization	18,399			10,921
Allowance for equity funds used during construction	(14,941		)	(13,129		)
Deferred income taxes	32,611			68,526
Deferred investment tax credit	28,875			20,159
Change in derivative instruments fair value	49			349
Changes in current assets and liabilities:
Customer and other receivables	(64,986		)	(79,408		)
Accrued unbilled revenues	(75,648		)	(68,763		)
Materials, supplies and fossil fuel	(9,435		)	(4,002		)
Income tax receivable	135,517			779
Other current assets	(14,038		)	(14,439		)
Accounts payable	30,725			85,563
Accrued taxes	30,709			4,253
Other current liabilities	19,978			(26,098		)
Change in margin and collateral accounts — assets	(2,107		)	(1,111		)
Change in margin and collateral accounts — liabilities	(22,425		)	14,600
Change in other long-term assets	(19,243		)	(23,796		)
Change in other long-term liabilities	(22,735		)	21,753
Net cash flow provided by operating activities	465,066			454,256

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(388,752		)	(376,601		)
Contributions in aid of construction	12,646			21,236
Allowance for borrowed funds used during construction	(7,560		)	(7,626		)
Proceeds from nuclear decommissioning trust sales	199,224			253,996
Investment in nuclear decommissioning trust	(207,848		)	(262,621		)
Other	(678		)	(262		)
Net cash flow used for investing activities	(392,968		)	(371,878		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	535,975			136,307
Repayment of long-term debt	(503,583		)	(40,127		)
Short-term borrowings and payments — net	23,525			(62,075		)
Dividends paid on common stock	(125,138		)	(116,231		)
Common stock equity issuance	12,625			9,751
Distributions to noncontrolling interests	(15,869		)	(9,197		)
Other	2			795
Net cash flow used for financing activities	(72,463		)	(80,777		)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(365		)	1,601

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	9,526			26,202

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	9,161		$	27,803

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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Consolidation and Nature of Operations

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

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

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

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

Statement of Cash Flows for the Six Months Ended June 30, 2013	As previously reported		Changes to conform to current year presentation			Amount reported after changes to conform to current year presentation
Cash Flows from Operating Activities
Accrued taxes and income tax receivable	$	5,032	$	(5,032	)	$	—
Income tax receivable - net	—		779			779
Accrued taxes	—		4,253			4,253

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

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

	Six Months Ended June 30,
	2014			2013
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(131,154	)	$	(9	)
Interest, net of amounts capitalized	90,707			91,346
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	19,668		$	8,904
Dividends accrued but not yet paid	62,656			59,946

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

On May 9, 2014, Pinnacle West replaced its $200 million revolving credit facility that would have matured in November 2016, with a new $200 million facility that matures in May 2019. At June 30, 2014, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At June 30, 2014, Pinnacle West had commercial paper borrowings of $4 million, no outstanding borrowings under its credit facility and no letters of credit outstanding.

APS

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. On January 15, 2014, both of these series of bonds were canceled and refinanced as described below.

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

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidated Balance Sheets at June 30, 2014. We expect to remarket or refinance all $64 million of the 2009 Series D Bonds and 2009 Series E Bonds within the next twelve months, which were classified as current maturities of long-term debt at December 31, 2013.

On May 9, 2014, APS replaced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019.

On May 30, 2014, APS purchased all $38 million of the Navajo County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034, and on June 1, 2014, APS purchased a total of $64 million of the Navajo 2009 Series B Bonds and 2009 Series C Bonds, in each case, in connection with the mandatory tender provisions for this indebtedness. We expect to remarket or refinance these bonds within the next twelve months. These bonds were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2013.

On June 1, 2014, APS remarketed all $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2014.

On June 18, 2014, APS issued $250 million of 3.35% unsecured senior notes that mature on June 15, 2024. The net proceeds from the sale were used along with other funds to repay at maturity APS’s $300 million aggregate principal amount of 5.80% senior notes due June 30, 2014.

At June 30, 2014, 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 (see above). APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At June 30, 2014, APS had $173 million of commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.

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

Debt Fair Value

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

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	As of June 30, 2014				As of December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Pinnacle West	$	125	$	125	$	125	$	125
APS	3,243		3,628		3,212		3,454
Total	$	3,368	$	3,753	$	3,337	$	3,579

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At June 30, 2014, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same.

3. Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “2012 Settlement Agreement”) 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.

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Other key provisions of the 2012 Settlement Agreement include the following:

· An authorized return on common equity of 10.0%;

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

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

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

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

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

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

· Implementation of a Lost Fixed Cost Recovery (“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”);

· 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.

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The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.

Cost Recovery Mechanisms

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

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

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

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 20 MW of APS-owned residential solar.

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 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

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

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

	Six Months Ended June 30,
	2014			2013
Beginning balance	$	21		$	73
Deferred fuel and purchased power costs — current period	(1		)	(36		)
Amounts charged to customers	(19		)	(10		)
Ending balance	$	1		$	27

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

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, the United States Federal Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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

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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.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. Workshops in this docket are being held in 2014.

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Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid. ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift. The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement.

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

On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015. The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design. The Commissioners stated that they plan to vote at an August 2014 open meeting on whether to eliminate the requirement that APS file a rate case in June 2015.

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Four Corners

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. If approved, these adjustments would result in an average bill impact to residential customers of approximately 2%. This includes the deferral for future recovery of all non-fuel operating 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. 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 $55 million as of June 30, 2014. ACC staff and other intervenors have filed testimony in this matter with the ACC, and APS has filed rebuttal testimony. Both ACC staff and the Residential Utility Customer Office have proposed adjustments to the return to be applied to the Four Corners investments until APS’s next rate case, which would result in a lower level of recovery than proposed by APS. A hearing on this matter is scheduled to begin August 4, 2014, and we anticipate a decision by the end of 2014. APS cannot predict the outcome of this matter.

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

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Regulatory Assets and Liabilities

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

	Remaining Amortization		June 30, 2014				December 31, 2013
	Period		Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits		(a)	$	—	$	342	$	—	$	314
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2043		4		108		4		105
Deferred fuel and purchased power — mark-to-market (Note 7)	2016		—		17		5		29
Transmission vegetation management	2016		9		9		9		14
Coal reclamation	2038		8		14		8		18
Palo Verde VIEs (Note 6)	2046		—		43		—		41
Deferred compensation	2036		—		36		—		34
Deferred fuel and purchased power (b) (c)	2015		1		—		21		—
Tax expense of Medicare subsidy	2023		2		15		2		15
Loss on reacquired debt	2034		1		17		1		17
Income taxes — investment tax credit basis adjustment	2043		2		47		1		39
Pension and other postretirement benefits deferral	2015		8		—		8		4
Four Corners cost deferral	2024		—		55		—		37
Lost fixed cost recovery (b)	2015		34		—		25		—
Transmission cost adjustor (b)	2015		5		—		8		2
Retired power plant costs	2020		3		16		3		18
Deferred property taxes		(d)	—		24		—		11
Other	Various		1		12		2		14
Total regulatory assets (e)			$	78	$	755	$	97	$	712

(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.

(d) Per the provision of the 2012 Settlement Agreement.

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(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		June 30, 2014				December 31, 2013
	Period		Current		Non-Current		Current		Non-Current
Removal costs		(a)	$	29	$	293	$	28	$	303
Asset retirement obligations		(a)	—		274		—		266
Renewable energy standard (b)	2015		35		11		33		15
Income taxes — change in rates	2043		—		73		—		74
Spent nuclear fuel	2047		5		36		6		36
Deferred gains on utility property	2019		2		9		2		10
Income taxes — deferred investment tax credit	2043		3		94		3		79
Demand side management (b)	2015		35		—		27		—
Deferred fuel and purchased power — mark to market (Note 7)	2015		4		—		—		—
Other	Various		1		19		—		18
Total regulatory liabilities			$	114	$	809	$	99	$	801

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

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

4. Retirement Plans and Other Benefits

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

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement. Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012. We amortized approximately $2 million and $4 million for the three and six months ended June 30, 2014 and 2013, respectively. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):

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	Pension Benefits												Other Benefits
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013			2014			2013			2014			2013
Service cost — benefits earned during the period	$	12		$	15		$	27		$	32		$	5		$	6		$	9		$	12
Interest cost on benefit obligation	33			28			65			56			11			10			23			20
Expected return on plan assets	(39		)	(36		)	(79		)	(73		)	(13		)	(12		)	(25		)	(23		)
Amortization of:
Prior service cost	—			—			—			1			—			—			—			—
Net actuarial loss	3			10			5			20			—			3			—			6
Net periodic benefit cost	$	9		$	17		$	18		$	36		$	3		$	7		$	7		$	15
Portion of cost charged to expense	$	5		$	9		$	11		$	19		$	3		$	4		$	5		$	9

Contributions

The minimum contributions for the pension plan total $141 million for the next three years under the Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016). However, we expect to make voluntary contributions totaling up to $300 million for the next three years ($175 million in 2014, of which $140 million was already contributed through July 2014, up to $100 million in 2015, and up to $25 million in 2016). The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

5. Income Taxes

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

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

In January 2014, we prospectively adopted guidance requiring unrecognized tax benefits to be presented as a reduction to any available deferred income tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. As a result of this guidance, $19 million and $5 million of unrecognized tax benefits were recorded as a reduction to net current deferred income tax assets on the Condensed Consolidated Balance Sheets and APS Condensed Consolidated Balance Sheets, respectively as of June 30, 2014.

As of June 30, 2014, the tax year ended December 31, 2010 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.

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6. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million per year during 2014 and 2015 related to these leases. The lease agreements include fixed rate renewal periods, which 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.

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 lease payments of approximately $23 million annually for the period 2016 through 2023, and about $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 two years, or return the assets to the lessors.

As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three and six months ended June 30, 2014 of $9 million and $18 million, respectively, and for the three and six months ended June 30, 2013 of $8 million and $17 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at June 30, 2014 and December 31, 2013 include the following amounts relating to the VIEs (in millions):

	June 30, 2014		December 31, 2013
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	123	$	125
Current maturities of long-term debt	37		26
Long-term debt excluding current maturities	1		13
Equity — Noncontrolling interests	148		146

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

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

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occurred as of June 30, 2014, APS would have been required to pay the noncontrolling equity participants approximately $138 million and assume $38 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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

7. Derivative Accounting

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

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

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

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting

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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 June 30, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	5,038	GWh
Gas	132	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 and six months ended June 30, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	Location	2014			2013			2014			2013

Gain (loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	66		$	(265	)	$	243		$	(169	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(3,216		)	(7,146		)	(7,654		)	(15,499		)

(a) During the three and six months ended June 30, 2014 and 2013, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that a net loss of $17 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 and six months ended June 30, 2014 and 2013 (dollars in thousands):

	Financial Statement	Three Months Ended June 30,					Six Months Ended June 30,
Commodity Contracts	Location	2014		2013			2014		2013

Net Gain Recognized in Income	Operating revenues (a)	$	155	$	322		$	63	$	205

Net Gain (loss) Recognized in Income	Fuel and purchased power (a)	4,805		(27,758		)	22,912		(10,408		)
Total		$	4,960	$	(27,436	)	$	22,975	$	(10,203	)

(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 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 June 30, 2014 and December 31, 2013, include gross liabilities of $4 million and $5 million, respectively, of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2014 and December 31, 2013. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

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As of June 30, 2014: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current Assets	$	26,941		$	(12,125	)	$	14,816		$	604		$	15,420
Investments and Other Assets	23,824			(3,753		)	20,071			1,510			21,581
Total Assets	50,765			(15,878		)	34,887			2,114			37,001

Current Liabilities	(40,376		)	26,367			(14,009		)	(7,493		)	(21,502		)
Deferred Credits and Other	(54,278		)	30,911			(23,367		)	—			(23,367		)
Total Liabilities	(94,654		)	57,278			(37,376		)	(7,493		)	(44,869		)
Total	$	(43,889	)	$	41,400		$	(2,489	)	$	(5,379	)	$	(7,868	)

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

(b) Includes cash collateral provided to counterparties of $41,400.

(c) Represents option premiums, and 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 $7,493, and cash margin provided to counterparties of $604.

As of December 31, 2013: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current Assets	$	24,587		$	(7,425	)	$	17,162		$	7		$	17,169
Investments and Other Assets	25,364			(1,549		)	23,815			—			23,815
Total Assets	49,951			(8,974		)	40,977			7			40,984

Current Liabilities	(50,540		)	26,166			(24,374		)	(7,518		)	(31,892		)
Deferred Credits and Other	(72,123		)	1,808			(70,315		)	—			(70,315		)
Total Liabilities	(122,663		)	27,974			(94,689		)	(7,518		)	(102,207		)
Total	$	(72,712	)	$	19,000		$	(53,712	)	$	(7,511	)	$	(61,223	)

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

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

(c) Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.

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Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 77% of Pinnacle West’s $37 million of risk management assets as of June 30, 2014. This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow 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 June 30, 2014 (dollars in millions):

	June 30, 2014
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	95
Cash Collateral Posted	41
Additional Cash Collateral in the Event Credit-Risk-Related Contingent Features were Fully Triggered (a)	43

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

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

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8. Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and six months ended June 30, 2014 and 2013 (dollars in thousands):

	Three Months Ended June 30, 2014									Three Months Ended June 30, 2013
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total

Beginning balance, April 1	$	4,222,786		$	154,915		$	4,377,701		$	4,014,455		$	137,875		$	4,152,330

Net income	132,458			8,926			141,384			131,207			8,391			139,598
Other comprehensive income	685			—			685			3,474			—			3,474
Total comprehensive income	133,143			8,926			142,069			134,681			8,391			143,072

Issuance of capital stock	2,280			—			2,280			2,363			—			2,363
Reissuance of treasury stock — net	654			—			654			366			—			366
Other (primarily stock compensation)	292			—			292			185			—			185
Dividends on common stock	(125,265		)	—			(125,265		)	(119,885		)	—			(119,885		)
Net capital activities by noncontrolling interests	—			(15,869		)	(15,869		)	—			(9,196		)	(9,196		)
Ending balance, June 30	$	4,233,890		$	147,972		$	4,381,862		$	4,032,165		$	137,070		$	4,169,235

	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total

Beginning balance, January 1	$	4,194,470		$	145,990		$	4,340,460		$	3,972,806		$	129,483		$	4,102,289

Net income	148,224			17,851			166,075			155,651			16,783			172,434
Other comprehensive income	3,836			—			3,836			9,551			—			9,551
Total comprehensive income	152,060			17,851			169,911			165,202			16,783			181,985

Issuance of capital stock	4,872			—			4,872			4,937			—			4,937
Reissuance (purchase) of treasury stock — net	4,119			—			4,119			(5,905		)	—			(5,905		)
Other (primarily stock compensation)	3,634			—			3,634			15,010			—			15,010
Dividends on common stock	(125,265		)	—			(125,265		)	(119,885		)	—			(119,885		)
Net capital activities by noncontrolling interests	—			(15,869		)	(15,869		)	—			(9,196		)	(9,196		)
Ending balance, June 30	$	4,233,890		$	147,972		$	4,381,862		$	4,032,165		$	137,070		$	4,169,235

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9. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

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

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.6 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers. 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 $20 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 $54 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

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Contractual Obligations

There have been no material changes as of June 30, 2014 outside the normal course of business in contractual obligations from the information provided in our 2013 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

On July 7, 2014, APS notified the Palo Verde Sale Leaseback lessor trust entities of APS’s intent to exercise fixed rate lease renewal options. Under the extended lease terms, APS will be required to make lease payments to the lessors of approximately $23 million annually for the period 2016 through 2023, and about $16 million annually for the period 2024 through 2033. See Note 6.

Superfund-Related Matters

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

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

Southwest Power Outage

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

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

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

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

On July 7, 2014, FERC approved a Stipulation and Consent Agreement among FERC’s Office of Enforcement, NERC and APS which resolves all civil and administrative disputes within the jurisdiction of FERC concerning the September 8 event, including FERC’s and NERC’s investigations. In the settlement, APS neither admitted nor denied alleged violations of four Reliability Standard Requirements. APS agreed to pay a civil penalty of $3.25 million, of which $2 million is to be paid in equal parts to the Department of the Treasury and NERC and $1.25 million will be credited as a partial civil penalty offset in exchange for APS completing certain reliability enhancements.

Litigation. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision. The appeal is now pending before the Ninth Circuit Court of Appeals. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Clean Air Act Citizen Lawsuit

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review (“NSR”) provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards (“NSPS”) program. Among other things, the environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default. We are unable to determine a range of potential losses that are reasonably possible of occurring.

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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 rulemakings imposing new requirements on Four Corners and the Cholla Power Plant (“Cholla”) and the Navajo Generating Station (“Navajo Plant.”) EPA and Arizona Department of Environmental Quality (“ADEQ”) will require these plants to install pollution control equipment that constitutes the “best available retrofit technology” (“BART”) to lessen the impacts of emissions on visibility surrounding the plants. Based on EPA’s final standards, APS’s 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $350 million. APS’s share of costs for upgrades at Navajo, based on EPA’s Federal Implementation Plan (“FIP”), could be up to approximately $200 million. APS has filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, will require installation of controls with a cost to APS of approximately $200 million.

Mercury and Other Hazardous Air Pollutants. In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla Units 2 and 3. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. Salt River Project Agricultural Improvement and Power District (“SRP”), the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, greenhouse gas (“GHG”) emissions (such as the EPA’s proposed “Clean Power Plan” rule issued in accordance with President Obama’s Climate Action Plan), and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Regional Haze Rules — Cholla

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan (“SIP”) and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.

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Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014, and the parties are waiting for the court to schedule oral argument.

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million. For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. APS believes the Assessment and the refund claim denial are without merit, but cannot predict the timing or outcome of this litigation.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes. At June 30, 2014, approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. One of these letters of credit expires in 2015 and two expire in 2016. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire on December 31, 2015, and totaled approximately $24 million at June 30, 2014. 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 June 30, 2014, that letter of credit totaled $5 million and will expire in 2014.

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

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2014.

10. Other Income and Other Expense

The following table provides detail of other income and other expense for the three and six months ended June 30, 2014 and 2013 (dollars in thousands):

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	Three Months Ended June 30,						Six Months Ended June 30
	2014			2013			2014			2013
Other income:
Interest income	$	495		$	467		$	746		$	1,176
Miscellaneous	2,286			2			4,402			51
Total other income	$	2,781		$	469		$	5,148		$	1,227

Other expense:
Non-operating costs	$	(2,620	)	$	(1,990	)	$	(4,992	)	$	(3,923	)
Investment losses — net	(105		)	(96		)	(246		)	(208		)
Miscellaneous	2,217			(148		)	46			(1,855		)
Total other expense	$	(508	)	$	(2,234	)	$	(5,192	)	$	(5,986	)

11. Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2014 and 2013 (in thousands, except per share amounts):

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013

Net income attributable to common shareholders	$	132,458	$	131,207	$	148,224	$	155,651
Average common shares outstanding — basic	110,565		109,962		110,546		109,898
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	437		970		379		945
Average common shares outstanding — diluted	111,002		110,932		110,925		110,843
Earnings per average common share attributable to common shareholders — basic	$	1.20	$	1.19	$	1.34	$	1.42
Earnings per average common share attributable to common shareholders — diluted	$	1.19	$	1.18	$	1.34	$	1.40

12. Fair Value Measurements

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

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

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

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

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

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 in the 2013 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

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

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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 Trusts

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

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

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed

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instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.

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

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Fair Value Tables

The following table presents the fair value at June 30, 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 June 30, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	17		$	33		$	(13	)(b)	$	37
Nuclear decommissioning trust:
U.S. commingled equity funds	—		291			—			—			291
Fixed income securities:
U.S. Treasury	122		—			—			—			122
Cash and cash equivalent funds	—		9			—			(5		)(c)	4
Corporate debt	—		106			—			—			106
Mortgage-backed securities	—		82			—			—			82
Municipality bonds	—		63			—			—			63
Other	—		14			—			—			14
Subtotal nuclear decommissioning trust	122		565			—			(5		)	682
Total	$	122	$	582		$	33		$	(18	)	$	719

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(19	)	$	(75	)	$	49	(b)	$	(45	)

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

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

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The following table presents the fair value at December 31, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at December 31, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	9		$	41		$	(9	)(b)	$	41
Nuclear decommissioning trust:
U.S. commingled equity funds	—		272			—			—			272
Fixed income securities:
U.S. Treasury	107		—			—			—			107
Cash and cash equivalent funds	—		11			—			(3		)(c)	8
Corporate debt	—		88			—			—			88
Mortgage-backed securities	—		85			—			—			85
Municipality bonds	—		71			—			—			71
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	107		538			—			(3		)	642
Total	$	107	$	547		$	41		$	(12	)	$	683

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(33	)	$	(90	)	$	21	(b)	$	(102	)

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

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

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.

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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 June 30, 2014 and December 31, 2013:

	June 30, 2014 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	29	$	52	Discounted cash flows	Electricity forward price (per MWh)	$25.27 - $73.70	$	42.78

Option Contracts (b)	—		20		Option model	Electricity forward price (per MWh)	$40.56 - $94.30	$	62.18
						Natural gas forward price (per MMBtu)	$3.93 - $4.04	$	4.00
						Electricity price volatilities	23% - 111%	53		%
						Natural gas price volatilities	23% - 49%	31		%
Natural Gas:
Forward Contracts (a)	4		3		Discounted cash flows	Natural gas forward price (per MMBtu)	$3.87 - $4.45	$	4.07
Total	$	33	$	75

(a) Includes swaps and physical and financial contracts.

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

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	December 31, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	40	$	66	Discounted cash flows	Electricity forward price (per MWh)	$24.89 - $65.04	$	41.09

Option Contracts (b)	—		19		Option model	Electricity forward price (per MWh)	$39.91 - $85.41	$	58.70
						Natural gas forward price (per MMBtu)	$3.57 - $3.80	$	3.71
						Electricity price volatilities	35% - 94%	59		%
						Natural gas price volatilities	22% - 36%	27		%
Natural Gas:
Forward Contracts (a)	1		5		Discounted cash flows	Natural gas forward price (per MMBtu)	$3.47 - $4.31	$	3.87
Total	$	41	$	90

(a) Includes swaps and physical and financial contracts.

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

The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2014 and 2013 (dollars in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2014			2013			2014			2013
Net derivative balance at beginning of period	$	(49	)	$	(53	)	$	(49	)	$	(48	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	3			(4		)	6			(5		)
Settlements	4			4			5			2
Transfers into Level 3 from Level 2	1			—			(2		)	(1		)
Transfers from Level 3 into Level 2	—			—			(1		)	(1		)
Net derivative balance at end of period	$	(41	)	$	(53	)	$	(41	)	$	(53	)

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

Amounts included in earnings are either recorded in operating revenues or 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

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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 any short-term borrowings approximate fair value. Our short-term borrowings are classified within Level 2 of the fair value hierarchy. For our long-term debt fair values, see Note 2.

13. Nuclear Decommissioning Trusts

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. See Note 12 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2014 and December 31, 2013 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2014
Equity securities	$	291		$	145	$	—
Fixed income securities	396			16		(1		)
Net payables (a)	(5		)	—		—
Total	$	682		$	161	$	(1	)

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

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

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Realized gains	$	1		$	1		$	2		$	3
Realized losses	(1		)	(1		)	(3		)	(2		)
Proceeds from the sale of securities (a)	96			119			199			254

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2014 is as follows (dollars in millions):

	Fair Value
Less than one year	$	22
1 year – 5 years	118
5 years – 10 years	109
Greater than 10 years	147
Total	$	396

14. New Accounting Standards

During 2014, we adopted, on a prospective basis, new guidance relating to the presentation of unrecognized tax benefits. This guidance generally requires entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. Prior to adopting this guidance, we presented unrecognized tax benefits on a gross basis. The adoption of this new guidance changed our balance sheet presentation of unrecognized tax benefits, but did not impact our operating results or cash flows. See Note 5 for details regarding the impacts of adopting this guidance.

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, including industry-specific guidance. The new guidance is effective for us on January 1, 2017, and may be adopted using 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. We are currently evaluating this new guidance and the impacts it may have on our financial statements.

15. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2014 and 2013 (dollars in thousands):

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	Three Months Ended June 30, 2014									Three Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total

Beginning balance, April 1	$	(20,364	)	$	(54,538	)	$	(74,902	)	$	(44,481	)	$	(63,450	)	$	(107,931	)

OCI (loss) before reclassifications	40			(2,072		)	(2,032		)	(160		)	(1,635		)	(1,795		)
Amounts reclassified from accumulated other comprehensive loss	1,955		(a)	762		(b)	2,717			4,322		(a)	947		(b)	5,269
Net current period OCI (loss)	1,995			(1,310		)	685			4,162			(688		)	3,474

Ending balance, June 30	$	(18,369	)	$	(55,848	)	$	(74,217	)	$	(40,319	)	$	(64,138	)	$	(104,457	)

(a) These amounts represent realized gains and losses, 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.

	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total

Beginning balance, January 1	$	(23,058	)	$	(54,995	)	$	(78,053	)	$	(49,592	)	$	(64,416	)	$	(114,008	)

OCI (loss) before reclassifications	(381		)	(2,072		)	(2,453		)	(102		)	(1,635		)	(1,737		)
Amounts reclassified from accumulated other comprehensive loss	5,070		(a)	1,219		(b)	6,289			9,375		(a)	1,913		(b)	11,288
Net current period OCI (loss)	4,689			(853		)	3,836			9,273			278			9,551

Ending balance, June 30	$	(18,369	)	$	(55,848	)	$	(74,217	)	$	(40,319	)	$	(64,138	)	$	(104,457	)

(a) These amounts represent realized gains and losses, 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.

16. Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. During the fourth quarter of 2013, a new decommissioning study with updated cash flow estimates was completed for Palo Verde. During the second quarter of 2014, an update to the 2013

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decommissioning study was completed for Palo Verde to incorporate additional fuel related charges. An update was made in the amount of $20 million.

The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term. The Four Corners coal-fired power plant asset retirement obligation relates to final plant decommissioning, including ash pond closures. In the fourth quarter of 2012, a new study related to ash pond closure was completed which updated the total costs estimates and related cash flows. In the fourth quarter of 2013, APS finalized the transaction to acquire SCE’s interest in Four Corners. As part of that transaction, APS assumed SCE’s asset retirement obligation. Also, APS retired Four Corners Units 1-3 on December 30, 2013. Decommissioning activities began for Units 1-3 in January 2014. An update was made to the timing of the Units 1-3 decommissioning cash flows to coincide with the expected decommissioning activities. In the first quarter of 2014, the Four Corners Units 1-3 decommissioning study was finalized and approved and an update was made in the amount of $24 million.

Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.

Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2014 (dollars in millions):

Asset retirement obligations at January 1, 2014	$	347
Changes attributable to:
Accretion expense	11
Settlements	(10		)
Estimated cash flow revisions	44
Asset retirement obligations at June 30, 2014	$	392

Decommissioning activities for Four Corners Units 1-3 began in January 2014; thus, $35.7 million of the total asset retirement obligation of $392 million at June 30, 2014, 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 June 30,
	2014			2013

ELECTRIC OPERATING REVENUES	$	905,578		$	915,065

OPERATING EXPENSES
Fuel and purchased power	290,854			277,584
Operations and maintenance	208,059			224,950
Depreciation and amortization	105,127			106,268
Income taxes	77,371			81,952
Taxes other than income taxes	43,773			40,583
Total	725,184			731,337
OPERATING INCOME	180,394			183,728

OTHER INCOME (DEDUCTIONS)
Income taxes	1,568			3,100
Allowance for equity funds used during construction	7,499			6,265
Other income (Note S-2)	3,221			948
Other expense (Note S-2)	(1,477		)	(4,844		)
Total	10,811			5,469

INTEREST EXPENSE
Interest on long-term debt	48,462			47,543
Interest on short-term borrowings	1,637			1,968
Debt discount, premium and expense	1,054			982
Allowance for borrowed funds used during construction	(3,790		)	(3,636		)
Total	47,363			46,857

NET INCOME	143,842			142,340

Less: Net income attributable to noncontrolling interests (Note 6)	8,926			8,391

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	134,916		$	133,949

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 June 30,
	2014			2013

NET INCOME	$	143,842		$	142,340

OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(26) and $105	40			(160		)
Reclassification of net realized loss, net of tax benefit of $1,261 and $2,824	1,954			4,322
Pension and other postretirement benefits activity, net of tax benefit of $828 and $399	(1,283		)	(611		)
Total other comprehensive income	711			3,551

COMPREHENSIVE INCOME	144,553			145,891
Less: Comprehensive income attributable to noncontrolling interests	8,926			8,391

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	135,627		$	137,500

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2014			2013

ELECTRIC OPERATING REVENUES	$	1,591,123		$	1,600,892

OPERATING EXPENSES
Fuel and purchased power	540,640			508,263
Operations and maintenance	416,344			445,702
Depreciation and amortization	206,875			209,974
Income taxes	87,849			98,012
Taxes other than income taxes	89,386			80,351
Total	1,341,094			1,342,302
OPERATING INCOME	250,029			258,590

OTHER INCOME (DEDUCTIONS)
Income taxes	2,778			5,432
Allowance for equity funds used during construction	14,941			13,129
Other income (Note S-2)	5,983			2,291
Other expense (Note S-2)	(6,533		)	(11,140		)
Total	17,169			9,712

INTEREST EXPENSE
Interest on long-term debt	97,358			93,764
Interest on short-term borrowings	3,050			3,397
Debt discount, premium and expense	2,065			1,993
Allowance for borrowed funds used during construction	(7,560		)	(7,626		)
Total	94,913			91,528

NET INCOME	172,285			176,774

Less: Net income attributable to noncontrolling interests (Note 6)	17,851			16,783

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	154,434		$	159,991

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)

	Six Months Ended June 30,
	2014			2013

NET INCOME	$	172,285		$	176,774

OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $(624) and $67	(381		)	(102		)
Reclassification of net realized loss, net of tax benefit of $2,584 and $6,124	5,070			9,374
Pension and other postretirement benefits activity, net of tax benefit (expense) of $222 and $(177)	(717		)	271
Total other comprehensive income	3,972			9,543

COMPREHENSIVE INCOME	176,257			186,317
Less: Comprehensive income attributable to noncontrolling interests	17,851			16,783

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	158,406		$	169,534

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)

	June 30,			December 31,
	2014			2013
ASSETS

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	15,444,835		$	15,196,598
Accumulated depreciation and amortization	(5,385,579		)	(5,296,501		)
Net	10,059,256			9,900,097

Construction work in progress	584,152			581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	123,190			125,125
Intangible assets, net of accumulated amortization	136,882			157,534
Nuclear fuel, net of accumulated amortization	125,246			124,557
Total property, plant and equipment	11,028,726			10,888,682

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 13)	682,359			642,007
Assets from risk management activities (Note 7)	21,581			23,815
Other assets	34,387			33,709
Total investments and other assets	738,327			699,531

CURRENT ASSETS
Cash and cash equivalents	9,082			3,725
Customer and other receivables	325,119			299,055
Accrued unbilled revenues	172,444			96,796
Allowance for doubtful accounts	(2,731		)	(3,203		)
Materials and supplies (at average cost)	230,310			221,682
Fossil fuel (at average cost)	38,835			38,028
Income tax receivable (Note 5)	—			135,179
Assets from risk management activities (Note 7)	15,420			17,169
Deferred fuel and purchased power regulatory asset (Note 3)	1,043			20,755
Other regulatory assets (Note 3)	77,148			76,388
Deferred income taxes	3,390			—
Other current assets	47,797			39,153
Total current assets	917,857			944,727

DEFERRED DEBITS
Regulatory assets (Note 3)	755,174			711,712
Unamortized debt issue costs	24,410			21,860
Other	115,966			114,865
Total deferred debits	895,550			848,437

TOTAL ASSETS	$	13,580,460		$	13,381,377

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30,			December 31,
	2014			2013
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,833,635			1,804,398
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(31,030		)	(30,313		)
Derivative instruments	(18,370		)	(23,059		)
Total shareholder equity	4,342,093			4,308,884
Noncontrolling interests (Note 6)	147,972			145,990
Total equity (Note S-1)	4,490,065			4,454,874
Long-term debt less current maturities (Note 2)	2,874,513			2,671,465
Total capitalization	7,364,578			7,126,339

CURRENT LIABILITIES
Short-term borrowings (Note 2)	172,775			153,125
Current maturities of long-term debt (Note 2)	368,841			540,424
Accounts payable	315,240			281,237
Accrued taxes (Note 5)	160,841			122,460
Accrued interest	52,520			48,132
Common dividends payable	62,600			62,500
Customer deposits	74,779			76,101
Deferred income taxes	—			2,033
Liabilities from risk management activities (Note 7)	21,502			31,892
Liabilities for asset retirements	35,726			32,896
Regulatory liabilities (Note 3)	114,204			99,273
Other current liabilities	148,676			130,774
Total current liabilities	1,527,704			1,580,847

DEFERRED CREDITS AND OTHER
Deferred income taxes	2,392,061			2,347,724
Regulatory liabilities (Note 3)	809,442			801,297
Liabilities for asset retirements (Note 16)	356,436			313,833
Liabilities for pension and other postretirement benefits (Note 4)	403,690			476,017
Liabilities from risk management activities (Note 7)	23,367			70,315
Customer advances	120,330			114,480
Coal mine reclamation	208,951			207,453
Deferred investment tax credit	181,236			152,361
Unrecognized tax benefits (Note 5)	36,994			42,209
Other	155,671			148,502
Total deferred credits and other	4,688,178			4,674,191

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

TOTAL LIABILITIES AND EQUITY	$	13,580,460		$	13,381,377

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

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	172,285		$	176,774
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	246,324			249,434
Deferred fuel and purchased power	1,315			36,183
Deferred fuel and purchased power amortization	18,399			10,921
Allowance for equity funds used during construction	(14,941		)	(13,129		)
Deferred income taxes	34,133			66,947
Deferred investment tax credit	28,875			20,159
Change in derivative instruments fair value	49			349
Changes in current assets and liabilities:
Customer and other receivables	(65,603		)	(80,854		)
Accrued unbilled revenues	(75,648		)	(68,763		)
Materials, supplies and fossil fuel	(9,435		)	(4,002		)
Income tax receivable	135,179			296
Other current assets	(14,120		)	(14,067		)
Accounts payable	28,465			86,338
Accrued taxes	38,381			12,596
Other current liabilities	31,296			(28,506		)
Change in margin and collateral accounts — assets	(2,107		)	(1,111		)
Change in margin and collateral accounts — liabilities	(22,425		)	14,600
Change in other long-term assets	(18,703		)	(21,658		)
Change in other long-term liabilities	(24,467		)	26,628
Net cash flow provided by operating activities	487,252			469,135

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(388,752		)	(376,601		)
Contributions in aid of construction	12,646			21,236
Allowance for borrowed funds used during construction	(7,560		)	(7,626		)
Proceeds from nuclear decommissioning trust sales	199,224			253,996
Investment in nuclear decommissioning trust	(207,848		)	(262,621		)
Other	(678		)	(270		)
Net cash flow used for investing activities	(392,968		)	(371,886		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	535,975			136,307
Short-term borrowings — net	19,650			(62,075		)
Repayment of long-term debt	(503,583		)	(40,127		)
Dividends paid on common stock	(125,100		)	(119,700		)
Noncontrolling interests	(15,869		)	(9,197		)
Net cash flow used for financing activities	(88,927		)	(94,792		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	5,357			2,457
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,725			3,499
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	9,082		$	5,956

Supplemental disclosure of cash flow information
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(134,399	)	$	—
Interest, net of amounts capitalized	$	88,461		$	89,676
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	19,668		$	8,904
Dividends declared but not yet paid	$	62,600		$	59,900

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

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

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

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. Changes in Equity

The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three and six months ended June 30, 2014 and 2013 (dollars in thousands):

	Three Months Ended June 30, 2014									Three Months Ended June 30, 2013
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total

Beginning balance, April 1	$	4,331,661		$	154,915		$	4,486,576		$	4,125,032		$	137,875		$	4,262,907

Net income	134,916			8,926			143,842			133,949			8,391			142,340
OCI	711			—			711			3,551			—			3,551
Total comprehensive income	135,627			8,926			144,553			137,500			8,391			145,891

Dividends on common stock	(125,200		)	—			(125,200		)	(119,800		)	—			(119,800		)
Net capital activities by noncontrolling interests	—			(15,869		)	(15,869		)	—			(9,196		)	(9,196		)
Other	5			—			5			(6		)	—			(6		)
Ending balance, June 30	$	4,342,093		$	147,972		$	4,490,065		$	4,142,726		$	137,070		$	4,279,796

	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total

Beginning balance, January 1	$	4,308,884		$	145,990		$	4,454,874		$	4,093,000		$	129,483		$	4,222,483

Net income	154,434			17,851			172,285			159,991			16,783			176,774
OCI	3,972			—			3,972			9,543			—			9,543
Total comprehensive income	158,406			17,851			176,257			169,534			16,783			186,317

Dividends on common stock	(125,200		)	—			(125,200		)	(119,800		)	—			(119,800		)
Net capital activities by noncontrolling interests	—			(15,869		)	(15,869		)	—			(9,196		)	(9,196		)
Other	3			—			3			(8		)	—			(8		)
Ending balance, June 30	$	4,342,093		$	147,972		$	4,490,065		$	4,142,726		$	137,070		$	4,279,796

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-2. Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2014 and 2013 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Other income:
Interest income	$	417		$	403		$	554		$	1,059
Miscellaneous	2,804			545			5,429			1,232
Total other income	$	3,221		$	948		$	5,983		$	2,291

Other expense:
Non-operating costs (a)	$	(2,868	)	$	(2,285	)	$	(5,455	)	$	(4,605	)
Asset dispositions	(285		)	(1,397		)	(468		)	(2,661		)
Miscellaneous	1,676			(1,162		)	(610		)	(3,874		)
Total other expense	$	(1,477	)	$	(4,844	)	$	(6,533	)	$	(11,140	)

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

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-3. Changes in Accumulated Other Comprehensive Loss

	Three Months Ended June 30, 2014									Three Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total

Beginning balance, April 1	$	(20,364	)	$	(29,747	)	$	(50,111	)	$	(44,482	)	$	(38,621	)	$	(83,103	)

OCI (loss) before reclassifications	40			(2,041		)	(2,001		)	(160		)	(1,630		)	(1,790		)
Amounts reclassified from accumulated other comprehensive loss	1,954		(a)	758		(b)	2,712			4,322		(a)	1,019		(b)	5,341
Net current period OCI (loss)	1,994			(1,283		)	711			4,162			(611		)	3,551

Ending balance, June 30	$	(18,370	)	$	(31,030	)	$	(49,400	)	$	(40,320	)	$	(39,232	)	$	(79,552	)

(a) These amounts represent realized gains and losses, 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.

	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013
	Derivative Instruments			Pension and Other Postretirement Benefits			Total			Derivative Instruments			Pension and Other Postretirement Benefits			Total

Beginning balance, January 1	$	(23,059	)	$	(30,313	)	$	(53,372	)	$	(49,592	)	$	(39,503	)	$	(89,095	)

OCI (loss) before reclassifications	(381		)	(2,041		)	(2,422		)	(102		)	(1,630		)	(1,732		)
Amounts reclassified from accumulated other comprehensive loss	5,070		(a)	1,324		(b)	6,394			9,374		(a)	1,901		(b)	11,275
Net current period OCI (loss)	4,689			(717		)	3,972			9,272			271			9,543

Ending balance, June 30	$	(18,370	)	$	(31,030	)	$	(49,400	)	$	(40,320	)	$	(39,232	)	$	(79,552	)

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

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

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

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Part 1, Item 1A of the 2013 Form 10-K.

OVERVIEW

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

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

Nuclear. APS operates and is a joint owner of Palo Verde. The March 2011 earthquake and tsunamis in Japan and the resulting accident at Japan’s Fukushima Daiichi nuclear power station had a significant impact on nuclear power operators worldwide. In the aftermath of the accident, the NRC conducted an independent assessment to consider actions to ensure that its regulations reflect lessons learned from the Fukushima events. As a result of the Fukushima event, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force. In response to these recommendations, Palo Verde expects to spend approximately $120 million for capital enhancements to the plant over the next several years (APS’s share is 29.1%).

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

Coal and Related Environmental Matters and Transactions. APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning 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 June 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 is closely monitoring its long-range capital management plans, understanding that any resulting regulation and

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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.

Four Corners

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

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

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

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

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federal environmental review is underway as part of the DOI review process. In March 2014, APS received a draft of the environmental impact statement (“DEIS”) in connection with the DOI review process. As a proponent of the Four Corners Power Plant and Navajo Mine Energy Project, APS, along with other members of the public, submitted comments on the DEIS. APS will also require a Prevention of Significant Deterioration (“PSD”) permit from EPA to install SCR control technology at Four Corners. APS cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners.

Transmission and Delivery. APS is working closely with regulators to identify and plan for transmission needs that continue to support system reliability, access to markets and renewable energy development. The capital expenditures table presented in the “Liquidity and Capital Resources” section below includes new APS transmission projects through 2016, along with other transmission costs for upgrades and replacements. APS is also working to establish and expand smart grid technologies throughout its service territory to provide long-term benefits both to APS and its customers. APS is strategically deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations, as well as the number of customers that experience outages, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

Renewable Energy. The ACC approved the RES in 2006. The renewable energy requirement is 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025. In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 1,700 GWh of new renewable resources to be in service by year-end 2015, in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is currently estimated to be approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year. A component of the RES targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million.

The following table summarizes APS’s renewable energy sources in operation and under development as of July 31, 2014.

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	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar (a)	169	20

Purchased Power Agreements:
Solar (b)	310	—
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	629	—

Total Distributed Energy: Solar (c)	359	34

Total Renewable Portfolio	1,157	54

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

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

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 $690 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.

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 program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 20 MW of APS-owned residential solar.

Demand Side Management. In December 2009, Arizona regulators placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. The ACC initiated an Energy Efficiency rulemaking, with a proposed EES of 22% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. This ambitious standard became effective on January 1, 2011.

On June 1, 2012, APS filed its 2013 DSM Plan. In 2013, the standards require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan. The ACC approved a budget of $68.9 million for each of 2013 and 2014. The ACC also approved a Resource

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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.

Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by FERC. On June 1, 2011, APS filed a rate case with the ACC. APS and other parties to the retail rate case subsequently entered into the 2012 Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. See Note 3 for details regarding the 2012 Settlement Agreement terms and for information on APS’s FERC rates.

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

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

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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. Workshops in this docket are being held in 2014.

Net Metering. On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

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

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

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Key Financial Drivers

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

Electric Operating Revenues. For the years 2011 through 2013, retail electric revenues comprised approximately 93% of our total electric operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth. Retail customers in APS’s service territory increased 1.3% for the six-month period ended June 30, 2014 compared with the prior-year period. For the three years 2011 through 2013, APS’s customer growth averaged 1.0% per year. We currently expect annual customer growth to average about 2.5% for 2014 through 2016 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.8% for the six-month period ended June 30, 2014 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 2011 through 2013, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kWh will increase on average about 1% during 2014 through 2016, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. A failure of the Arizona economy to improve could further impact these estimates.

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

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

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

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Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors. In the 2009 Settlement Agreement, APS committed to operational expense reductions from 2010 through 2014, and received approval to defer certain pension and other postretirement benefit cost increases incurred in 2011 and 2012, which totaled $25 million, as a regulatory asset, until the most recent general retail rate case decision became effective on July 1, 2012. In July 2012, we began amortizing the regulatory asset over a 36-month period.

Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” below for information regarding the planned additions to our facilities. See Note 3 regarding deferral of certain costs pursuant to an ACC order.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.5% of the assessed value for 2013 and 9.6% for 2012. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities. (See Note 3 for property tax deferrals contained in the 2012 Settlement Agreement).

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

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

RESULTS OF OPERATIONS

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

Operating Results — Three-month period ended June 30, 2014 compared with three-month period ended June 30, 2013.

Our consolidated net income attributable to common shareholders for the three months ended June 30, 2014 was $132 million, compared with consolidated net income of $131 million for the prior-year period. The results reflect an increase of approximately $2 million for the regulated electricity segment primarily related to lower operations and maintenance expenses resulting from lower

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employee benefit costs, and higher other income. These positive factors were partially offset by lower retail sales due to changes in customer usage patterns and related pricing, and the effects of weather.

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

	Three Months Ended June 30,
	2014			2013			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	615		$	637		$	(22	)
Operations and maintenance	(211		)	(229		)	18
Depreciation and amortization	(105		)	(106		)	1
Taxes other than income taxes	(44		)	(41		)	(3		)
All other income and expenses, net	10			3			7
Interest charges, net of allowance for borrowed funds used during construction	(48		)	(48		)	—
Income taxes	(75		)	(77		)	2
Less income related to noncontrolling interests (Note 6)	(9		)	(8		)	(1		)
Regulated electricity segment net income	133			131			2
All other	(1		)	—			(1		)
Net Income Attributable to Common Shareholders	$	132		$	131		$	1

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $22 million lower for the three months ended June 30, 2014 compared with the prior-year period. The following table summarizes the major components of this change:

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

Higher renewable energy regulatory surcharges and purchased power, offset by lower demand side management regulatory surcharges	$	—		$	8		$	(8	)
Lower retail sales due to changes in customer usage patterns and related pricing, partially offset by customer growth	(12		)	(5		)	(7		)
Effects of weather	(9		)	(3		)	(6		)
Higher net fuel and purchased power costs, including related deferrals and higher off-system sales	9			11			(2		)
Miscellaneous items, net	3			2			1
Total	$	(9	)	$	13		$	(22	)

Operations and maintenance. Operations and maintenance expenses decreased $18 million for the three months ended June 30, 2014 compared with the prior-year period primarily because of:

· A decrease of $14 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues and purchased power;

· A decrease of $5 million related to lower employee benefit costs; and

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

All other income and expenses, net. All other income and expenses, net, increased $7 million for the three months ended June 30, 2014 compared with the prior-year period primarily due to interest income and other non-operating income.

Six-month period ended June 30, 2014 compared with six-month period ended June 30, 2013.

Our consolidated net income attributable to common shareholders for the six months ended June 30, 2014 was $148 million, compared with consolidated net income of $156 million for the prior-year period. The results reflect a decrease of approximately $7 million for the regulated electricity segment primarily related to the effects of weather, lower retail transmission revenues, and higher property taxes. These negative factors were partially offset by lower operations and maintenance expenses related to lower employee benefit costs, higher other income, and lower income taxes.

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

	Six Months Ended June 30,
	2014			2013			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,051		$	1,093		$	(42	)
Operations and maintenance	(424		)	(453		)	29
Depreciation and amortization	(207		)	(210		)	3
Taxes other than income taxes	(90		)	(81		)	(9		)
All other income and expenses, net	15			7			8
Interest charges, net of allowance for borrowed funds used during construction	(97		)	(93		)	(4		)
Income taxes	(81		)	(90		)	9
Less income related to noncontrolling interests (Note 6)	(18		)	(17		)	(1		)
Regulated electricity segment net income	149			156			(7		)

All other	(1		)	—			(1		)
Net Income Attributable to Common Shareholders	$	148		$	156		$	(8	)

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $42 million lower for the six months ended June 30, 2014 compared with the prior-year period. The following table summarizes the major components of this change:

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

Effects of weather	$	(45	)	$	(16	)	$	(29	)
Lower retail transmission revenues	(9		)	—			(9		)
Higher renewable energy regulatory surcharges and purchased power, offset by lower demand side management regulatory surcharges	6			13			(7		)
Lower retail sales due to changes in customer usage patterns and related pricing, partially offset by customer growth	(9		)	(3		)	(6		)
Higher net fuel and purchased power costs, including related deferrals and higher off-system sales	38			39			(1		)
Lost fixed cost recovery	7			—			7
Miscellaneous items, net	2			(1		)	3
Total	$	(10	)	$	32		$	(42	)

Operations and maintenance. Operations and maintenance expenses decreased $29 million for the six months ended June 30, 2014 compared with the prior-year period primarily because of:

· A decrease of $16 million related to lower employee benefit costs; and

· A decrease of $13 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues and purchased power.

Taxes other than income taxes. Taxes other than income taxes were $9 million higher for the six months ended June 30, 2014 compared with the prior-year period primarily due to higher property tax rates and higher plant balances.

All other income and expenses, net. All other income and expenses, net, were $8 million higher for the six months ended June 30, 2014 compared with the prior-year period primarily due to interest income and other non-operating income.

Income taxes. Income taxes were $9 million lower for the six months ended June 30, 2014 compared with the prior-year period primarily due to lower pretax income.

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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 June 30, 2014, APS’s common equity ratio, as defined, was 58%. Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

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

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the six months ended June 30, 2014 and 2013 (dollars in millions):

Pinnacle West Consolidated

	Six Months Ended June 30						Net
	2014			2013			Change
Net cash flow provided by operating activities	$	465		$	454		$	11
Net cash flow used for investing activities	(393		)	(372		)	(21		)
Net cash flow used for financing activities	(72		)	(80		)	8
Net increase in cash and cash equivalents	$	—		$	2		$	(2	)

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Arizona Public Service Company

	Six Months Ended June 30						Net
	2014			2013			Change
Net cash flow provided by operating activities	$	487		$	469		$	18
Net cash flow used for investing activities	(393		)	(372		)	(21		)
Net cash flow used for financing activities	(89		)	(95		)	6
Net increase in cash and cash equivalents	$	5		$	2		$	3

Operating Cash Flows

Six-month period ended June 30, 2014 compared with six-month period ended June 30, 2013. Pinnacle West’s consolidated net cash provided by operating activities was $465 million in 2014 compared to $454 million in 2013, an increase of $11 million in net cash provided. The increase is primarily related to a $135 million income tax refund received in the first quarter of 2014, partially offset by $49 million of higher pension contributions in the six month-period ended June 30, 2014 (approximately $6 million of which is reflected in capital expenditures), a $38 million change in cash collateral posted, $35 million in higher fuel and purchased power costs, and other working capital.

Other. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was 107% funded as of January 1, 2013 and is estimated to be approximately 103% funded as of January 1, 2014. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. The minimum contributions for the pension plan total $141 million for the next three years under the Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015 and $122 million in 2016). However, we expect to make voluntary contributions totaling up to $300 million for the next three years ($175 million in 2014, of which $140 million was already contributed through July 2014, up to $100 million in 2015, and up to $25 million in 2016). The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

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

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Investing Cash Flows

Six-month period ended June 30, 2014 compared with six-month period ended June 30, 2013. Pinnacle West’s consolidated net cash used for investing activities was $393 million in 2014, compared to $372 million in 2013, an increase of $21 million in net cash used primarily related to increased capital expenditures.

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

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2014		2015		2016
APS
Generation:
Nuclear Fuel	$	75	$	86	$	88
Renewables	131		8		—
Environmental	22		58		212
New Gas Generation	2		42		129
Other Generation	220		205		227
Distribution	230		373		363
Transmission	177		213		196
Other (a)	74		41		48
Total APS	$	931	$	1,026	$	1,263

(a) Primarily information systems and facilities projects.

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

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.

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

Financing Cash Flows and Liquidity

Six-month period ended June 30, 2014 compared with six-month period ended June 30, 2013. Pinnacle West’s consolidated net cash used for financing activities was $72 million in 2014, compared to $80 million in 2013, a decrease of $8 million in net cash used. The decrease in net cash used for financing activities is primarily due to $400 million in higher issuances of long-term debt and an $86 million net change in short-term borrowings, partially offset by $463 million in higher repayments of long-term debt (see below).

Significant Financing Activities. On June 18, 2014, the Pinnacle West Board of Directors declared a dividend of $0.5675 per share of common stock, payable on September 2, 2014 to shareholders of record on August 1, 2014.

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

On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E due 2029 in connection with the mandatory tender provisions for this indebtedness. On May 14, 2014, APS remarketed all $36 million of the 2009 Series A Bonds, which are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2014. We expect to remarket or refinance all $64 million of the 2009 Series D Bonds and 2009 Series E Bonds within the next twelve months, which were classified as current maturities of long-term debt at December 31, 2013.

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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.

On May 9, 2014, APS replaced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019.

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

Other Financing Matters.

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

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

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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 June 30, 2014, the ratio was approximately 46% 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.

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 July 25, 2014 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings 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.

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

Off-Balance Sheet Arrangements

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

Contractual Obligations

There have been no material changes, as of June 30, 2014, outside the normal course of business in contractual obligations from the information provided in our 2013 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

On July 7, 2014, APS notified the Palo Verde sale leaseback lessor trust entities of APS’s intent to exercise fixed rate lease renewal options. Under the extended lease terms, APS will be required to make lease payments to the lessors of approximately $23 million annually for the period 2016 through 2023, and about $16 million annually for the period 2024 through 2033. See Note 6.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. There have been no changes to our critical accounting policies since our 2013 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2013 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

During 2014, we adopted new accounting guidance relating to the balance sheet presentation of certain unrecognized tax benefits. In addition, we are currently evaluating new revenue recognition guidance that we will be adopting on January 1, 2017. See Note 14.

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MARKET AND CREDIT RISKS

Market Risks

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

Interest Rate and Equity Risk

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

Commodity Price Risk

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

The following table shows the net pretax changes in mark-to-market of our derivative positions for the six months ended June 30, 2014 and 2013 (dollars in millions):

	Six Months Ended June 30,
	2014			2013
Mark-to-market of net positions at beginning of year	$	(73	)	$	(122	)
Decrease (increase) in regulatory asset/liability	21			(3		)
Recognized in OCI:
Mark-to-market losses realized during the period	8			16
Change in valuation techniques	—			—
Mark-to-market of net positions at end of year	$	(44	)	$	(109	)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at June 30, 2014 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” in Item 8 of our 2013 Form 10-K and Note 12 for more discussion of our valuation methods.

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Source of Fair Value	2014			2015			2016			2017			2018			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(2	)	$	(1	)	$	(1	)	$	1		$	—		$	—		$	(3	)
Prices based on unobservable inputs	(7		)	(14		)	(9		)	(4		)	(3		)	(4		)	(41		)
Total by maturity	$	(9	)	$	(15	)	$	(10	)	$	(3	)	$	(3	)	$	(4	)	$	(44	)

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 June 30, 2014 and December 31, 2013 (dollars in millions):

	June 30, 2014 Gain (Loss)					December 31, 2013 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings (a)
Natural gas	$	—	$	—		$	—	$	—
Regulatory asset (liability) or OCI (b)
Electricity	3		(3		)	6		(6		)
Natural gas	37		(37		)	26		(26		)
Total	$	40	$	(40	)	$	32	$	(32	)

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

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

Credit Risk

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (15 U.S.C. 78a et seq.), is recorded, processed, summarized and reported, within the time periods specified in the 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 June 30, 2014. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of APS’s disclosure controls and procedures as of June 30, 2014. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended June 30, 2014 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See “Environmental Matters” in Item 5 below and “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2013 Form 10-K with regard to pending or threatened litigation and other disputes.

See Note 3 for ACC and FERC-related matters.

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

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A — Risk Factors in the 2013 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS. The risks described in the 2013 Form 10-K are not the only risks facing Pinnacle West and APS. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS. The risk factor below is an update to our 2013 Form 10-K.

APS faces physical and operational risks related to climate change, and potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG emissions.

Concern over climate change has led to significant legislative and regulatory efforts to limit CO2, which is a major byproduct of the combustion of fossil fuel, and other GHG emissions.

Financial Risks — Potential Greenhouse Gas Regulation. On June 2, 2014, EPA proposed a rule to limit carbon dioxide emissions from existing power plants. EPA expects to finalize the proposal in June 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.

Physical and Operational Risks. Weather extremes such as drought and high temperature variations are common occurrences in the Southwest’s desert area, and these are risks that APS considers in the normal course of business in the engineering and construction of its electric system. Large increases in ambient temperatures could require evaluation of certain materials used within its system and represent a greater challenge.

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

Issuer Purchases of Equity Securities

There were no issuer purchases of equity securities during the second quarter of 2014.

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Item 5. OTHER INFORMATION

Physical Security Standards

On March 7, 2014, FERC issued an order requiring NERC to act within 90 days to develop standards that will require utilities to take steps, or to demonstrate that they have taken steps, to address physical security risks and vulnerabilities related to the reliable operation of the bulk-power system. On May 23, 2014, NERC filed a petition with FERC for approval of the proposed Physical Security Reliability Standard CIP-014-1. The proposed Physical Security Reliability Standard requires transmission owners and operators to protect those critical transmission stations and substations and their associated primary control centers that if rendered inoperable or damaged as a result of a physical attack could result in widespread instability, uncontrolled separation or cascading within an interconnection. Until the NERC standards have been approved by FERC, we cannot predict the extent of any financial or operational impacts on APS.

Union Contract

As previously disclosed in Part I, Item 1 “Business — Other Information” in the 2013 Form 10-K, APS and union representatives from the United Security Professionals of America, the union representing Palo Verde security personnel, were engaged in negotiations over the terms of a new collective bargaining agreement. On June 1, 2014, the union members ratified a three-year contract, which will expire on May 31, 2017. The contract provides an average wage increase of 1.65% for the first year, 1.98% for the second year and 2.35% for the third year.

Environmental Matters

Climate Action Plan and Greenhouse Gas Emissions

As previously reported, consistent with President Obama’s June 2013 Climate Action Plan addressing his plans to reduce GHG emissions in the United States, pursuant to its endangerment finding and its authority under Section 111(b) of the Clean Air Act, on September 20, 2013, EPA issued a proposed rule, which would establish New Source Performance Standards (“NSPS”) for new fossil-fired power plants. The President directed EPA to finalize the greenhouse gas NSPS for electric utilities in a timely fashion. Once finalized, APS does not expect that the standards will have any material impact on its current operations.

Also in accordance with the Climate Action Plan, on June 2, 2014, EPA issued two additional proposed rules to regulate GHG emissions from existing fossil fuel-fired power plants and modified and reconstructed electric generating units. Exercising its authority under Section 111(d) of the Clean Air Act, EPA’s proposed “Clean Power Plan” rule proposes state-specific goals or targets to achieve reductions in CO2 emissions measured from a 2012 baseline. EPA’s proposed emission rates would not apply directly to specific electric generating units, but must be met on a state-wide basis. As proposed, each state’s goal is an emissions rate—a single number for the future carbon intensity of that state. The proposed rule provides guidelines to states to help develop their plans for meeting the interim (2020-2029) and final (2030 and beyond) emission rates set forth in the proposal. States would be required to submit their plans to EPA by June 2016, although states may be eligible for one or two year extensions, provided they submit detailed explanations by April 2016 that contain specified information required by EPA. As for sources in Indian country (which are not subject to state plans), including Four Corners and the Navajo Plant, EPA stated that it intends to publish a supplemental proposal at a later date to develop a federal plan establishing standards of performance for these sources. EPA explained that it would finalize this federal plan by June 2015.

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EPA’s proposal for Arizona would result in in-state coal-fired generation (with the exception of coal-fired generation located in Indian country) shifting to natural gas combined cycle 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 will continue to monitor these standards as they are developed.

On June 2, 2014, EPA also issued a proposal to regulate CO2 emissions from modified and reconstructed power plants pursuant to Section 111(b) of the Clean Air Act. The proposed rule would require modified and reconstructed fossil fuel-fired electric generating units to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. The rule would also require existing electric generating units that are modified or reconstructed after becoming subject to state or federal standards of performance for existing power plants under Section 111(d) of the Clean Air Act to continue to meet those requirements. President Obama directed EPA to finalize both rules by June 1, 2015. We cannot currently predict the shape of any final rules or standards for modified and reconstructed fossil-fired power plants or assess how they might potentially impact the Company.

Cooling Water Intake Structures

EPA issued its final cooling water intake structures rule on May 19, 2014, which establishes national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to Section 316(b) of the Clean Water Act. The standards are intended to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The rule requires all affected sources to submit source water baseline characterization data to the permitting authority. To minimize impingement mortality, the rule requires facilities, such as Four Corners and the Navajo Plant, to meet one of seven impingement mortality standards. To minimize entrainment mortality, the rule requires the permit writer to consider an array of factors, including social costs and benefits, and choose the “best technology available.”

Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority. APS is currently in discussions with EPA Region 9, the National Pollutant Discharge Elimination System permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS does not expect such costs to be material.

Climate Change - Regulatory Initiatives Update

In 2009, EPA determined that GHG emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that GHGs fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, EPA has the authority to regulate GHG emissions of new motor vehicles under the Clean Air Act. As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. (See “Climate Action Plan” discussion above.) EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new GHG emission thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review,” or “NSR,” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source. The tailoring rule became applicable to power plants in January 2011. Several groups filed lawsuits challenging EPA’s endangerment finding and the tailoring rule, but the D.C. Circuit upheld these rules. Petitioners asked the United States Supreme Court to reverse all or

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part of the appeals court’s decision upholding EPA’s GHG rules. On October 15, 2013, the Supreme Court granted these petitions limiting the question it would review to whether EPA permissibly determined that its regulation of GHG emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit such gasses, including power plants.

On June 23, 2014, the Supreme Court issued its decision holding that while GHG emissions alone cannot trigger an obligation to obtain a pre-construction permit, EPA can require a source to obtain a pre-construction permit limiting GHG emissions if it is required to obtain such permit for any other pollutant regulated under the Clean Air Act (so-called “anyway” sources). Because APS expects that most projects it will undertake at its power plants will be “anyway” projects, APS does not expect that the Supreme Court’s decision will have a significant impact on APS’s current operations. APS will be required to consider the impact of GHG emissions as part of its traditional NSR analysis for new sources and major modifications to existing plants.

Regional Haze Rules — Four Corners BART FIP Challenge

On October 22, 2012, WildEarth Guardians filed a petition for review in the United States Court of Appeals for the Ninth Circuit alleging that EPA violated the Endangered Species Act when it promulgated the final Four Corners BART FIP (see Note 9 for additional discussion of the Regional Haze Rules). The court granted APS’s motion for leave to intervene as a defendant and subsequently transferred the case to the Tenth Circuit. On July 23, 2014, the court affirmed EPA’s action and denied WildEarth Guardians’ petition for review. APS is unable to predict whether WildEarth Guardians will file a petition for rehearing or otherwise appeal the decision.

Pinnacle West Transmission

On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, Bright Canyon Energy Corporation (“BCE”). BCE will focus on new growth opportunities that leverage the Company’s core expertise in the electric energy industry. BCE’s first initiative, also announced on July 31, 2014, is a joint venture with MidAmerican Transmission, LLC. The joint venture intends to focus on transmission opportunities within the Western Electricity Coordinating Council, excluding the retail service territories of the venture partners’ affiliates. The joint venture intends to 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. 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, and the existing Colorado River substation, located just west of Blythe, California.

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Item 6. EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description

10.1*	Pinnacle West APS	Second Amendment to the Pinnacle West Capital Corporation Savings Plan

10.2	Pinnacle West APS	Amendment No. 3, dated July 10, 2014, to Facility Lease, dated as of December 15, 1986 between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to the First National Bank of Boston, as Lessor, and APS, as Lessee

10.3	Pinnacle West APS	Five-Year Credit Agreement dated as of May 9, 2014, among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto

10.4	Pinnacle West	Five-Year Credit Agreement, dated as of May 9, 2014, among Pinnacle West, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto

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

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Exhibit No.	Registrant(s)	Description
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

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

**Furnished herewith as an Exhibit.

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

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

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

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

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

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

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

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

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SIGNATURES

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

	PINNACLE WEST CAPITAL CORPORATION
	(Registrant)


Dated: July 31, 2014	By:	/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)


	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)


Dated: July 31, 2014	By:	/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)