10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2015

OR

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

For the transition period from              to          

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

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

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION

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

ARIZONA PUBLIC SERVICE COMPANY

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of July 24, 2015: 110,813,659
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of July 24, 2015: 71,264,947

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

TABLE OF CONTENTS

		Page
Forward-Looking Statements		2
Part I		3
Item 1.	Financial Statements	3
	Pinnacle West Capital Corporation	3
	Arizona Public Service Company	48
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	78
Item 4.	Controls and Procedures	79
Part II		80
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 5.	Other Information	80
Item 6.	Exhibits	81
Signatures		84

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

1

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as "estimate," "predict," "may," "believe," "plan," "expect," "require," "intend," "assume" and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2014 ("2014 Form 10-K") and in Part I, Item 2 — "Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, these factors include, but are not limited to:

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

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

• power plant and transmission system performance and outages;

• competition in retail and wholesale power markets;

• regulatory and judicial decisions, developments and proceedings;

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

• fuel and water supply availability;

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

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

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

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

• the development of new technologies which may affect electric sales or delivery;

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

• environmental and other concerns surrounding coal-fired generation;

• volatile fuel and purchased power costs;

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

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

• potential shortfalls in insurance coverage;

• new accounting requirements or new interpretations of existing requirements;

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

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

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

• restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission ("ACC") orders.

These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our 2014 Form 10-K, which readers should review carefully before placing any reliance on our financial statements or disclosures.  Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

2

PART I — FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended   June 30,
	2015			2014
OPERATING REVENUES	$	890,648		$	906,264
OPERATING EXPENSES
Fuel and purchased power	281,477			290,854
Operations and maintenance	210,965			211,222
Depreciation and amortization	122,739			105,150
Taxes other than income taxes	43,032			44,004
Other expenses	462			921
Total	658,675			652,151
OPERATING INCOME	231,973			254,113
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	9,345			7,499
Other income (Note 9)	175			2,781
Other expense (Note 9)	(2,609		)	(508		)
Total	6,911			9,772
INTEREST EXPENSE
Interest charges	48,328			51,751
Allowance for borrowed funds used during construction	(4,322		)	(3,790		)
Total	44,006			47,961
INCOME BEFORE INCOME TAXES	194,878			215,924
INCOME TAXES	67,371			74,540
NET INCOME	127,507			141,384
Less: Net income attributable to noncontrolling interests (Note 6)	4,605			8,926
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	122,902		$	132,458
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	110,986			110,565
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	111,460			111,002
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	1.11		$	1.20
Net income attributable to common shareholders — diluted	$	1.10		$	1.19
DIVIDENDS DECLARED PER SHARE	$	1.19		$	1.14

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

3

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   June 30,
	2015			2014
NET INCOME	$	127,507		$	141,384
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain, net of tax expense of $16 and $26	25			40
Reclassification of net realized loss, net of tax benefit of $556 and $1,261	874			1,955
Pension and other postretirement benefits activity, net of tax benefit of $74 and $845	(117		)	(1,310		)
Total other comprehensive income	782			685
COMPREHENSIVE INCOME	128,289			142,069
Less: Comprehensive income attributable to noncontrolling interests	4,605			8,926
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	123,684		$	133,143

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

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Six Months Ended   June 30,
	2015			2014
OPERATING REVENUES	$	1,561,867		$	1,592,515
OPERATING EXPENSES
Fuel and purchased power	504,714			540,640
Operations and maintenance	425,909			424,104
Depreciation and amortization	243,688			206,922
Taxes other than income taxes	86,248			89,849
Other expenses	1,651			1,717
Total	1,262,210			1,263,232
OPERATING INCOME	299,657			329,283
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	18,569			14,941
Other income (Note 9)	410			5,148
Other expense (Note 9)	(6,895		)	(5,192		)
Total	12,084			14,897
INTEREST EXPENSE
Interest charges	96,727			104,720
Allowance for borrowed funds used during construction	(8,538		)	(7,560		)
Total	88,189			97,160
INCOME BEFORE INCOME TAXES	223,552			247,020
INCOME TAXES	75,318			80,945
NET INCOME	148,234			166,075
Less: Net income attributable to noncontrolling interests (Note 6)	9,210			17,851
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	139,024		$	148,224
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	110,958			110,546
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	111,426			110,925
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	1.25		$	1.34
Net income attributable to common shareholders — diluted	$	1.25		$	1.34
DIVIDENDS DECLARED PER SHARE	$	1.19		$	1.14

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

5

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended   June 30,
	2015			2014
NET INCOME	$	148,234		$	166,075
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $489 and $624	(775		)	(381		)
Reclassification of net realized loss, net of tax benefit of $923 and $2,584	2,850			5,070
Pension and other postretirement benefits activity, net of tax benefit (expense) of $(793) and $128	466			(853		)
Total other comprehensive income	2,541			3,836
COMPREHENSIVE INCOME	150,775			169,911
Less: Comprehensive income attributable to noncontrolling interests	9,210			17,851
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	141,565		$	152,060

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

6

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	13,557		$	7,604
Customer and other receivables	289,236			297,740
Accrued unbilled revenues	185,216			100,533
Allowance for doubtful accounts	(2,518		)	(3,094		)
Materials and supplies (at average cost)	231,101			218,889
Fossil fuel (at average cost)	43,196			37,097
Deferred income taxes	77,841			122,232
Income tax receivable (Note 5)	—			3,098
Assets from risk management activities (Note 7)	14,722			13,785
Deferred fuel and purchased power regulatory asset (Note 3)	—			6,926
Other regulatory assets (Note 3)	134,578			129,808
Other current assets	44,827			38,817
Total current assets	1,031,756			973,435
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	18,513			17,620
Nuclear decommissioning trust (Note 12)	723,582			713,866
Other assets	51,987			54,047
Total investments and other assets	794,082			785,533
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,926,594			15,543,063
Accumulated depreciation and amortization	(5,497,350		)	(5,397,751		)
Net	10,429,244			10,145,312
Construction work in progress	638,285			682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	119,320			121,255
Intangible assets, net of accumulated amortization	127,742			119,755
Nuclear fuel, net of accumulated amortization	156,608			125,201
Total property, plant and equipment	11,471,199			11,194,330
DEFERRED DEBITS
Regulatory assets (Note 3)	1,081,113			1,054,087
Assets for other postretirement benefits (Note 4)	168,755			152,290
Other	154,578			153,857
Total deferred debits	1,404,446			1,360,234
TOTAL ASSETS	$	14,701,483		$	14,313,532

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

7

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2015			December 31, 2014
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	326,119		$	295,211
Accrued taxes (Note 5)	155,812			140,613
Accrued interest	54,547			52,603
Common dividends payable	65,933			65,790
Short-term borrowings (Note 2)	157,500			147,400
Current maturities of long-term debt (Note 2)	102,723			383,570
Customer deposits	72,785			72,307
Liabilities from risk management activities (Note 7)	60,673			59,676
Deferred fuel and purchased power regulatory liability (Note 3)	16,209			—
Liabilities for asset retirements (Note 15)	28,543			32,462
Other regulatory liabilities (Note 3)	136,273			130,549
Other current liabilities	162,742			178,962
Total current liabilities	1,339,859			1,559,143
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	3,565,857			3,031,215
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,614,274			2,582,636
Regulatory liabilities (Note 3)	1,016,991			1,051,196
Liabilities for asset retirements (Note 15)	419,072			358,288
Liabilities for pension benefits (Note 4)	425,002			453,736
Liabilities from risk management activities (Note 7)	87,689			50,602
Customer advances	120,063			123,052
Coal mine reclamation	200,155			198,292
Deferred investment tax credit	176,389			178,607
Unrecognized tax benefits (Note 5)	14,311			19,377
Other	196,178			188,286
Total deferred credits and other	5,270,124			5,204,072
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 110,865,030 and 110,649,762 issued at respective dates	2,526,945			2,512,970
Treasury stock at cost; 53,559 and 78,400 shares at respective dates	(1,765		)	(3,401		)
Total common stock	2,525,180			2,509,569
Retained earnings	1,933,256			1,926,065
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(57,290		)	(57,756		)
Derivative instruments	(8,310		)	(10,385		)
Total accumulated other comprehensive loss	(65,600		)	(68,141		)
Total shareholders’ equity	4,392,836			4,367,493
Noncontrolling interests (Note 6)	132,807			151,609
Total equity	4,525,643			4,519,102
TOTAL LIABILITIES AND EQUITY	$	14,701,483		$	14,313,532

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

8

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended   June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	148,234		$	166,075
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	282,218			246,371
Deferred fuel and purchased power	11,711			1,315
Deferred fuel and purchased power amortization	11,424			18,399
Allowance for equity funds used during construction	(18,569		)	(14,941		)
Deferred income taxes	65,377			32,611
Deferred investment tax credit	(2,218		)	28,875
Change in derivative instruments fair value	(225		)	49
Changes in current assets and liabilities:
Customer and other receivables	(17,402		)	(64,986		)
Accrued unbilled revenues	(84,683		)	(75,648		)
Materials, supplies and fossil fuel	(18,311		)	(9,435		)
Income tax receivable	3,098			135,517
Other current assets	(8,728		)	(14,038		)
Accounts payable	36,634			30,725
Accrued taxes	15,199			30,709
Other current liabilities	(13,138		)	19,978
Change in margin and collateral accounts — assets	(4,552		)	(2,107		)
Change in margin and collateral accounts — liabilities	26,853			(22,425		)
Change in other long-term assets	(4,817		)	(19,243		)
Change in other long-term liabilities	(33,811		)	(22,735		)
Net cash flow provided by operating activities	394,294			465,066
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(531,035		)	(388,752		)
Contributions in aid of construction	41,010			12,646
Allowance for borrowed funds used during construction	(8,538		)	(7,560		)
Proceeds from nuclear decommissioning trust sales	225,779			199,224
Investment in nuclear decommissioning trust	(234,651		)	(207,848		)
Other	(2,068		)	(678		)
Net cash flow used for investing activities	(509,503		)	(392,968		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	600,000			535,975
Repayment of long-term debt	(344,847		)	(503,583		)
Short-term borrowings and payments — net	10,100			23,525
Dividends paid on common stock	(128,241		)	(125,138		)
Common stock equity issuance	12,161			12,625
Distributions to noncontrolling interest	(28,012		)	(15,869		)
Other	1			2
Net cash flow provided by (used for) financing activities	121,162			(72,463		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,953			(365		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	7,604			9,526
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	13,557		$	9,161

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

9

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands, except per share amounts)

	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
Balance, January 1, 2014	110,280,703	$	2,491,558	(98,944	)	$	(4,308	)	$	1,785,273		$	(78,053	)	$	145,990		$	4,340,460
Net income									148,224						17,851			166,075
Other comprehensive income												3,836						3,836
Dividends on common stock									(125,265		)							(125,265		)
Issuance of common stock	149,753	8,506																8,506
Purchase of treasury stock (a)				(82,474	)	(4,535		)										(4,535		)
Stock-based compensation and other				157,594		8,654												8,654
Net capital activities by noncontrolling interests															(15,869		)	(15,869		)
Balance, June 30, 2014	110,430,456	$	2,500,064	(23,824	)	$	(189	)	$	1,808,232		$	(74,217	)	$	147,972		$	4,381,862
Balance, January 1, 2015	110,649,762	$	2,512,970	(78,400	)	$	(3,401	)	$	1,926,065		$	(68,141	)	$	151,609		$	4,519,102
Net income									139,024						9,210			148,234
Other comprehensive income												2,541						2,541
Dividends on common stock									(131,833		)							(131,833		)
Issuance of common stock	215,268	13,975																13,975
Purchase of treasury stock (a)				(93,280	)	(6,096		)										(6,096		)
Stock-based compensation and other				118,121		7,732												7,732
Net capital activities by noncontrolling interests															(28,012		)	(28,012		)
Balance, June 30, 2015	110,865,030	$	2,526,945	(53,559	)	$	(1,765	)	$	1,933,256		$	(65,600	)	$	132,807		$	4,525,643

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

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

10

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Consolidation and Nature of Operations

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

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

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

Supplemental Cash Flow Information

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

	Six Months Ended   June 30,
	2015		2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$	1,834	$	(131,154	)
Interest, net of amounts capitalized	84,008		90,707
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	38,985	$	19,668
Dividends accrued but not yet paid	65,933		62,656

2. Long-Term Debt and Liquidity Matters

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

Pinnacle West

Pinnacle West's $200 million revolving credit facility matures in May 2019.  At June 30, 2015, the facility was available to refinance indebtedness of the Company and for other general corporate purposes,

11

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the size of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At June 30, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

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

On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% Notes due May 15, 2015.

On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness.

On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

At June 30, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million facility that matures in May 2019.  APS may increase the size of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2015, APS had $158 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.

See "Financial Assurances" in Note 8 for a discussion of APS’s separate outstanding letters of credit.

Debt Fair Value

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

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	As of June 30, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,544		3,818		3,290		3,714
Total	$	3,669	$	3,943	$	3,415	$	3,839

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At June 30, 2015, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.3 billion, assuming APS’s total capitalization remains the same.

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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.

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

• An authorized return on common equity of 10.0%;

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

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

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

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

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

• A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);

• Implementation of a Lost Fixed Cost Recovery ("LFCR") rate mechanism to support energy efficiency and distributed renewable generation;

• Modifications to the Environmental Improvement Surcharge ("EIS") to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental

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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.

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

Cost Recovery Mechanisms

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

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

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.

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

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

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million.

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

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

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

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

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.

Electric Energy Efficiency

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014

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to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

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

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2015 and 2014 (dollars in millions):

	Six Months Ended   June 30,
	2015			2014
Beginning balance	$	7		$	21
Deferred fuel and purchased power costs — current period	(12		)	(1		)
Amounts charged to customers	(11		)	(19		)
Ending balance	$	(16	)	$	1

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

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

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

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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.

Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 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, 2015.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future.

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 files for a LFCR adjustment every January.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a "market" basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and early 2015. No further action has been taken by the ACC to date.

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Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The fixed charge does not increase APS's revenue because it is credited to the LFCR.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. 

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

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

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

Four Corners

On December 30, 2013, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $74 million as of June 30, 2015 and is being amortized in rates over 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals

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of the ACC decision approving the rate adjustments. APS has intervened and will actively participate in the proceeding. We cannot predict when or how this appeal will be resolved.

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

Cholla

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

If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($125 million as of June 30, 2015), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

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Regulatory Assets and Liabilities

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

	Remaining Amortization Period	June 30, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Pension benefits	(a)	$	—	$	505	$	—	$	485
Income taxes — allowance for funds used during construction ("AFUDC") equity	2044	5		122		5		118
Deferred fuel and purchased power — mark-to-market (Note 7)	2018	53		62		51		46
Transmission vegetation management	2016	9		—		9		5
Coal reclamation	2026	—		6		—		7
Palo Verde VIEs (Note 6)	2046	—		26		—		35
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		7		—
Tax expense of Medicare subsidy	2024	2		13		2		14
Loss on reacquired debt	2034	1		16		1		16
Income taxes — investment tax credit basis adjustment	2044	2		46		2		46
Pension and other postretirement benefits deferral	2015	—		—		4		—
Four Corners cost deferral	2024	7		67		7		70
Lost fixed cost recovery (b)	2016	45		—		38		—
Retired power plant costs	2033	10		131		10		136
Deferred property taxes	(d)	—		40		—		30
Other	Various	1		11		2		12
Total regulatory assets (e)		$	135	$	1,081	$	138	$	1,054

(a) This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues.  See Note 4 for further discussion.

(b) See "Cost Recovery Mechanisms" discussion above.

(c) Subject to a carrying charge.

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

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

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

	Remaining Amortization Period	June 30, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	44	$	245	$	31	$	273
Asset retirement obligations	2044	—		272		—		296
Renewable energy standard (b)	2017	29		20		25		23
Income taxes — change in rates	2043	1		71		—		72
Spent nuclear fuel	2047	3		68		5		66
Deferred gains on utility property	2019	2		7		2		8
Income taxes — deferred investment tax credit	2043	3		92		4		93
Deferred fuel and purchased power (b) (c)	2016	16		—		—		—
Demand side management (b)	2017	8		27		31		—
Other postretirement benefits	(d)	33		189		32		199
Other	Various	13		26		1		21
Total regulatory liabilities		$	152	$	1,017	$	131	$	1,051

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

(b) See "Cost Recovery Mechanisms" discussion above.

(c) Subject to a carrying charge.

(d) See Note 4.

4. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of these plan changes in 2014, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new account to pay for active union employee medical costs.

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We amortized approximately $2 million and $4 million for the three and six months ended June 30, 2015 and 2014, respectively. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):

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	Pension Benefits												Other Benefits
	Three Months Ended   June 30,						Six Months Ended   June 30,						Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost — benefits earned during the period	$	14		$	12		$	30		$	27		$	4		$	5		$	8		$	9
Interest cost on benefit obligation	31			33			62			65			7			11			14			23
Expected return on plan assets	(45		)	(39		)	(90		)	(79		)	(9		)	(13		)	(18		)	(25		)
Amortization of:
Prior service cost	—			—			—			—			(9		)	—			(19		)	—
Net actuarial loss	8			3			16			5			—			—			2			—
Net periodic benefit cost	$	8		$	9		$	18		$	18		$	(7	)	$	3		$	(13	)	$	7
Portion of cost charged to expense	$	5		$	5		$	11		$	11		$	(2	)	$	3		$	(4	)	$	5

Contributions

We have made voluntary contributions of $80 million to our pension plan year-to-date in 2015. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

5. Income Taxes

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

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

As of June 30, 2015, the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS.  With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2009.

6. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lease agreements include fixed rate renewal periods. On July 7, 2014, APS notified the lessor trust entities of APS's intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining the assets

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through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $49 million in 2015, $23 million annually for the period 2016 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to 2 years, or return the assets to the lessors.

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

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for the three and six months ended June 30, 2015 of $5 million and $9 million, respectively, and for the three and six months ended June 30, 2014 of $9 million and $18 million, respectively, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased because of lower rent income resulting from the July 7, 2014 lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):

	June 30, 2015		December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	119	$	121
Current maturities of long-term debt	1		13
Equity — Noncontrolling interests	133		152

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

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of June 30, 2015, APS would have been required to pay the noncontrolling equity participants approximately $114 million and assume $1 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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For regulatory ratemaking purposes, the agreements 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 11 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time.  We assess hedge effectiveness both at inception and on a continuing basis.  These assessments exclude the time value of certain options.  For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings.  We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment.  As cash

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

Commodity	Quantity
Power	3,808	GWh
Gas	188	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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   June 30,						Six Months Ended   June 30,
Commodity Contracts		2015			2014			2015			2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	41		$	66		$	(286	)	$	243
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(1,430		)	(3,216		)	(3,773		)	(7,654		)

(a) During the three and six months ended June 30, 2015 and 2014, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that a net loss of $4 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, most 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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   June 30,					Six Months Ended June 30,
Commodity Contracts		2015			2014		2015			2014
Net gain (loss) recognized in income	Operating revenues (a)	$	(66	)	$	155	$	(114	)	$	63
Net gain (loss) recognized in income	Fuel and purchased power (a)	10,613			4,805		(34,190		)	22,912
Total		$	10,547		$	4,960	$	(34,304	)	$	22,975

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

Derivative Instruments in the Condensed Consolidated Balance Sheets

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

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

The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, each include gross liabilities of $4 million of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2015 and December 31, 2014.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

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As of June 30, 2015: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance  Sheet
Current assets	$	25,485		$	(12,925	)	$	12,560		$	2,162		$	14,722
Investments and other assets	20,560			(4,787		)	15,773			2,740			18,513
Total assets	46,045			(17,712		)	28,333			4,902			33,235
Current liabilities	(83,203		)	30,626			(52,577		)	(8,096		)	(60,673		)
Deferred credits and other	(92,475		)	4,786			(87,689		)	—			(87,689		)
Total liabilities	(175,678		)	35,412			(140,266		)	(8,096		)	(148,362		)
Total	$	(129,633	)	$	17,700		$	(111,933	)	$	(3,194	)	$	(115,127	)

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

(b) Includes cash collateral provided to counterparties of $17,700.

(c) Represents cash collateral, cash margin and option premiums that are not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $8,096, cash margin provided to counterparties of $2,162 and option premiums of $2,740.

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

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

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

(c) Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,443, and cash margin provided to counterparties of $350.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties.  We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 81% of Pinnacle West’s $33 million of risk management assets as of June 30, 2015.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties. 

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Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2015 (dollars in millions):

	June 30, 2015
Aggregate fair value of derivative instruments in a net liability position	$	176
Cash collateral posted	18
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	89

(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 $161 million if our debt credit ratings were to fall below investment grade.

8. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit seeks to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified

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costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

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

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of $12.98 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments.  The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment of approximately $16.5 million.

The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination.  APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds.  The maximum amount APS could incur under the current NEIL policies totals approximately $23.1 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 $61.7 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

During the quarter our purchase obligations have increased by about $170 million relating to gas generation projects. The expected payments to be made are $26 million in 2015, $89 million in 2016, $46 million in 2017 and $9 million in 2018.

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Other than the item described above, there have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2014 Form 10-K.

Superfund-Related Matters

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

On August 6, 2013, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Southwest Power Outage

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

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

Clean Air Act Citizen Lawsuit

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners

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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 sought to have the court enjoin operations at Four Corners until APS applied for and obtained any required NSR permits and complied with the NSPS.  The plaintiffs further requested the court to order the payment of civil penalties, including a beneficial mitigation project.  The case was held in abeyance while APS negotiated a settlement with the United States Department of Justice ("DOJ") and environmental plaintiffs.  In March 2015, the parties agreed in principle on final proposed language to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On that same day, DOJ also published notice of the filing in the Federal Register, which opened a 30-day period for public comment. The settlement would resolve claims by the government and environmental plaintiffs that the co-owners violated the Clean Air Act by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement would require installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule best available retrofit technology ("BART") requirements. The settlement would also require Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.2 million for certain environmental mitigation projects to benefit the Navajo Nation. APS would be responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows. APS expects DOJ to file a motion to enter the consent decree with the court after expiration of the 30-day comment period.

Environmental Matters

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

Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners, Cholla and the Navajo Generating Station ("Navajo Plant").  EPA and ADEQ will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. 

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

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

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Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million, is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.  Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  Briefing in the case was completed in February 2014. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rule-making processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On June 10, 2015, ADEQ issued for public comment the draft Cholla permit, which memorializes APS's proposal, and a proposed revision to the SIP, which would incorporate the new permit terms.  APS is unable to predict when or whether APS's proposal may ultimately be approved.

Mercury and Air Toxic Standards ("MATS").  In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants.  APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS's compromise proposal discussed above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  Salt River Project Agricultural Improvement and Power District ("SRP"), the operating agent for the Navajo Plant, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. The United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS rule.  This decision does not materially impact APS.  Regardless of whether the MATS rule is ultimately vacated by the lower court, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla.

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

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

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associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

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

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

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment").  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013.  The New Mexico Taxation and Revenue Department denied the refund claim.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The New Mexico Taxation and Revenue Department has indicated it intends to appeal the decision. We cannot predict the timing or outcome of any appeal; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

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Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At June 30, 2015, 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.  Two of these letters of credit expire in 2016 and one expires in 2017.  APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $20 million at June 30, 2015.  Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including a natural gas tolling contract entered into with a third party.  At June 30, 2015, $35 million of such letters of credit were outstanding that will expire in 2015 and 2016.

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

9. 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, 2015 and 2014 (dollars in thousands):

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Other income:
Interest income	$	184		$	495		$	294		$	746
Miscellaneous	(9		)	2,286			116			4,402
Total other income	$	175		$	2,781		$	410		$	5,148
Other expense:
Non-operating costs	$	(1,952	)	$	(2,620	)	$	(4,200	)	$	(4,992	)
Investment losses — net	(650		)	(105		)	(1,145		)	(246		)
Miscellaneous	(7		)	2,217			(1,550		)	46
Total other expense	$	(2,609	)	$	(508	)	$	(6,895	)	$	(5,192	)

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10. 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, 2015 and 2014 (in thousands, except per share amounts):

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
Net income attributable to common shareholders	$	122,902	$	132,458	$	139,024	$	148,224
Weighted average common shares outstanding — basic	110,986		110,565		110,958		110,546
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	474		437		468		379
Weighted average common shares outstanding — diluted	111,460		111,002		111,426		110,925
Earnings per average common share attributable to common shareholders — basic	$	1.11	$	1.20	$	1.25	$	1.34
Earnings per average common share attributable to common shareholders — diluted	$	1.10	$	1.19	$	1.25	$	1.34

11. Fair Value Measurements

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

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

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

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

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize

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

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 7 in the 2014 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

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

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

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

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

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

Investments Held in our Nuclear Decommissioning Trust

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

Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper.  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 typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.

We price securities using information provided by our trustee for our nuclear decommissioning trust assets.  Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value.  We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.  See Note 12 for additional discussion about our nuclear decommissioning trust.

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Fair Value Tables

The following table presents the fair value at June 30, 2015, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at June 30, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	16		$	30		$	(13	)	(b)	$	33
Nuclear decommissioning trust:
U.S. commingled equity funds	—		314			—			—				314
Cash and cash equivalent funds	—		11			—			(4		)	(c)	7
Fixed income securities:
U.S. Treasury	93		2			—			—				95
Corporate debt	—		116			—			—				116
Mortgage-backed securities	—		87			—			—				87
Municipal bonds	—		86			—			—				86
Other	—		19			—			—				19
Subtotal nuclear decommissioning trust	93		635			—			(4		)		724
Total	$	93	$	651		$	30		$	(17	)		$	757
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(103	)	$	(73	)	$	28		(b)	$	(148	)

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

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

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

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

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at December 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	33		$	(23	)	(b)	$	31
Nuclear decommissioning trust:
U.S. commingled equity funds	—		310			—			—				310
Fixed income securities:
U.S. Treasury	119		—			—			—				119
Cash and cash equivalent funds	—		11			—			(7		)	(c)	4
Corporate debt	—		109			—			—				109
Mortgage-backed securities	—		89			—			—				89
Municipal bonds	—		69			—			—				69
Other	—		14			—			—				14
Subtotal nuclear decommissioning trust	119		602			—			(7		)		714
Total	$	119	$	623		$	33		$	(30	)		$	745
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(95	)	$	(74	)	$	59		(b)	$	(110	)

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

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

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

Fair Value Measurements Classified as Level 3

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

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

Our option contracts classified as Level 3 primarily relate to purchase heat rate options.  The significant unobservable inputs at June 30, 2015 for these instruments include electricity prices, and

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volatilities. The significant unobservable inputs at December 31, 2014 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, 2015 and December 31, 2014:

	June 30, 2015 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	28	$	57	Discounted cash flows	Electricity forward price (per MWh)	$21.07 - $67.74	$	31.46
Option Contracts (b)	—		12		Option model	Electricity forward price (per MWh)	$32.85 - $67.74	$	46.13
						Electricity price volatilities	26% - 115%	68		%
						Natural gas price volatilities	27% - 42%	31		%
Natural Gas:
Forward Contracts (a)	2		4		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.69 - $3.61	$	3.23
Total	$	30	$	73

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

(a) Includes swaps and physical and financial contracts.

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

The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2015 and 2014 (dollars in millions):

	Three Months Ended   June 30,						Six Months Ended   June 30,
Commodity Contracts	2015			2014			2015			2014
Net derivative balance at beginning of period	$	(49	)	$	(49	)	$	(41	)	$	(49	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	6			3			(5		)	6
Settlements	5			4			5			5
Transfers into Level 3 from Level 2	(4		)	1			(4		)	(2		)
Transfers from Level 3 into Level 2	(1		)	—			2			(1		)
Net derivative balance at end of period	$	(43	)	$	(41	)	$	(43	)	$	(41	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

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

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

Financial Instruments Not Carried at Fair Value

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

12. Nuclear Decommissioning Trusts

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities.  APS classifies investments in decommissioning trust funds as available for sale.  As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets.  See Note 11 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities.  The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2015 and December 31, 2014 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2015
Equity securities	$	314		$	160	$	—
Fixed income securities	414			13		(3		)
Net payables (a)	(4		)	—		—
Total	$	724		$	173	$	(3	)

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

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

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

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Realized gains	$	1		$	1		$	2		$	2
Realized losses	(1		)	(1		)	(2		)	(3		)
Proceeds from the sale of securities (a)	110			96			226			199

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2015 is as follows (dollars in millions):

	Fair Value
Less than one year	$	13
1 year – 5 years	111
5 years – 10 years	123
Greater than 10 years	167
Total	$	414

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13. New Accounting Standards

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

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

In April 2015, the Financial Accounting Standards Board issued new guidance that changes the balance sheet presentation of debt issuance costs. Currently, debt issuance costs are presented on the balance sheet as assets. The new guidance requires us to reflect debt issuance costs as a reduction to the related debt liabilities, consistent with the presentation of debt discounts. The new guidance is effective for us during the first quarter of 2016, and must be adopted retrospectively. We do not expect these presentation changes to be material to our balance sheet. The adoption of this new guidance will not impact our results of operations or cash flows.

14. Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended June 30, 2015											Three Months Ended June 30, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, April 1	$	(9,209	)		$	(57,173	)		$	(66,382	)	$	(20,364	)		$	(54,538	)		$	(74,902	)
OCI (loss) before reclassifications	25				(969		)		(944		)	40				(2,072		)		(2,032		)
Amounts reclassified from accumulated other comprehensive loss	874			(a)	852			(b)	1,726			1,955			(a)	762			(b)	2,717
Net current period OCI (loss)	899				(117		)		782			1,995				(1,310		)		685
Ending balance, June 30	$	(8,310	)		$	(57,290	)		$	(65,600	)	$	(18,369	)		$	(55,848	)		$	(74,217	)

(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.

45

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Six Months Ended June 30, 2015											Six Months Ended June 30, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(57,756	)		$	(68,141	)	$	(23,058	)		$	(54,995	)		$	(78,053	)
OCI (loss) before reclassifications	(775		)		(969		)		(1,744		)	(381		)		(2,072		)		(2,453		)
Amounts reclassified from accumulated other comprehensive loss	2,850			(a)	1,435			(b)	4,285			5,070			(a)	1,219			(b)	6,289
Net current period OCI (loss)	2,075				466				2,541			4,689				(853		)		3,836
Ending balance, June 30	$	(8,310	)		$	(57,290	)		$	(65,600	)	$	(18,369	)		$	(55,848	)		$	(74,217	)

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

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

15. Asset Retirement Obligations

In the first quarter of 2015, an updated decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the asset retirement obligation ("ARO") in the amount of $18 million.

In the second quarter of 2015, there was a revision in estimated cash flows for the Four Corners decommissioning, whichresulted in an increase to the ARO in the amount of $6 million. In addition, APS recognized an ARO for Cholla as a result of new CCR environmental rulings that were published in the Federal Register in the second quarter of 2015. See Note 8 for additional information related to the CCR environmental rulings. This resulted in an increase to the ARO in the amount of $39 million, an increase in plant in service of $23 million and a reduction of the regulatory liability of $16 million.

46

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2015 (dollars in millions): 

Asset retirement obligations at January 1, 2015	$	391
Changes attributable to:
Accretion expense	12
Settlements	(18		)
Estimated cash flow revisions	24
Newly incurred liabilities	39
Asset retirement obligations at June 30, 2015	$	448

Decommissioning activities for Four Corners Units 1-3 began in January 2014; thus, $29 million of the total asset retirement obligation of $448 million at June 30, 2015, is classified as a current liability on the balance sheet.

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

47

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   June 30,
	2015			2014
ELECTRIC OPERATING REVENUES	$	889,723		$	905,578
OPERATING EXPENSES
Fuel and purchased power	281,477			290,854
Operations and maintenance	208,031			208,059
Depreciation and amortization	122,716			105,127
Income taxes	71,672			77,371
Taxes other than income taxes	43,123			43,773
Total	727,019			725,184
OPERATING INCOME	162,704			180,394
OTHER INCOME (DEDUCTIONS)
Income taxes	2,980			1,568
Allowance for equity funds used during construction	9,345			7,499
Other income (Note S-1)	710			3,221
Other expense (Note S-1)	(2,449		)	(1,477		)
Total	10,586			10,811
INTEREST EXPENSE
Interest on long-term debt	44,826			48,462
Interest on short-term borrowings	1,705			1,637
Debt discount, premium and expense	1,103			1,054
Allowance for borrowed funds used during construction	(4,311		)	(3,790		)
Total	43,323			47,363
NET INCOME	129,967			143,842
Less: Net income attributable to noncontrolling interests (Note 6)	4,605			8,926
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	125,362		$	134,916

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

48

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   June 30,
	2015			2014
NET INCOME	$	129,967		$	143,842
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain, net of tax expense of $16 and $26	25			40
Reclassification of net realized loss, net of tax benefit of $556 and $1,261	874			1,954
Pension and other postretirement benefits activity, net of tax benefit of $47 and $828	(74		)	(1,283		)
Total other comprehensive income	825			711
COMPREHENSIVE INCOME	130,792			144,553
Less: Comprehensive income attributable to noncontrolling interests	4,605			8,926
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	126,187		$	135,627

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

49

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended   June 30,
	2015			2014
ELECTRIC OPERATING REVENUES	$	1,560,391		$	1,591,123
OPERATING EXPENSES
Fuel and purchased power	504,714			540,640
Operations and maintenance	417,978			416,344
Depreciation and amortization	243,642			206,875
Income taxes	83,911			87,849
Taxes other than income taxes	86,109			89,386
Total	1,336,354			1,341,094
OPERATING INCOME	224,037			250,029
OTHER INCOME (DEDUCTIONS)
Income taxes	5,131			2,778
Allowance for equity funds used during construction	18,569			14,941
Other income (Note S-1)	1,349			5,983
Other expense (Note S-1)	(7,803		)	(6,533		)
Total	17,246			17,169
INTEREST EXPENSE
Interest on long-term debt	90,254			97,358
Interest on short-term borrowings	2,879			3,050
Debt discount, premium and expense	2,237			2,065
Allowance for borrowed funds used during construction	(8,527		)	(7,560		)
Total	86,843			94,913
NET INCOME	154,440			172,285
Less: Net income attributable to noncontrolling interests (Note 6)	9,210			17,851
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	145,230		$	154,434

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

50

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Six Months Ended   June 30,
	2015			2014
NET INCOME	$	154,440		$	172,285
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax expense of $489 and $624	(775		)	(381		)
Reclassification of net realized loss, net of tax benefit of $923 and $2,584	2,850			5,070
Pension and other postretirement benefits activity, net of tax benefit (expense) of $(722) and $222	607			(717		)
Total other comprehensive income	2,682			3,972
COMPREHENSIVE INCOME	157,122			176,257
Less: Comprehensive income attributable to noncontrolling interests	9,210			17,851
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	147,912		$	158,406

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

51

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	June 30, 2015			December 31, 2014
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	15,923,342		$	15,539,811
Accumulated depreciation and amortization	(5,494,236		)	(5,394,650		)
Net	10,429,106			10,145,161
Construction work in progress	636,927			682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	119,320			121,255
Intangible assets, net of accumulated amortization	127,587			119,600
Nuclear fuel, net of accumulated amortization	156,608			125,201
Total property, plant and equipment	11,469,548			11,194,024
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 12)	723,582			713,866
Assets from risk management activities (Note 7)	18,513			17,620
Other assets	33,976			33,362
Total investments and other assets	776,071			764,848
CURRENT ASSETS
Cash and cash equivalents	7,973			4,515
Customer and other receivables	281,609			297,712
Accrued unbilled revenues	185,216			100,533
Allowance for doubtful accounts	(2,518		)	(3,094		)
Materials and supplies (at average cost)	231,101			218,889
Fossil fuel (at average cost)	43,196			37,097
Assets from risk management activities (Note 7)	14,722			13,785
Deferred fuel and purchased power regulatory asset (Note 3)	—			6,926
Other regulatory assets (Note 3)	134,578			129,808
Deferred income taxes	54,789			55,253
Other current assets	44,168			38,693
Total current assets	994,834			900,117
DEFERRED DEBITS
Regulatory assets (Note 3)	1,081,113			1,054,087
Assets for other postretirement benefits (Note 4)	165,682			149,260
Unamortized debt issue costs	27,843			24,642
Other	125,694			128,026
Total deferred debits	1,400,332			1,356,015
TOTAL ASSETS	$	14,640,785		$	14,215,004

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

52

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands) 

	June 30, 2015			December 31, 2014
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,982,150			1,968,718
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(37,341		)	(37,948		)
Derivative instruments	(8,310		)	(10,385		)
Total shareholder equity	4,494,357			4,478,243
Noncontrolling interests (Note 6)	132,807			151,609
Total equity	4,627,164			4,629,852
Long-term debt less current maturities (Note 2)	3,440,857			2,906,215
Total capitalization	8,068,021			7,536,067
CURRENT LIABILITIES
Short-term borrowings (Note 2)	157,500			147,400
Current maturities of long-term debt (Note 2)	102,723			383,570
Accounts payable	321,860			289,930
Accrued taxes (Note 5)	199,492			131,110
Accrued interest	54,314			52,358
Common dividends payable	65,900			65,800
Customer deposits	72,785			72,307
Liabilities from risk management activities (Note 7)	60,673			59,676
Liabilities for asset retirements (Note 15)	28,543			32,462
Deferred fuel and purchased power regulatory liability (Note 3)	16,209			—
Other regulatory liabilities (Note 3)	136,273			130,549
Other current liabilities	132,800			167,302
Total current liabilities	1,349,072			1,532,464
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,601,294			2,571,365
Regulatory liabilities (Note 3)	1,016,991			1,051,196
Liabilities for asset retirements (Note 15)	419,072			358,288
Liabilities for pension benefits (Note 4)	397,160			424,508
Liabilities from risk management activities (Note 7)	87,689			50,602
Customer advances	120,063			123,052
Coal mine reclamation	200,155			198,292
Deferred investment tax credit	176,389			178,607
Unrecognized tax benefits (Note 5)	45,305			45,740
Other	159,574			144,823
Total deferred credits and other	5,223,692			5,146,473
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	14,640,785		$	14,215,004

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

53

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Six Months Ended   June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	154,440		$	172,285
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	282,172			246,324
Deferred fuel and purchased power	11,711			1,315
Deferred fuel and purchased power amortization	11,424			18,399
Allowance for equity funds used during construction	(18,569		)	(14,941		)
Deferred income taxes	24,442			34,133
Deferred investment tax credit	(2,218		)	28,875
Change in derivative instruments fair value	(225		)	49
Changes in current assets and liabilities:
Customer and other receivables	(9,250		)	(65,603		)
Accrued unbilled revenues	(84,683		)	(75,648		)
Materials, supplies and fossil fuel	(18,311		)	(9,435		)
Income tax receivable	—			135,179
Other current assets	(8,193		)	(14,120		)
Accounts payable	37,656			28,465
Accrued taxes	68,382			38,381
Other current liabilities	(31,408		)	31,296
Change in margin and collateral accounts — assets	(4,552		)	(2,107		)
Change in margin and collateral accounts — liabilities	26,853			(22,425		)
Change in other long-term assets	(6,765		)	(18,703		)
Change in other long-term liabilities	(27,136		)	(24,467		)
Net cash flow provided by operating activities	405,770			487,252
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(530,850		)	(388,752		)
Contributions in aid of construction	41,010			12,646
Allowance for borrowed funds used during construction	(8,527		)	(7,560		)
Proceeds from nuclear decommissioning trust sales	225,779			199,224
Investment in nuclear decommissioning trust	(234,651		)	(207,848		)
Other	(614		)	(678		)
Net cash flow used for investing activities	(507,853		)	(392,968		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	600,000			535,975
Short-term borrowings — net	10,100			19,650
Repayment of long-term debt	(344,847		)	(503,583		)
Dividends paid on common stock	(131,700		)	(125,100		)
Noncontrolling interests	(28,012		)	(15,869		)
Net cash flow provided by (used for) financing activities	105,541			(88,927		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	3,458			5,357
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	4,515			3,725
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	7,973		$	9,082
Supplemental disclosure of cash flow information
Cash paid (received) during the period for:
Income taxes, net of refunds	$	184		$	(134,399	)
Interest, net of amounts capitalized	$	82,651		$	88,461
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	38,985		$	19,668
Dividends declared but not yet paid	$	65,900		$	62,600

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

54

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)

	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount
Balance, January 1, 2014	71,264,947	$	178,162	$	2,379,696	$	1,804,398		$	(53,372	)	$	145,990		$	4,454,874
Net income						154,434						17,851			172,285
Other comprehensive income									3,972						3,972
Dividends on common stock						(125,200		)							(125,200		)
Other						3									3
Net capital activities by noncontrolling interests												(15,869		)	(15,869		)
Balance, June 30, 2014	71,264,947	$	178,162	$	2,379,696	$	1,833,635		$	(49,400	)	$	147,972		$	4,490,065
Balance, January 1, 2015	71,264,947	$	178,162	$	2,379,696	$	1,968,718		$	(48,333	)	$	151,609		$	4,629,852
Net income						145,230						9,210			154,440
Other comprehensive income									2,682						2,682
Dividends on common stock						(131,800		)							(131,800		)
Other						2									2
Net capital activities by noncontrolling interests												(28,012		)	(28,012		)
Balance, June 30, 2015	71,264,947	$	178,162	$	2,379,696	$	1,982,150		$	(45,651	)	$	132,807		$	4,627,164

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

55

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

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

56

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Other income:
Interest income	$	6		$	417		$	73		$	554
Gain on disposition of property	478			328			685			645
Miscellaneous	226			2,476			591			4,784
Total other income	$	710		$	3,221		$	1,349		$	5,983
Other expense:
Non-operating costs (a)	$	(1,878	)	$	(2,868	)	$	(4,395	)	$	(5,455	)
Loss on disposition of property	(251		)	(285		)	(894		)	(468		)
Miscellaneous	(320		)	1,676			(2,514		)	(610		)
Total other expense	$	(2,449	)	$	(1,477	)	$	(7,803	)	$	(6,533	)

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

57

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-2. Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended June 30, 2015											Three Months Ended June 30, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, April 1	$	(9,209	)		$	(37,267	)		$	(46,476	)	$	(20,364	)		$	(29,747	)		$	(50,111	)
OCI (loss) before reclassifications	25				(927		)		(902		)	40				(2,041		)		(2,001		)
Amounts reclassified from accumulated other comprehensive loss	874			(a)	853			(b)	1,727			1,954			(a)	758			(b)	2,712
Net current period OCI (loss)	899				(74		)		825			1,994				(1,283		)		711
Ending balance, June 30	$	(8,310	)		$	(37,341	)		$	(45,651	)	$	(18,370	)		$	(31,030	)		$	(49,400	)

(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.

	Six Months Ended June 30, 2015											Six Months Ended June 30, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(37,948	)		$	(48,333	)	$	(23,059	)		$	(30,313	)		$	(53,372	)
OCI (loss) before reclassifications	(775		)		(927		)		(1,702		)	(381		)		(2,041		)		(2,422		)
Amounts reclassified from accumulated other comprehensive loss	2,850			(a)	1,534			(b)	4,384			5,070			(a)	1,324			(b)	6,394
Net current period OCI (loss)	2,075				607				2,682			4,689				(717		)		3,972
Ending balance, June 30	$	(8,310	)		$	(37,341	)		$	(45,651	)	$	(18,370	)		$	(31,030	)		$	(49,400	)

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

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

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

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report.  For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see "Forward-Looking Statements" at the front of this report and "Risk Factors" in Part 1, Item 1A of the 2014 Form 10-K.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS.  APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS 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 address lessons learned from the Fukushima events. The independent assessment, named the "Near Term Task Force," recommended a number of proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans. The NRC has directed nuclear power plants to begin implementing some of the Near Term Task Force’s recommendations. To implement these recommendations, Palo Verde expects to spend approximately $19 million for capital enhancements to the plant through 2016 in addition to the approximate $112 million that has already been spent on capital enhancements as of June 30, 2015 (APS’s share is 29.1%).

Coal and Related Environmental Matters and Transactions.  APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants.  APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning GHG emissions.  On June 2, 2014, EPA proposed a rule to limit carbon dioxide emissions from existing power plants (the "Clean Power Plan").  EPA expects to finalize the proposal in summer 2015.  EPA’s nationwide CO₂ emissions reduction goal is 30% below 2005 emission levels.  In the Clean Power Plan, EPA proposed the second most stringent goal in the country for the state of Arizona, a 52% reduction.   EPA’s proposal for Arizona could force a shift in in-state generation from coal to natural gas and renewable generation.  Until EPA issues its final rule and the state of Arizona develops its implementation plan, we are unable to determine the actual impacts to APS.  We expect that our plans described below to close Cholla Unit 2 in 2016, and to cease burning coal at the other APS-owned units at Cholla (Units 1 and 3) by the mid-2020s, will help to facilitate compliance with the Clean Power Plan.  APS continually analyzes its long-range capital management plans to assess the potential effects of these changes, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to continue participation in such plants.

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Cholla

On September 11, 2014, APS announced that it will close its 260 megawatt Unit 2 at Cholla by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. (See Note 3 for details related to the resulting regulatory asset and Note 8 for details of the proposal.) APS believes that the environmental benefits of this proposal are greater in the long term than the benefits that would have resulted from adding the emissions control equipment.

Four Corners

Asset Purchase Agreement and Coal Supply Matters.  On December 30, 2013, APS purchased SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The final purchase price for the interest was approximately $182 million. In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction. On December 23, 2014, the ACC approved rate adjustments related to APS’s acquisition of SCE’s interest in Four Corners resulting in a revenue increase of $57.1 million on an annual basis. On February 23, 2015, the ACC decision approving the rate adjustments was appealed. APS intends to intervene and actively participate in the proceeding. We cannot predict when or how this appeal will be resolved.

Concurrently with the closing of the SCE transaction, BHP Billiton New Mexico Coal, Inc. ("BHP Billiton"), the parent company of BHP Navajo Coal Company ("BNCC"), the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to Navajo Transitional Energy Company, LLC ("NTEC"), a company formed by the Navajo Nation to own the mine and develop other energy projects. BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016. Also occurring concurrently with the closing, the Four Corners’ co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031 (the "2016 Coal Supply Agreement"). El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. The cash purchase price, which will be subject to certain adjustments at closing, is immaterial in amount, and the purchaser will assume El Paso's reclamation and decommissioning obligations associated with the 7% interest. Completion of the purchase is subject to the receipt of certain regulatory approvals and is expected to occur in July 2016.

When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.

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

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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 that the Four Corners participants are pursuing.  A federal environmental review was undertaken as part of the DOI review process, and culminated in the issuance by DOI of a record of decision on July 17, 2015. The record of decision provides the authority for the Bureau of Indian Affairs to sign the lease amendments and rights-of-way renewals, which we anticipate will occur in the near future. 

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

Transmission and Delivery.  APS is working closely with regulators to identify and plan for transmission needs that continue to support system reliability, access to markets and renewable energy development.  The capital expenditures table presented in the "Liquidity and Capital Resources" section below includes new APS transmission projects through 2017, along with other transmission costs for upgrades and replacements.  APS is also working to establish and expand smart grid technologies throughout its service territory to provide long-term benefits both to APS and its customers.  APS is strategically deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations, as well as the number of customers that experience outages, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

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

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits.  On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC

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to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.

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

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million.

The following table summarizes renewable energy sources in APS's renewable portfolio that are in operation and under development as of July 30, 2015.

	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar (a)	169	29
Purchased Power Agreements:
Solar	310	—
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	629	—
Total Distributed Energy: Solar (b)	425	27
Total Renewable Portfolio	1,223	56

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

(b) Includes rooftop solar facilities owned by third parties. Distributed generation is produced in DC and is converted to AC for reporting purposes.

APS is developing owned solar resources through the ACC-approved AZ Sun Program.  Under this program to date, APS estimates its investment commitment will be approximately $675 million.  Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.

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

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Demand Side Management.  In December 2009, Arizona regulators placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy.  The ACC initiated an Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard 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 standard became effective on January 1, 2011.

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

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

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

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.

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

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

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

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

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

Deregulation.  On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a "market" basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013, to explore technological advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and early 2015. No further action has been taken by the ACC to date.

Net Metering.  On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The fixed charge does not increase APS's revenue because it is credited to the LFCR.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.

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

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

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

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

Other Subsidiaries.

Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE will focus on new growth opportunities that leverage the Company’s core expertise in the electric energy industry.  BCE’s first initiative is a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.  The joint venture, named TransCanyon, is pursuing independent transmission opportunities within the eleven states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.  The joint venture, in collaboration with SCE, submitted a bid into California Independent System Operator’s ("CAISO") competitive solicitation process to design, build, own and operate a new 500 kV transmission line between Arizona and California, the Delaney to Colorado River Transmission Line.  The CAISO announced the winner of the bidding process in early July. The TransCanyon/SCE bid was not selected. TransCanyon continues to pursue other transmission development opportunities in the western United States consistent with its strategy.

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

Key Financial Drivers

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

Electric Operating Revenues.  For the years 2012 through 2014, retail electric revenues comprised approximately 93% of our total electric operating revenues.  Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.  These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth.  Retail customers in APS’s service territory increased 1.2% for the six-month period ended June 30, 2015 compared with the prior-year period.  For the three years 2012 through 2014, APS’s customer growth averaged 1.3% per year. We currently expect annual customer growth to

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average in the range of 2.0-3.0% for 2015 through 2017 based on our assessment of modestly improving economic conditions in Arizona. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.2% for the six-month period ended June 30, 2015 compared with the prior-year period, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, partially offset by improving economic conditions and customer growth.  For the three years 2012 through 2014, APS experienced annual decreases in retail electricity sales averaging 0.2%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average in the range of 0.5-1.5% during 2015 through 2017, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  A slower recovery of the Arizona economy could further impact these estimates.

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

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

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

Operations and Maintenance Expenses.  Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.  On September 30, 2014, Pinnacle West announced plan design changes to the group life and medical postretirement benefit plan, which reduced net periodic benefit costs. See Note 4.

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

Property Taxes.  Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates.  The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.7% of the assessed value for 2014 and 10.5% for 2013.  We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities.  (See Note 3 for property tax deferrals contained in the 2012 Settlement Agreement).

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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, 2015 compared with three-month period ended June 30, 2014.

Our consolidated net income attributable to common shareholders for the three months ended June 30, 2015 was $123 million, compared with consolidated net income of $132 million for the prior-year period.  The results reflect a decrease of approximately $10 million for the regulated electricity segment primarily due to higher depreciation and amortization, the effects of weather, and lower transmission revenues, partially offset by the Four Corners related rate change and lower interest charges.

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

	Three Months Ended June 30,
	2015			2014			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	608		$	615		$	(7	)
Operations and maintenance	(211		)	(211		)	—
Depreciation and amortization	(123		)	(105		)	(18		)
Taxes other than income taxes	(43		)	(44		)	1
All other income and expenses, net	9			10			(1		)
Interest charges, net of allowance for borrowed funds used during construction	(44		)	(48		)	4
Income taxes	(68		)	(75		)	7
Less income related to noncontrolling interests (Note 6)	(5		)	(9		)	4
Regulated electricity segment net income	123			133			(10		)
All other	—			(1		)	1
Net Income Attributable to Common Shareholders	$	123		$	132		$	(9	)

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Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $7 million lower for the three months ended June 30, 2015 compared with the prior-year period.  The following table summarizes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Effects of weather	$	(16	)	$	(5	)	$	(11	)
Lower transmission revenues	(8		)	—			(8		)
Changes in long-term wholesale contracted sales	(11		)	(7		)	(4		)
Four Corners related rate change	15			—			15
Miscellaneous items, net	4			3			1
Total	$	(16	)	$	(9	)	$	(7	)

Operations and maintenance.  Operations and maintenance expenses were comparable in total for the three months ended June 30, 2015 compared with the prior-year period and included the following:

• A decrease of $18 million for lower employee benefit costs primarily related to lower costs for other postretirement benefits, group insurance claims, and stock compensation;

• An increase of $10 million in fossil generation costs, primarily due to higher planned fossil plant maintenance costs as a result of more work being completed in the second quarter of 2015 compared with the second quarter of 2014; and

• An increase of $8 million related to higher nuclear generation costs.

Depreciation and amortization.  Depreciation and amortization expenses were $18 million higher for the three months ended June 30, 2015 compared with the prior-year period primarily related to:

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

• An increase of $5 million due to increased plant in service;

• An increase of $5 million related to the regulatory treatment of the Palo Verde sale leaseback, which is offset in noncontrolling interests; and

• An increase of $2 million due to other miscellaneous factors.

Interest charges, net of allowance for borrowed funds used during construction.  Interest charges, net of allowance for borrowed funds used during construction, decreased $4 million for the three months ended June 30, 2015 compared with the prior-year period, primarily because of lower interest rates in the current year.

Income Taxes.  Income taxes were $7 million lower for the three months ended June 30, 2015 compared with the prior-year period, primarily because of lower taxable income in the current year.

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Operating Results — Six-month period ended June 30, 2015 compared with six-month period ended June 30, 2014.

Our consolidated net income attributable to common shareholders for the six months ended June 30, 2015 was $139 million, compared with consolidated net income of $148 million for the prior-year period.  The results reflect a decrease of approximately $9 million for the regulated electricity segment primarily due to higher depreciation and amortization, partially offset by the Four Corners related rate change and lower interest charges.

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

	Six Months Ended June 30,
	2015			2014			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,056		$	1,051		$	5
Operations and maintenance	(426		)	(424		)	(2		)
Depreciation and amortization	(244		)	(207		)	(37		)
Taxes other than income taxes	(86		)	(90		)	4
All other income and expenses, net	13			15			(2		)
Interest charges, net of allowance for borrowed funds used during construction	(88		)	(97		)	9
Income taxes	(76		)	(81		)	5
Less income related to noncontrolling interests (Note 6)	(9		)	(18		)	9
Regulated electricity segment net income	140			149			(9		)
All other	(1		)	(1		)	—
Net Income Attributable to Common Shareholders	$	139		$	148		$	(9	)

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Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $5 million higher for the six months ended June 30, 2015 compared with the prior-year period.  The following table summarizes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Four Corners related rate change	$	26		$	—		$	26
Changes in long-term wholesale contracted sales	(19		)	(12		)	(7		)
Lower transmission revenues	(5		)	—			(5		)
Effects of weather	(5		)	(1		)	(4		)
Lower retail sales due to changes in customer usage patterns and related pricing, partially offset by customer growth	(5		)	(1		)	(4		)
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(24		)	(22		)	(2		)
Miscellaneous items, net	1			—			1
Total	$	(31	)	$	(36	)	$	5

Operations and maintenance.  Operations and maintenance expenses increased $2 million for the six months ended June 30, 2015 compared with the prior-year period primarily because of:

• An increase of $16 million in fossil generation costs, primarily due to higher planned fossil plant maintenance costs as a result of more work being completed in the first half of 2015 compared with the first half of 2014;

• An increase of $9 million related to higher nuclear generation costs;

• A decrease of $22 million for lower employee benefit costs primarily related to lower costs for other postretirement benefits and stock compensation; and

• A decrease of $1 million related to other miscellaneous factors.

Depreciation and amortization.  Depreciation and amortization expenses were $37 million higher for the six months ended June 30, 2015 compared with the prior-year period primarily related to:

• An increase of $11 million related to the 2015 amortization of the Four Corners cost deferrals and acquisition adjustment;

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

• An increase of $9 million due to increased plant in service;

• An increase of $10 million related to the regulatory treatment of the Palo Verde sale leaseback, which is offset in noncontrolling interests; and

• A decrease of $2 million due to other miscellaneous factors.

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Interest charges, net of allowance for borrowed funds used during construction.  Interest charges, net of allowance for borrowed funds used during construction, decreased $9 million for the six months ended June 30, 2015 compared with the prior-year period, primarily because of lower interest rates in the current year.

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, 2015, APS’s common equity ratio, as defined, was 55%.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.3 billion, assuming APS’s total capitalization remains the same.  This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

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

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the six months ended June 30, 2015 and 2014 (dollars in millions):

Pinnacle West Consolidated

	Six Months Ended June 30,						Net
	2015			2014			Change
Net cash flow provided by operating activities	$	394		$	465		$	(71	)
Net cash flow used for investing activities	(509		)	(393		)	(116		)
Net cash flow provided by (used for) financing activities	121			(72		)	193
Net increase in cash and cash equivalents	$	6		$	—		$	6

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Arizona Public Service Company

	Six Months Ended June 30,						Net
	2015			2014			Change
Net cash flow provided by operating activities	$	406		$	487		$	(81	)
Net cash flow used for investing activities	(508		)	(393		)	(115		)
Net cash flow provided by (used for) financing activities	106			(89		)	195
Net increase in cash and cash equivalents	$	4		$	5		$	(1	)

Operating Cash Flows

Six-month period ended June 30, 2015 compared with six-month period ended June 30, 2014.  Pinnacle West’s consolidated net cash provided by operating activities was $394 million in 2015 compared to $465 million in 2014, a decrease of $71 million in net cash provided.  The decrease is primarily related to a $135 million income tax refund received in the first quarter of 2014. The decrease is partially offset by a $47 million change in cash collateral posted, and other changes in working capital.

Other.  Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries.  The requirements of the Employee Retirement Income Security Act of 1974 ("ERISA") require us to contribute a minimum amount to the qualified plan.  We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount.  The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations.  Under ERISA, the qualified pension plan was 118% funded as of January 1, 2014 and 116% funded as of January 1, 2015.  Under GAAP, the qualified pension plan was 90% funded as of January 1, 2014 and 89% funded as of January 1, 2015. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.  Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We have made voluntary contributions of $80 million to our pension plan year-to-date in 2015. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

Investing Cash Flows

Six-month period ended June 30, 2015 compared with six-month period ended June 30, 2014.  Pinnacle West’s consolidated net cash used for investing activities was $509 million in 2015, compared to $393 million in 2014, an increase of $116 million in net cash used primarily related to increased capital expenditures.

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

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2015		2016		2017
APS
Generation:
Nuclear Fuel	$	78	$	87	$	79
Renewables	80		1		2
Environmental	43		178		180
New Gas Generation	62		81		264
Other Generation	176		184		204
Distribution	325		375		331
Transmission	192		113		146
Other (a)	100		92		79
Total APS	$	1,056	$	1,111	$	1,285

(a) Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’s existing fossil and nuclear plants.  Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment.  The estimated Renewables expenditures include 20 MW of utility-scale solar projects which were approved by the ACC in the 2014 RES Implementation Plan and the residential rooftop solar program.  We have not included estimated costs for Cholla’s compliance with MATS or EPA’s regional haze rule since we have challenged the regional haze rule judicially and we have proposed a compromise strategy to EPA, which, if approved, would allow us to avoid expenditures related to environmental control equipment. The portion of estimated costs through 2017 for installation of pollution control equipment needed to ensure Four Corners’ compliance with EPA’s regional haze rules have been included in the table above.  The portion of estimated costs through 2017 for incremental costs to comply with the CCR rule for Four Corners and Cholla have also been included in the table above. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. The table above does not include capital expenditures related to El Paso's 7% interest in Four Corners Units 4 and 5 of $3 million in 2015, $21 million in 2016 and $26 million in 2017. We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

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

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

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Financing Cash Flows and Liquidity

Six-month period ended June 30, 2015 compared with six-month period ended June 30, 2014.  Pinnacle West’s consolidated net cash provided by financing activities was $121 million in 2015, compared to $72 million of net cash used in 2014, an increase of $193 million in net cash provided.  The increase in net cash provided by financing activities is primarily due to $159 million lower repayments of long-term debt and $64 million higher issuances of long-term debt.

Significant Financing Activities.  On June 17, 2015, the Pinnacle West Board of Directors declared a dividend of $0.595 per share of common stock, payable on September 1, 2015 to shareholders of record on August 3, 2015.

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

On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% Notes due May 15, 2015.

On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness.

On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

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

Pinnacle West's $200 million revolving credit facility matures in May 2019.  At June 30, 2015, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the size of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At June 30, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

At June 30, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million facility that matures in May 2019.  APS may increase the size of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2015, APS had $158 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.

See "Financial Assurances" in Note 8 for a discussion of APS’s separate outstanding letters of credit.

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

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

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.  Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At June 30, 2015, the ratio was approximately 48% for Pinnacle West and 46% for APS.  Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could "cross-default" other debt.  See further discussion of "cross-default" provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain "rating triggers" that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.  However, our bank credit agreements and term loan facilities 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.

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Credit Ratings

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

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	A3	A-	A-
Commercial paper	P-2	A-2	F2
Outlook	Stable	Stable	Stable
APS
Corporate credit rating	A2	A-	A-
Senior unsecured	A2	A-	A
Secured lease obligation bonds	A2	A-	A
Commercial paper	P-1	A-2	F2
Outlook	Stable	Stable	Stable

Off-Balance Sheet Arrangements

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

Contractual Obligations

During the quarter our purchase obligations have increased by about $170 million relating to gas generation projects. The expected payments to be made are $26 million in 2015, $89 million in 2016, $46 million in 2017, and $9 million in 2018.

Other than the item described above, there have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2014 Form 10-K.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period.  Some of those judgments can be subjective and complex, and actual results could differ from those estimates.  There have been no changes to our critical accounting policies since our 2014 Form 10-K.  See "Critical Accounting Policies" in Item 7 of the 2014 Form 10-K for further details about our critical accounting policies.

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OTHER ACCOUNTING MATTERS

We are currently evaluating the impacts of adopting two new accounting standards: consolidation analysis guidance that will be adopted on January 1, 2016, and revenue recognition guidance that will be effective for us on January 1, 2018. Additionally, new guidance relating to balance sheet presentation of debt issuance costs will be effective for us during the first quarter of 2016. See Note 13.

MARKET AND CREDIT RISKS

Market Risks

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

Interest Rate and Equity Risk

We have exposure to changing interest rates.  Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 11 and Note 12) and benefit plan assets.  The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments.  Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

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

The following table shows the net pretax changes in mark-to-market of our derivative positions for the six months ended June 30, 2015 and 2014 (dollars in millions):

	Six Months Ended June 30,
	2015			2014
Mark-to-market of net positions at beginning of year	$	(115	)	$	(73	)
Decrease (increase) in regulatory asset/liability	(18		)	21
Recognized in OCI:
Mark-to-market losses realized during the period	3			8
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(130	)	$	(44	)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at June 30, 2015 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 

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See Note 1, "Derivative Accounting" and "Fair Value Measurements," in Item 8 of our 2014 Form 10-K and Note 11 for more discussion of our valuation methods.

Source of Fair Value	2015			2016			2017			2018			2019			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(34	)	$	(29	)	$	(20	)	$	(4	)	$	—		$	—		$	(87	)
Prices based on unobservable inputs	(8		)	(14		)	(8		)	(6		)	(5		)	(2		)	(43		)
Total by maturity	$	(42	)	$	(43	)	$	(28	)	$	(10	)	$	(5	)	$	(2	)	$	(130	)

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

	June 30, 2015 Gain (Loss)					December 31, 2014 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) or OCI (a)
Electricity	$	2	$	(2	)	$	3	$	(3	)
Natural gas	37		(37		)	29		(29		)
Total	$	39	$	(39	)	$	32	$	(32	)

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

Credit Risk

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

Item 3.        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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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, 2015.  Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of APS’s disclosure controls and procedures as of June 30, 2015.  Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended June 30, 2015 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

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PART II -- OTHER INFORMATION

Item 1.                   LEGAL PROCEEDINGS

See "Business of Arizona Public Service Company — Environmental Matters" in Item 1 of the 2014 Form 10-K with regard to pending or threatened litigation and other disputes.

See Note 3 for ACC and FERC-related matters.

See Note 8 for information regarding environmental matters, Superfund-related matters, matters related to a September 2011 power outage and a New Mexico tax matter.

Item 1A.                RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A — Risk Factors in the 2014 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS.  The risks described in the 2014 Form 10-K are not the only risks facing Pinnacle West and APS.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.   

Item 5.                OTHER INFORMATION

Environmental Matters

See "Environmental Matters - Mercury and Air Toxic Standards" in Note 8 for information regarding a recent United States Supreme Court decision related to MATS.

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Item 6.                EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
10.1	Pinnacle West APS	Term Loan Agreement dated as of June 26, 2015 among Arizona Public Service Company, as Borrower, Toronto Dominion (Texas) LLC, as Agent, Citibank, N.A., as Syndication Agent, and such institutions compromising the lenders party 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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31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1*	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	Pinnacle West APS	XBRL Instance Document
101.SCH	Pinnacle West APS	XBRL Taxonomy Extension Schema Document
101.CAL	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Pinnacle West APS	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Pinnacle West APS	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Pinnacle West APS	XBRL Taxonomy Definition Linkbase Document

_________________________________

*Furnished herewith as an Exhibit.

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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	8/3/2010
3.2	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/7/2008
3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form  8-K Report, File No. 1-4473	9/29/1993
3.4	APS	Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012	3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473	5/22/2012
3.5	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008	3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473	2/20/2009

_______________________________

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

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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 30, 2015	By:	/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)
	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)
Dated: July 30, 2015	By:	/s/ James R. Hatfield
		James R. Hatfield
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)

84

EX-10.1

Exhibit 10.1

U.S. $50,000,000

TERM LOAN AGREEMENT

Dated as of June 26, 2015

among

ARIZONA PUBLIC SERVICE COMPANY,

asBorrower,

THE LENDERS PARTY HERETO,

TORONTO DOMINION (TEXAS) LLC,

asAgent,

CITIBANK, N.A.,

asSyndicationAgent,

_______________________________________________________________________

TD SECURITIES (USA) LLC,

and

CITIBANK, N.A.

asJointLeadArrangersandasJointBookrunners

ACTIVE 208126585v.7

TABLE OF CONTENTS

ARTICLE I	DEFINITIONS AND ACCOUNTING TERMS	1
Section 1.01	Certain Defined Terms.	1
Section 1.02	Other Interpretive Provisions.	18
Section 1.03	Accounting Terms.	19
Section 1.04	Rounding.	19
Section 1.05	Times of Day.	19
ARTICLE II	AMOUNTS AND TERMS OF THE LOANS	19
Section 2.01	The Loans.	19
Section 2.02	Making the Loans.	19
Section 2.03	Agent’s Fees.	21
Section 2.04	Repayment of Loans.	21
Section 2.05	Interest on Loans.	21
Section 2.06	Interest Rate Determination.	22
Section 2.07	Optional Conversion of Loans.	23
Section 2.08	Prepayments of Loans.	23
Section 2.09	Increased Costs.	24
Section 2.10	Illegality.	25
Section 2.11	Payments and Computations.	26
Section 2.12	Taxes.	27
Section 2.13	Sharing of Payments, Etc.	31
Section 2.14	Evidence of Debt.	31
Section 2.15	Use of Proceeds.	32
Section 2.16	Affected Lenders.	32
Section 2.17	Replacement of Lenders.	32
ARTICLE III	CONDITIONS PRECEDENT	33
Section 3.01	Conditions Precedent to Effectiveness.	33
Section 3.02	Determinations Under Section 3.01.	35
ARTICLE IV	REPRESENTATIONS AND WARRANTIES	35
Section 4.01	Representations and Warranties of the Borrower.	35
ARTICLE V	COVENANTS OF THE BORROWER	39
Section 5.01	Affirmative Covenants.	39
Section 5.02	Negative Covenants.	43
Section 5.03	Financial Covenant.	45

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ARTICLE VI	EVENTS OF DEFAULT	45
Section 6.01	Events of Default.	45
ARTICLE VII	THE AGENT	47
Section 7.01	Appointment and Authority.	47
Section 7.02	Rights as a Lender.	47
Section 7.03	Exculpatory Provisions.	48
Section 7.04	Reliance by Agent.	48
Section 7.05	Delegation of Duties.	49
Section 7.06	Resignation of Agent.	49
Section 7.07	Non-Reliance on Agent and Other Lenders.	50
Section 7.08	No Other Duties, Etc.	50
ARTICLE VIII	MISCELLANEOUS	50
Section 8.01	Amendments, Etc.	50
Section 8.02	Notices, Etc.	51
Section 8.03	No Waiver; Cumulative Remedies; Enforcement.	53
Section 8.04	Costs and Expenses; Indemnity; Damage Waiver.	54
Section 8.05	Right of Set-off.	55
Section 8.06	Effectiveness; Binding Effect.	56
Section 8.07	Successors and Assigns.	56
Section 8.08	Confidentiality.	59
Section 8.09	Governing Law.	60
Section 8.10	Counterparts; Integration.	60
Section 8.11	Jurisdiction, Etc.	60
Section 8.12	Payments Set Aside.	61
Section 8.13	Patriot Act.	61
Section 8.14	Waiver of Jury Trial.	61
Section 8.15	No Advisory or Fiduciary Responsibility.	61
Section 8.16	Survival of Representations and Warranties.	62
Section 8.17	Severability.	62
Schedules
Schedule 1.01	Commitments and Ratable Shares
Schedule 4.01(j)	Subsidiaries
Schedule 4.01(k)	Existing Indebtedness
Schedule 8.02	Certain Addresses for Notices

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Exhibits
Exhibit A	Form of Note
Exhibit B	Form of Notice of Initial Borrowing
Exhibit C	Form of Assignment and Assumption
Exhibit D	Form of Interest Election Request
Exhibit E	Form of Prepayment Notice

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TERM LOAN AGREEMENT
Dated as of June 26, 2015

ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation (the “Borrower”), the banks, financial institutions and other institutional lenders (the “Initial Lenders”) listed on the signature pages hereof, CITIBANK, N.A., as Syndication Agent and TORONTO DOMINION (TEXAS) LLC, as Agent for the Lenders (as hereinafter defined), agree as follows:

The Borrower has requested that the Lenders provide a $50,000,000 term loan facility for the purposes set forth herein, and the Lenders are willing to do so on the terms and conditions set forth herein.

In consideration of the mutual covenants and agreements herein contained, the parties hereto covenant and agree as follows:

Article IDEFINITIONS AND ACCOUNTING TERMS

Section 1.01Certain Defined Terms. As used in this Agreement, the following terms shall have the following meanings:

“2013 Order” means Decision No. 73659, dated February 6, 2013, of the Arizona Corporation Commission.

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Agent.

“Affected Lender” means any Lender, as reasonably determined by the Agent or, if the Agent is the Affected Lender, by the Required Lenders, that (a) has failed to (i) fund all or any portion of its Loans or (ii) pay to the Agent or any other Lender any other amount required to be paid by it under this Agreement, (b) has notified the Borrower, the Agent or any Lender in writing of its intention not to fund a Loan or any of its other funding obligations under this Agreement, (c) has failed, within three Business Days after written request by the Agent, or, if the Agent is the Affected Lender, by the Required Lenders, to confirm that it will comply with the terms of this Agreement relating to its obligations to fund a Loan or (d) shall (or whose parent company shall) generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or shall have had any proceeding instituted by or against such Lender (or its parent company) seeking to adjudicate it as bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or custodian for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it), either

such proceeding shall remain undismissed or unstayed for a period of 30 days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or custodian for, it or for any substantial part of its property) shall occur, or shall take (or whose parent company shall take) any corporate action to authorize any of the actions set forth above in this subsection (d), provided that a Lender shall not be deemed to be an Affected Lender solely by virtue of the ownership or acquisition of any equity interest in such Lender or any Person that directly or indirectly controls such Lender by a Governmental Authority or an instrumentality thereof.

“Affiliate” means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person. For purposes of this definition, the term “control” (including the terms “controlling”, “controlled by” and “under common control with”) of a Person means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of Voting Stock, by contract or otherwise.

“Agent” means Toronto Dominion (Texas) LLC, (including its branches and Affiliates as may be required to administer its duties) in its capacity as administrative agent under any of the Loan Documents, or any successor administrative agent.

“Agent’s Account” means the account of the Agent designated as such by the Agent to the Lenders and the Borrower from time to time.

“Agent’s Office” means the Agent’s address specified in Section 8.02(a) and, as appropriate, the Agent’s Account, or such other address or account as the Agent may from time to time notify to the Borrower and the Lenders.

“Agreement” means this Term Loan Agreement, dated as of June 26, 2015, among the Borrower, the Lenders named herein and from time to time party hereto, the Syndication Agent and the Agent, together with all schedules and exhibits hereto.

“Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Borrower or its Subsidiaries from time to time concerning or relating to bribery, corruption or money laundering.

“Applicable Lending Office” means, with respect to each Lender, such Lender’s Domestic Lending Office in the case of a Base Rate Loan and such Lender’s Eurodollar Lending Office in the case of a Eurodollar Rate Loan.

“Applicable Rate” means, from time to time, the following percentages per annum determined by reference to the Public Debt Rating as set forth below:

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Public Debt Rating S&P/Moody’s	Base Rate Loan		Eurodollar Rate Loan
Level 1 ≥ A/A2	0.000	%	0.60	%
Level 2 < Level 1 but  ≥ A-/A3	0.000	%	0.65	%
Level 3 < Level 2 but ≥ BBB+/Baa1	0.000	%	0.75	%
Level 4 < Level 3 but > BBB/Baa2	0.000	%	0.95	%
Level 5 < Level 4	0.10	%	1.10	%

“Approved Fund” means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of any entity that administers or manages a Lender.

“Arrangers” means each of TD Securities (USA) LLC, and Citibank, N.A., together with their successors and assigns.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an Eligible Assignee, and accepted by the Agent, in substantially the form of Exhibit C hereto.

“Authorized Officer” means the chairman of the board, chief executive officer, chief operating officer, chief financial officer, chief accounting officer, president, any vice president, treasurer, controller or any assistant treasurer of the Borrower.

“Base Rate” means for any day a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus ½ of 1.00% and (c) the Eurodollar Rate for a one month Interest Period on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1.00%, provided that, for the avoidance of doubt, the Eurodollar Rate for any day shall be based on the Eurodollar Rate at approximately 11:00 a.m. London time on such day, subject to the interest rate floors set forth therein. Any change in the Base Rate due to a change in the Prime Rate, the Federal Funds Rate or the Eurodollar Rate shall be effective from and including the effective date of such change in the Prime Rate, the Federal Funds Rate or the Eurodollar Rate, respectively.

“Base Rate Loan” means a Loan that bears interest as provided in Section 2.05(a)(i).

“Borrower” has the meaning given to such term in the introductory paragraph hereof.

“Borrower Information” has the meaning specified in Section 8.08.

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“Borrowing” means Loans of the same Type that are made, Converted or continued on the same date and, in the case of Eurodollar Rate Loans, as to which a single Interest Period is in effect.

“Business Day” means a day of the year on which banks are not required or authorized by Law to close in New York, New York or Phoenix, Arizona and, if the applicable Business Day relates to any Loan in which interest is calculated by reference to the Eurodollar Rate, on which dealings are carried on in the London interbank market.

“Capital Lease” means, at any time, a lease with respect to which the lessee is required concurrently to recognize the acquisition of an asset and the incurrence of a liability in accordance with GAAP.

“Capital Lease Obligations” means as to any Person, the obligations of such Person to pay rent or other amounts under a lease of (or other agreement conveying the right to use) real and/or personal property, which obligations are required to be classified and accounted for as a Capital Lease on the balance sheet of such Person under GAAP and, for the purposes of this Agreement, the amount of such obligations shall be the capitalized amount thereof, determined in accordance with GAAP.

“Change in Law” means the occurrence, after the date of this Agreement, of any of the following: (a) the adoption of any Law, (b) any change in any Law or in the administration, interpretation or application thereof by any Governmental Authority or (c) the making or issuance of any request, rules, guideline, requirement or directive (whether or not having the force of law) by any Governmental Authority; provided, however, that notwithstanding anything herein to the contrary, (i) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines, requirements and directives thereunder, issued in connection therewith or in implementation thereof, and (ii) all requests, rules, guidelines, requirements and directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed a “Change in Law” regardless of the date enacted, adopted, issued or implemented.

“Commitment” means, as to any Lender, its obligation to make a Loan to the Borrower pursuant to Section 2.01, in an aggregate principal amount not to exceed the amount set forth opposite such Lender’s name on Schedule 1.01 under the column “Commitment”. “Commitments” means the total of the Lenders’ Commitments hereunder. The Commitments shall in no event exceed $50,000,000.

“Consolidated” refers to the consolidation of accounts in accordance with GAAP.

“Consolidated Indebtedness” means, at any date, the Indebtedness of the Borrower and its Consolidated Subsidiaries determined on a Consolidated basis as of such date; provided, however, that so long as the creditors of the VIE Lessor Trusts have no recourse to the assets of the Borrower, “Consolidated Indebtedness” shall not include any Indebtedness or other obligations of the VIE Lessor Trusts.

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“Consolidated Net Worth” means, at any date, the sum as of such date of (a) the par value (or value stated on the books of the Borrower) of all classes of capital stock of the Borrower and its Subsidiaries, excluding the Borrower’s capital stock owned by the Borrower and/or its Subsidiaries, plus (or minus in the case of a surplus deficit) (b) the amount of the Consolidated surplus, whether capital or earned, of the Borrower, determined in accordance with GAAP as of the end of the most recent calendar month (excluding the effect on the Borrower’s accumulated other comprehensive income/loss of the ongoing application of Accounting Standards Codification Topic 815).

“Consolidated Subsidiary” means, at any date, any Subsidiary or other entity the accounts of which would be Consolidated with those of the Borrower on its Consolidated financial statements if such financial statements were prepared as of such date; provided that in no event will Consolidated Subsidiaries include the VIE Lessor Trusts.

“Controlled Affiliate” has the meaning specified in Section 4.01(n).

“Convert”, “Conversion” and “Converted” each refers to a conversion of Loans of one Type into Loans of the other Type pursuant to Section 2.06, Section 2.07 or Section 2.10.

“Debtor Relief Laws” means the Bankruptcy Code of the United States of America, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief Laws of the United States of America or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.

“Default” means any Event of Default or any event that would constitute an Event of Default but for the requirement that notice be given or time elapse or both.

“Dollars” or “$” means dollars of the United States of America.

“Domestic Lending Office” means, with respect to any Lender, the office of such Lender described as such in such Lender’s Administrative Questionnaire, or such other office or offices as a Lender may from time to time notify the Borrower and the Agent.

“Effective Date” has the meaning specified in Section 3.01.

“Eligible Assignee” means any Person that meets the requirements to be an assignee under Section 8.07(b)(iii) and (v), (subject to such consents, if any, as may be required under Section 8.07(b)(iii)).

“Environmental Action” means any action, suit, demand, demand letter, claim, notice of non-compliance or violation, notice of liability or potential liability, investigation, proceeding, consent order or consent agreement relating in any way to any Environmental Law, Environmental Permit or Hazardous Materials or arising from alleged injury or threat of injury to health, safety or the environment and relating to any Environmental Law, including, without limitation, (a) by any Governmental Authority for enforcement, cleanup, removal, response, remedial or other actions or

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damages and (b) by any Governmental Authority or any third party for damages, contribution, indemnification, cost recovery, compensation or injunctive relief.

“Environmental Law” means any federal, state, local or foreign statute, law, ordinance, rule, regulation, code, order, judgment, decree or judicial or agency interpretation, policy or guidance relating to pollution or protection of the environment, natural resources or, to the extent relating to exposure to Hazardous Materials, human health or safety, including, without limitation, those relating to the use, handling, transportation, treatment, storage, disposal, release or discharge of Hazardous Materials.

“Environmental Permit” means any permit, approval, identification number, license or other authorization required under any Environmental Law.

“ERISA” means the Employee Retirement Income Security Act of 1974.

“ERISA Affiliate” means any trade or business (whether or not incorporated) under common control with the Borrower within the meaning of Section 414(b) or (c) of the Internal Revenue Code (and Sections 414(m) and (o) of the Internal Revenue Code for purposes of provisions relating to Section 412 of the Internal Revenue Code).

“ERISA Event” means (a) a Reportable Event with respect to a Pension Plan; (b) a withdrawal by the Borrower or any ERISA Affiliate from a Pension Plan subject to Section 4063 of ERISA during a plan year in which it was a substantial employer (as defined in Section 4001(a)(2) of ERISA) or a cessation of operations that is treated as such a withdrawal under Section 4062(e) of ERISA; (c) a complete or partial withdrawal by the Borrower or any ERISA Affiliate from a Multiemployer Plan or notification that a Multiemployer Plan is in reorganization; (d) the filing of a notice of intent to terminate, the treatment of a Plan amendment as a termination under Section 4041 or 4041A of ERISA, or the commencement of proceedings by the PBGC to terminate a Pension Plan or Multiemployer Plan; (e) an event or condition which constitutes grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Pension Plan or Multiemployer Plan; or (f) the imposition of any liability under Title IV of ERISA, other than for PBGC premiums due but not delinquent under Section 4007 of ERISA, upon the Borrower or any ERISA Affiliate.

“Eurodollar Lending Office” means, with respect to any Lender, the office of such Lender described as such in such Lender’s Administrative Questionnaire, or such other office or offices as a Lender may from time to time notify the Borrower and the Agent.

“Eurodollar Rate” means, with respect to any Eurodollar Rate Loan for any applicable Interest Period, the London interbank offered rate as administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate) for Dollars for a period equal in length to such Interest Period as displayed on pages LIBOR01 or LIBOR02 of the Reuters screen, or in the event such rate does not appear on either of such Reuters pages, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that publishes such rate as shall be selected by the Agent from time to time in its reasonable discretion (in each case the “LIBOR Screen Rate”) at approximately 11:00

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a.m., London time, two (2) Business Days prior to the commencement of such Interest Period; provided that, if the LIBOR Screen Rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement; provided, further, that if a LIBOR Screen Rate shall not be available at such time for such Interest Period (the “Impacted Interest Period”), then the Eurodollar Rate for such Interest Period shall be the Interpolated Rate; provided, that, if any Interpolated Rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement. It is understood and agreed that all of the terms and conditions of this definition of “Eurodollar Rate” shall be subject to Section 2.06.

“Eurodollar Rate Loan” means a Loan that bears interest at a rate based on the Eurodollar Rate (other than a Base Rate Loan bearing interest at a rate based on the Eurodollar Rate).

“Events of Default” has the meaning specified in Section 6.01.

“Excluded Taxes” means, with respect to the Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of the Borrower hereunder, (a) Taxes imposed on or measured by its overall net income (however denominated), and franchise Taxes imposed on it (in lieu of net income Taxes), by the United States of America or the jurisdiction (or any political subdivision thereof) under the Laws of which such recipient is organized or does business or in which its principal office is located or, in the case of any Lender, in which its Applicable Lending Office is located, (b) any branch profits Taxes imposed by the United States of America or any similar Tax imposed by any other jurisdiction in which the Borrower is located, (c) any backup withholding Tax that is required by the Internal Revenue Code to be withheld from amounts payable to a Lender that has failed to comply with clause (A) of Section 2.12(e)(ii), (d) in the case of a Foreign Lender (other than as agreed to between any assignee and the Borrower pursuant to a request by the Borrower under Section 2.17), any United States of America withholding Tax that (i) is required to be imposed on amounts payable to such Foreign Lender pursuant to the Laws in force at the time such Foreign Lender becomes a party hereto (or designates a new Applicable Lending Office) or (ii) is attributable to such Foreign Lender’s failure or inability (other than as a result of a Change in Law) to comply with clause (B) of Section 2.12(e)(ii), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new Applicable Lending Office (or assignment), to receive additional amounts from the Borrower with respect to such withholding Tax pursuant to Section 2.12(a)(i) or (ii); and (e) any United States withholding Tax imposed by FATCA.

“Executive Order” has the meaning specified in Section 4.01 (p).

“FATCA” means Sections 1471 through 1474 of the Internal Revenue Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreement entered into pursuant to Section 1471(b)(1) of the Internal Revenue Code.

“Federal Funds Rate” means, for any day, the weighted average (rounded upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next

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succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day for such transactions received by the Agent from three Federal funds brokers of recognized standing selected by the Agent; provided that if the Federal Funds Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“Fee Letter” means that certain Administrative Agent Fee Letter dated as June 26, 2015, between the Agent and the Borrower, as amended, modified, restated or supplemented from time to time.

“Foreign Lender” means any Lender that is organized under the Laws of a jurisdiction other than that in which the Borrower is resident for tax purposes. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“Four Corners Acquisition” means the acquisition by the Borrower from Southern California Edison Company (“SCE”) of SCE’s interests in Units 4 and 5 of the Four Corners Power Plant near Farmington, New Mexico, pursuant to the Purchase and Sale Agreement, dated as of November 8, 2010, by and between SCE and the Borrower.

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” has the meaning specified in Section 1.03.

“Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank) and any group or body charged with setting financial accounting or regulatory capital rules or standards (including, without limitation, the Financial Accounting Standards Board, the Bank for International Settlements or the Basel Committee on Banking Supervision or any successor or similar authority to any of the foregoing).

“Government Official” shall mean (a) an executive, official, employee or agent of a governmental department, agency or instrumentality, (b) a director, officer, employee or agent of a wholly or partially government owned or controlled company or business, (c) a political party or official thereof, or candidate for political office or (d) an executive, official, employee or agent of a public international organization (e.g., the International Monetary Fund or the World Bank).

“Guarantee” means as to any Person, any obligation, contingent or otherwise, of such Person directly or indirectly guaranteeing any Indebtedness of any other Person or in any manner providing for the payment of any Indebtedness of any other Person or otherwise protecting the holder of such

8

Indebtedness against loss (whether by virtue of partnership arrangements, agreements to keep well, to purchase assets, goods, securities or services, or to take-or-pay or otherwise), provided that the term “Guarantee” shall not include endorsements for collection or deposit in the ordinary course of business. The term “Guarantee” used as a verb has a corresponding meaning.

“Hazardous Materials” means (a) petroleum and petroleum products, byproducts or breakdown products, radioactive materials, asbestos-containing materials, polychlorinated biphenyls and radon gas and (b) any other chemicals, materials or substances designated, classified or regulated as hazardous or toxic or as a pollutant or contaminant under any Environmental Law.

“Hedge Agreement” means any interest rate swap, cap or collar agreement, interest rate future or option contract, currency swap agreement, currency future or option contract, commodity future or option contract, commodity forward contract or other similar agreement.

“Impacted Interest Period” has the meaning assigned to such term in the definition of “Eurodollar Rate”.

“Indebtedness” means as to any Person at any date (without duplication): (a) indebtedness created, issued, incurred or assumed by such Person for borrowed money or evidenced by bonds, debentures, notes or similar instruments; (b) all obligations of such Person to pay the deferred purchase price of property or services, excluding, however, trade accounts payable (other than for borrowed money) arising in, and accrued expenses incurred in, the ordinary course of business of such Person so long as such trade accounts payable are paid within 180 days of the date incurred (unless subject to a good faith dispute); (c) all Indebtedness secured by a Lien on any asset of such Person, to the extent such Indebtedness has been assumed by, or is a recourse obligation of, such Person; (d) all Guarantees by such Person; (e) all Capital Lease Obligationsof such Person; and (f) the amount of all reimbursement obligations of such Person (whether contingent or otherwise) in respect of letters of credit, bankers’ acceptances, surety or other bonds and similar instruments in support of Indebtedness.

“Indemnified Taxes” means Taxes other than Excluded Taxes.

“Ineligible Institution” means (a) a natural person, (b) an Affected Lender or any of its Subsidiaries, (c) the Borrower, any of its Subsidiaries or any of its Affiliates, or (d) a company, investment vehicle or trust for, or owned and operated for the primary benefit of, a natural person or relative(s) thereof.

“Initial Borrowing” means the Loans made by the Initial Lenders on the Effective Date pursuant to Section 2.01 hereof.

“Initial Lenders” has the meaning given to such term in the introductory paragraph hereof.

“Interest Election Request” means a written request by the Borrower to Convert or continue a Borrowing in accordance with the definition of “Interest Period” contained in this Section 1.01 and/or Section 2.07, as applicable, in each case in substantially the form of Exhibit D hereto.

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“Interest Period” means, for each Eurodollar Rate Loan comprising part of the same Borrowing, the period commencing on (i) the date such Eurodollar Rate Loan is disbursed, (ii) the date of the Conversion of any Base Rate Loan into such Eurodollar Rate Loan or (iii) the effective date of the most recent continuation of such Eurodollar Rate Loan, as the case may be, and ending on the last day of the period selected by the Borrower pursuant to the provisions below and, thereafter, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by the Borrower pursuant to the provisions below. The duration of each such Interest Period shall be one, two, three or six months, as the Borrower may, upon notice (in the form of an Interest Election Request duly completed and executed by the Borrower) received by the Agent not later than 12:00 noon on the third Business Day prior to the first day of such Interest Period, select; provided, however, that:

(a)    the Borrower may not select any Interest Period that ends after the Maturity Date;

(b)    Interest Periods commencing on the same date for Eurodollar Rate Loans comprising part of the same Borrowing shall be of the same duration;

(c)    whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, provided, however, that, if such extension would cause the last day of such Interest Period to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day; and

(d)    whenever the first day of any Interest Period occurs on a day of an initial calendar month for which there is no numerically corresponding day in the calendar month that succeeds such initial calendar month by the number of months equal to the number of months in such Interest Period, such Interest Period shall end on the last Business Day of such succeeding calendar month.

“Internal Revenue Code” means the Internal Revenue Code of 1986, as amended from time to time, and the regulations promulgated and rulings issued thereunder.

“Interpolated Rate” means, at any time, the rate per annum determined by the Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the LIBOR Screen Rate for the longest period (for which the LIBOR Screen Rate is available) that is shorter than the Impacted Interest Period and (b) the LIBOR Screen Rate for the shortest period (for which the LIBOR Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

“Laws” means, collectively, all international, foreign, Federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, licenses, authorizations and permits of, and agreements with, any Governmental Authority.

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“Lenders” means the Initial Lenders and each Person that shall become a party hereto pursuant to Section 8.07.

“Lien” means any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or otherwise), charge or other security interest or preferential arrangement that has the practical effect of creating a security interest, including, without limitation, the lien or retained security title of a conditional vendor and any easement, right of way or other encumbrance on title to real property, and any Capital Lease having substantially the same economic effect as any of the foregoing.

“LIBOR Screen Rate” has the meaning assigned to such term in the definition of “Eurodollar Rate”.

“Loans” has the meaning specified in Section 2.01.

“Loan Documents” mean this Agreement, each Note and the Fee Letter.

“Material Adverse Effect” means a material adverse effect on (a) the financial condition, operations, business or properties of the Borrower and its Subsidiaries taken as a whole, (b) the rights and remedies of the Agent or any Lender under this Agreement or any Note or (c) the ability of the Borrower to perform its obligations under this Agreement or any Note.

“Material Subsidiary” means at any time, any Subsidiary of the Borrower which as of such time meets the definition of a “significant subsidiary” included as of the date hereof in Regulation S-X of the Securities and Exchange Commission or whose assets at such time exceed 10% of the assets of the Borrower and the Subsidiaries (on a Consolidated basis).

“Maturity Date” means June 26, 2018.

“Moody’s” means Moody’s Investors Service, Inc.

“Multiemployer Plan” means any employee benefit plan of the type described in Section 4001(a)(3) of ERISA, to which the Borrower or any ERISA Affiliate makes or is obligated to make contributions, or during the preceding five plan years, has made or been obligated to make contributions.

“Note” means a promissory note of the Borrower payable to the order of any Lender, delivered pursuant to a request made under Section 2.14, in substantially the form of Exhibit A hereto.

“Notice of Initial Borrowing” has the meaning specified in Section 2.02(a).

“Obligations” means all loans to, and debts, liabilities, obligations, covenants and duties of, the Borrower arising under any Loan Document or otherwise with respect to any Loan, whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising and including interest and fees that accrue under any Loan Document after the commencement by or against the Borrower of any proceeding under any Debtor

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Relief Laws naming such Person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding.

“OFAC” means Office of Foreign Assets Control of the United States Department of the Treasury.

“Other Taxes” means all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or under any other Loan Document or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement or any other Loan Document.

“Participant” has the meaning specified in Section 8.07(d).

“Participant Register” has the meaning specified in Section 8.07(d).

“PATRIOT Act” means the USA PATRIOT Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)), as amended.

“PBGC” means the Pension Benefit Guaranty Corporation.

“Pension Plan” means any “employee pension benefit plan” (as such term is defined in Section 3(2) of ERISA), other than a Multiemployer Plan, that is subject to Title IV of ERISA and is sponsored or maintained by the Borrower or any ERISA Affiliate or to which the Borrower or any ERISA Affiliate contributes or has an obligation to contribute, or in the case of a multiple employer or other plan described in Section 4064(a) of ERISA, has made contributions at any time during the immediately preceding five plan years.

“Permitted Lien” of the Borrower or any Material Subsidiary means any of the following:

(i)Liens for taxes, assessments or other governmental charges or levies not at the time delinquent or thereafter payable without penalty or being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been made;

(ii)Liens imposed by or arising by operation of law, such as Liens of carriers, warehousemen, mechanics, materialmen and landlords incurred in the ordinary course of business, including, without limitation, landlord’s liens arising under Arizona Law under leases entered into by the Borrower in the 1986 sale and leaseback transactions with respect to PVNGS Unit 2 and securing the payment of rent under such leases, in each case, for sums not overdue for a period of more than 30 days or being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been made;

(iii)Liens incurred in the ordinary course of business in connection with worker’s compensation, unemployment insurance or other forms of governmental insurance or benefits or other similar statutory obligations;

(iv)Liens to secure obligations on surety or appeal bonds;

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(v)Liens on cash deposits in the nature of a right of setoff, banker’s lien, counterclaim or netting of cash amounts owed arising in the ordinary course of business on deposit accounts, commodity accounts or securities accounts;

(vi)easements, restrictions, reservations, licenses, covenants, and other defects of title that are not, in the aggregate, materially adverse to the use of such property for the purpose for which it is used;

(vii)Liens securing claims against or other obligations of any Person other than the Borrower or any Subsidiary of the Borrower neither assumed nor guaranteed by the Borrower or any Subsidiary of the Borrower nor on which the Borrower or any Subsidiary of the Borrower customarily pays interest, existing upon real estate or rights in or relating to real estate acquired by the Borrower or any Subsidiary of the Borrower for use in the operation of the business of the Borrower or any Subsidiary of the Borrower, including, without limitation, for the generation, transmission or distribution of electric energy, transportation, telephonic, telegraphic, radio, wireless or other electronic communication or any other purpose;

(viii)rights reserved to or vested in and Liens on assets arising out of obligations or duties to any municipality or public authority with respect to any right, power, franchise, grant, license or permit, or by any provision of Law;

(ix)rights reserved to or vested in others to take or receive any part of the power pursuant to firm power commitment contracts, purchased power contracts, tolling agreements and similar agreements, coal, gas, oil or other minerals, timber or other products generated, developed, manufactured or produced by, or grown on, or acquired with, any property of the Borrower;

(x)rights reserved to or vested in any municipality or public authority to control or regulate any property of the Borrower, or to use such property in a manner that does not materially impair the use of such property for the purposes for which it is held by the Borrower;

(xi)security interests granted in favor of the lessors in the Borrower’s Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 (such agreement, as amended or otherwise modified from time to time, being the “Unit 2 Trust Agreement”) entered into in connection with the PVNGS Unit 2 sale leaseback transaction to secure the Borrower’s obligations in respect of the decommissioning of PVNGS Unit 2 or related facilities;

(xii)Liens that may exist with respect to the Unit 2 Trust Agreement (other than as described in paragraph (xi) above) or with respect to either of the Borrower’s Decommissioning Trust Agreement (PVNGS Unit 1) or Decommissioning Trust Agreement (PVNGS Unit 3), each dated as of July 1, 1991, as amended or otherwise modified from time to time, relating to the Borrower’s obligation to set aside funds for the decommissioning and retirement from service of such Units;

(xiii)pledges of pollution control bonds and related rights to secure the Borrower’s reimbursement obligations in respect of letters of credit, bond insurance, and other credit or liquidity enhancements supporting pollution control bond transactions, provided that such pollution control bonds are not secured by any other assets of the Borrower or any Material Subsidiary;

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(xiv)rights and interests of Persons other than the Borrower or any Material Subsidiary (including, without limitation, acquisition rights), related obligations of the Borrower or any Material Subsidiary and restrictions on it or its property arising out of contracts, agreements and other instruments to which the Borrower or any Material Subsidiary is a party that relate to the common ownership or joint use of property or other use of property for the benefit of one or more third parties or that allow a third party to purchase property of the Borrower or any Material Subsidiary and all Liens on the interests of Persons other than the Borrower or any Material Subsidiary in such property;

(xv)transfers of operational or other control of facilities to a regional transmission organization or other similar body and Liens on such facilities to cover expenses, fees and other costs of such an organization or body;

(xvi)Liens established on specified bank accounts of the Borrower to secure the Borrower’s reimbursement obligations in respect of letters of credit supporting commercial paper issued by the Borrower and similar arrangements for collateral security with respect to refinancings or replacements of the same;

(xvii)rights of transmission users or any regional transmission organizations or similar entities in transmission facilities;

(xviii)Liens on property of the Borrower sold in a transaction permitted by Section 5.02(a) to another Person pursuant to a conditional sales agreement where the Borrower retains title;

(xix)Liens created under this Agreement;

(xx)Liens on cash or cash equivalents not to exceed $200,000,000 (A) deposited in margin accounts with or on behalf of futures contract brokers or paid over to other contract counterparties or (B) pledged or deposited as collateral to a contract counterparty to secure obligations with respect to (1) contracts (other than for Indebtedness) for commercial and trading activities in the ordinary course of business for the purchase, transmission, distribution, sale, storage, lease or hedge of any energy or energy related commodity or (2) Hedge Agreements;

(xxi)Liens granted on cash or cash equivalents to defease Indebtedness of the Borrower or any of its Subsidiaries;

(xxii)Liens granted on cash or cash equivalents constituting proceeds from any sale or disposition of assets that is not prohibited by Section 5.02(c) deposited in escrow accounts or otherwise withheld or set aside to secure obligations of the Borrower or any Subsidiary providing for indemnification, adjustment of purchase price or any similar obligations, in each case, in an amount not to exceed the amount of gross proceeds received by the Borrower or any Subsidiary in connection with such sale or disposition;

(xxiii)Liens, deposits and similar arrangements to secure the performance of bids, tenders or contracts (other than contracts for borrowed money), public or statutory obligations, performance bonds and other obligations of a like nature incurred in the ordinary course of business by the Borrower or any of its Subsidiaries;

(xxiv)rights of lessees arising under leases entered into by the Borrower or any of its Subsidiaries as lessor, in the ordinary course of business;

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(xxv)any Liens on or reservations with respect to governmental and other licenses, permits, franchises, consents and allowances;

(xxvi)Liens on property which is the subject of a Capital Lease Obligation designating the Borrower or any of its Subsidiaries as lessee and all right, title and interest of the Borrower or any of its Subsidiaries in and to such property and in, to and under such lease agreement, whether or not such lease agreement is intended as a security;

(xxvii)licenses of intellectual property entered into in the ordinary course of business;

(xxviii) Liens solely on any cash earnest money deposits made by the Borrower or any of its Subsidiaries in connection with any letter of intent or purchase agreement permitted hereunder;

(xxix) deposits or funds established for the removal from service of operating facilities and coal mines and related facilities or other similar facilities used in connection therewith; and

(xxx)Liens on cash deposits used to secure letters of credit under defaulting lender provisions in credit or reimbursement facilities;

provided, however, that no Lien in favor of the PBGC shall, in any event, be a Permitted Lien.

“Percentage” means, with respect to any Lender at any time, a fraction the numerator of which is the outstanding principal amount of such Lender’s Loans at such time and the denominator of which is the aggregate outstanding principal amount of all Loans at such time; provided, that (i) the initial Percentage of each Lender shall be the percentage set forth opposite such Lender’s name on Schedule 1.01 under the column “Ratable Share” and (ii) if the outstanding principal amount of all Loans has been repaid in full, the Percentage of each Lender shall be such Lender’s Percentage as in effect immediately prior to such repayment.

“Person” means an individual, partnership, corporation (including a business trust), joint stock company, trust, unincorporated association, joint venture, limited liability company or other entity, or a government or any political subdivision or agency thereof.

“Plan” means any “employee benefit plan” (as such term is defined in Section 3(3) of ERISA) established by the Borrower or, with respect to any such plan that is subject to Section 412 of the Internal Revenue Code or Title IV of ERISA, any ERISA Affiliate.

“Prohibited Person” means any Person (a) listed in the Annex to the Executive Order or identified pursuant to Section 1 of the Executive Order; (b) that is owned or controlled by, or acting for or on behalf of, any Person listed in the Annex to the Executive Order or identified pursuant to the provisions of Section 1 of the Executive Order; (c) with whom a Lender is prohibited from dealing or otherwise engaging in any transaction by any terrorism or anti-laundering law, including the Executive Order; (d) who commits, threatens, conspires to commit, or support “terrorism” as defined in the Executive Order; (e) who is named as a “Specially designated national or blocked person” on the most current list published by the OFAC at its official website, at http://www.treas.gov/offices/enforcement/ofac/sdn/t11sdn.pdf or any replacement website or other

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replacement official publication of such list; or (f) who is owned or controlled by a Person listed above in clause (c) or (e).

“Prime Rate” means the rate of interest per annum announced from time to time by Toronto Dominion (Texas) LLC as its prime rate in effect at its principal office in New York, New York; each change in the Prime Rate shall be effective from and including the date such change is announced as being effective.

“Public Debt Rating” means, as of any date, the rating that has been most recently announced by either S&P or Moody’s, as the case may be, applicable to any outstanding class of non-credit enhanced long-term senior unsecured debt issued by the Borrower, including any bank facility rating (or, if any such rating agency shall have issued more than one such rating, the lowest such rating issued by such rating agency). For purposes of the foregoing, (a) if only one of S&P and Moody’s shall have in effect a Public Debt Rating, the Applicable Rate shall be determined by reference to the available rating; (b) except as set forth in the proviso at the end of this definition, if neither S&P nor Moody’s shall have in effect a Public Debt Rating, the Applicable Rate will be set in accordance with Level 5 under the definition of “Applicable Rate”; (c) if the ratings established by S&P and Moody’s shall fall within different levels, the Applicable Rate shall be based upon the higher rating unless such ratings differ by two or more levels, in which case the applicable level will be deemed to be one level below the higher of such levels; and (d) if any rating established by S&P or Moody’s shall be changed (other than as a result of a change in the basis on which ratings are established), such change shall be effective as of the date on which such change is first announced publicly by the rating agency making such change; provided that if the Public Debt Rating system of S&P or Moody’s shall change, or if either such rating agency shall cease to be in the business of rating corporate debt obligations, the Borrower and the Lenders shall negotiate in good faith to amend the definition of “Applicable Rate” to reflect such changed rating system or the unavailability of ratings from such rating agency and, pending the effectiveness of any such amendment, the Applicable Rate will be set in accordance with the level most recently in effect under the definition of “Applicable Rate” prior to such change or cessation.

“PVNGS” means the Palo Verde Nuclear Generating Station.

“PWCC” means Pinnacle West Capital Corporation, an Arizona corporation.

“Ratable Share” of any amount means, with respect to any Lender at any time, the product of such amount times such Lender’s Percentage.

“Register” has the meaning specified in Section 8.07(c).

“Related Parties” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees and advisors of such Person and of such Person’s Affiliates.

“Reportable Event” means any of the events set forth in Section 4043(c) of ERISA, other than events for which the 30-day notice period has been waived under the final regulations issued under Section 4043, as in effect as of the date of this Agreement (the “Section 4043 Regulations”).

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Any changes made to the Section 4043 Regulations that become effective after the Effective Date shall have no impact on the definition of Reportable Event as used herein unless otherwise amended by the Borrower and the Required Lenders.

“Required Lenders” means, as of any date of determination, but subject to Section 2.16, Lenders holding in the aggregate more than 50% of the aggregate outstanding principal amount of all Loans (or, if all Loans have been repaid in full, more than 50% of the aggregate amount of all outstanding Obligations); provided that at all times when two or more Lenders (excluding Affected Lenders) are party to this Agreement, the term “Required Lenders” shall in no event mean less than two Lenders

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc.

“Sanctions” means economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by OFAC and any similar economic or financial sanctions or trade embargoes of the type described in Sections 4.01(n) through (q) and imposed, administered or enforced from time to time by the U.S. government, including the U.S. Department of State.

“SEC Reports” means the Borrower’s (i) Form 10-K Report for the fiscal year ended December 31, 2014, (ii) Form 10-Q Reports for the quarter ended March 31, 2015 and (iii) Form 8-K Reports filed on January 9, 2015 (as amended January 15, 2015), April 2, 2015 and May 19, 2015 in each case, as filed with the Securities and Exchange Commission.

“Subsidiary” of any Person means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (a) the issued and outstanding Voting Stock, (b) the interest in the capital or profits of such limited liability company, partnership or joint venture or (c) the beneficial interest in such trust or estate, is at the time directly or indirectly owned or controlled by such Person, by such Person and one or more of its other Subsidiaries or by one or more of such Person’s other Subsidiaries; provided that in no event will Subsidiaries include the VIE Lessor Trusts.

“Subsequent Order” means any decision, order or ruling of the Arizona Corporation Commission issued after the Effective Date relating to the incurrence or maintenance of Indebtedness by the Borrower and that amends, supersedes or otherwise modifies the 2013 Order or any successor decision, order or ruling.

“Syndication Agent” means Citibank, N.A., in its capacity as syndication agent for the Lenders.

“Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

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“Type”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Eurodollar Rate or the Base Rate.

“VIE Lessor Trusts” means the three (3) separate variable-interest entity lessor trusts that purchased from, and leased back to, the Borrower certain interests in the PVNGS Unit 2 and related common facilities, as described in Note 6 of Notes to Condensed Consolidated Financial Statements in the Borrower’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015.

“Voting Stock” means capital stock issued by a corporation, or equivalent interests in any other Person, the holders of which are ordinarily, in the absence of contingencies, entitled to vote for the election of directors (or persons performing similar functions) of such Person, even if the right so to vote has been suspended by the happening of such a contingency.

Section 1.02Other Interpretive Provisions. With reference to this Agreement and each other Loan Document, unless otherwise specified herein or in such other Loan Document:

(a)The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation.” The word “will” shall be construed to have the same meaning and effect as the word “shall.” Unless the context requires otherwise, (i) any definition of or reference to any agreement, instrument or other document shall be construed as referring to such agreement, instrument or other document as from time to time amended, restated, supplemented or otherwise modified (subject to any restrictions on such amendments, restatements, supplements or modifications set forth herein or in any other Loan Document), (ii) any reference herein to any Person shall be construed to include such Person’s permitted successors and permitted assigns, (iii) the words “herein,” “hereof” and “hereunder,” and words of similar import when used in any Loan Document, shall be construed to refer to such Loan Document in its entirety and not to any particular provision thereof, (iv) all references in a Loan Document to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, the Loan Document in which such references appear, (v) any reference to any law shall include all statutory and regulatory provisions consolidating, amending, replacing or interpreting such law and any reference to any law or regulation shall, unless otherwise specified, refer to such law or regulation as amended, modified or supplemented from time to time, and (vi) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

(b)In the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including;” the words “to” and “until” each mean “to but excluding;” and the word “through” means “to and including.”

(c)Section headings herein and in the other Loan Documents are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other Loan Document.

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Section 1.03Accounting Terms. Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all accounting determinations hereunder shall be made, and all financial statements required to be delivered hereunder shall be prepared, in accordance with generally accepted accounting principles as in effect from time to time, applied on a basis consistent (except for changes concurred in by the Borrower’s independent public accountants) with the most recent audited Consolidated financial statements of the Borrower delivered to the Agent (“GAAP”). If at any time any change in GAAP or in the interpretation thereof would affect the computation of any financial ratio or requirement set forth in any Loan Document, and either the Borrower or the Required Lenders shall so request, the Agent, the Lenders and the Borrower shall negotiate in good faith to amend such ratio or requirement to preserve the original intent thereof in light of such change in GAAP or in the interpretation thereof (subject to the approval of the Required Lenders); providedthat, unless and until so amended, such ratio or requirement shall continue to be computed in accordance with GAAP prior to such change therein.

Section 1.04Rounding. Any financial ratios required to be maintained by the Borrower pursuant to this Agreement shall be calculated by dividing the appropriate component by the other component, carrying the result to one place more than the number of places by which such ratio is expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).

Section 1.05Times of Day. Unless otherwise specified, all references herein to times of day shall be references to Eastern time (daylight or standard, as applicable).

ARTICLE IIAMOUNTS AND TERMS OF THE LOANS

Section 2.01The Loans.

Subject to the terms and conditions hereof (including, without limitation, Section 3.01), each Lender, by its acceptance hereof, severally agrees to make a one-time loan (individually, a “Loan” and, collectively, the “Loans”) to the Borrower on the Effective Date in Dollars in an aggregate principal amount equal to such Lender’s Commitment.  As provided in Section 2.05, the Borrower may elect that each Borrowing of Loans be either Base Rate Loans or Eurodollar Rate Loans. Amounts borrowed by the Borrower hereunder and prepaid or otherwise repaid may not be reborrowed. Unless an earlier maturity is provided for hereunder, all Loans shall mature and be due and payable on the Maturity Date. The Commitments shall immediately and automatically terminate upon the earlier of (i) 5:00 p.m. on the Effective Date and (ii) the making of the Loans pursuant to this Section 2.01.

Section 2.02Making the Loans.

(a)The Initial Borrowing shall be made on notice, given not later than (x) 12:00 noon on the third Business Day prior to the Effective Date in the case of an Initial Borrowing consisting of Eurodollar Rate Loans or (y) 12:00 noon on the Business Day prior to the Effective Date in the case of an Initial Borrowing consisting of Base Rate Loans, by the Borrower to the Agent, which

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shall give to each Lender prompt notice thereof by facsimile. Such notice of the Initial Borrowing (the “Notice of Initial Borrowing”) shall be in writing or by facsimile in substantially the form of Exhibit B hereto, specifying therein the requested (i) date of the Initial Borrowing (which shall be the Effective Date and a Business Day), (ii) Type of Loans comprising the Initial Borrowing, (iii) aggregate amount of the Initial Borrowing, and (iv) in the case of an Initial Borrowing consisting of Eurodollar Rate Loans, initial Interest Period for each such Loan. Each Lender shall, before 2:00 p.m. on the date of the Initial Borrowing, make available for the account of its Applicable Lending Office to the Agent at the Agent’s Account, in same day funds, such Lender’s Ratable Share of the Initial Borrowing. After the Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Agent will make such funds available to the Borrower at the Agent’s address referred to in Section 8.02 or as requested by the Borrower in the Notice of Initial Borrowing.

(b)Anything in subsection (a) above to the contrary notwithstanding, (i) the Borrower may not select Eurodollar Rate Loans for any Borrowing if the aggregate amount of such Borrowing is less than $5,000,000 (or an integral multiple of $1,000,000 in excess thereof) or if the obligation of the Lenders to make Eurodollar Rate Loans shall then be suspended pursuant to Section 2.06 or 2.10, and (ii) at no time shall there be more than three (3) different Interest Periods outstanding for Eurodollar Rate Loans.

(c)The Notice of Initial Borrowing shall be irrevocable and binding on the Borrower. If the Notice of Initial Borrowing specifies that the Initial Borrowing is to be comprised of Eurodollar Rate Loans, the Borrower shall indemnify each Lender against any loss, cost or expense reasonably incurred by such Lender as a result of any failure (i) to fulfill on or before the date specified in the Notice of Initial Borrowing the applicable conditions set forth in Article III or (ii) to otherwise borrow the Eurodollar Rate Loans requested by the Borrower in the Notice of Initial Borrowing on such date (and shall set forth such indemnification obligation in the Notice of Initial Borrowing), including, without limitation, any loss (excluding loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to fund the Loan to be made by such Lender as part of the Initial Borrowing when such Loan, as a result of any such failure, is not made on such date.

(d)Unless the Agent shall have received notice from a Lender prior to the time of the Initial Borrowing that such Lender will not make available to the Agent such Lender’s Ratable Share of the Initial Borrowing, the Agent may assume that such Lender has made such portion available to the Agent on the date of the Initial Borrowing in accordance with subsection (a) of this Section 2.02 and the Agent may, in reliance upon such assumption, make available to the Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such Ratable Share available to the Agent, such Lender and the Borrower severally agree to repay to the Agent within one Business Day after demand for such Lender and within three Business Days after demand for the Borrower such corresponding amount together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Agent, at (i) in the case of the Borrower, the interest rate applicable at the time to Loans comprising the Initial Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If the Borrower and such Lender shall pay such interest to the Agent for the same or an overlapping period,

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the Agent shall promptly remit to the Borrower the amount of such interest paid by the Borrower for such period. If such Lender shall repay to the Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Loan as part of the Initial Borrowing for purposes of this Agreement.

(e)The failure of any Lender to make the Loan to be made by it as part of the Initial Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Loan on the date of the Initial Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Loan to be made by such other Lender on the date of the Initial Borrowing.

Section 2.03Agent’s Fees. The Borrower shall pay to the Agent for its own account such fees as are agreed between the Borrower and the Agent pursuant to the Fee Letter between the Borrower and the Agent.

Section 2.04Repayment of Loans. The Borrower hereby unconditionally agrees to pay to the Agent on the Maturity Date, for the account of the Lenders and the Agent, the then unpaid principal amount of the Loans, together with all accrued and unpaid interest thereon, and all other outstanding Obligations.

Section 2.05Interest on Loans.

(a)Scheduled Interest. The Borrower shall pay interest on the unpaid principal amount of each Loan owing to each Lender from the date of such Loan until such principal amount shall be paid in full, at the following rates per annum:

(i)Base Rate Loans. During such periods as such Loan is a Base Rate Loan, a rate per annum equal at all times to the sum of (x) the Base Rate in effect from time to time plus (y) the Applicable Rate for Base Rate Loans in effect from time to time, payable in arrears quarterly on the last day of each March, June, September and December during such periods and on the date such Base Rate Loan shall be Converted or paid in full.

(ii)Eurodollar Rate Loans. During such periods as such Loan is a Eurodollar Rate Loan, a rate per annum equal at all times during each Interest Period for such Loan to the sum of (x) the Eurodollar Rate for such Interest Period for such Loan plus (y) the Applicable Rate for Eurodollar Rate Loans in effect from time to time, payable in arrears on the last day of such Interest Period and, if such Interest Period has a duration of more than three months, on each day that occurs during such Interest Period every three months from the first day of such Interest Period and on the date such Eurodollar Rate Loan shall be Converted or paid in full.

(b)Default Interest. Upon the occurrence and during the continuance of an Event of Default under Section 6.01(a), the Agent may, and upon the request of the Required Lenders shall, require the Borrower to pay interest (“Default Interest”) on (i) the unpaid principal amount of each Loan owing to each Lender, payable in arrears on the dates referred to in clause (a)(i) or (a)(ii) above, at a rate per annum equal at all times to 2% per annum above the rate per annum required to be paid on such Loan pursuant to clause (a)(i) or (a)(ii) above and (ii) to the fullest extent permitted

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by Law, the amount of any interest, fee or other amount payable hereunder that is not paid when due, from the date such amount shall be due until such amount shall be paid in full, payable in arrears on the date such amount shall be paid in full and on demand, at a rate per annum equal at all times to 2% per annum above the rate per annum required to be paid on Base Rate Loans pursuant to clause (a)(i) above, provided, however, that following acceleration of the Loans pursuant to Section 6.01, Default Interest shall accrue and be payable hereunder whether or not previously required by the Agent.

(c)Interest Rate Limitation. Nothing contained in this Agreement or in any other Loan Document shall be deemed to establish or require the payment of interest to any Lender at a rate in excess of the maximum rate permitted by applicable Law. If the amount of interest payable for the account of any Lender on any interest payment date would exceed the maximum amount permitted by applicable Law to be charged by such Lender, the amount of interest payable for its account on such interest payment date shall be automatically reduced to such maximum permissible amount. In the event of any such reduction affecting any Lender, if from time to time thereafter the amount of interest payable for the account of such Lender on any interest payment date would be less than the maximum amount permitted by applicable Law to be charged by such Lender, then the amount of interest payable for its account on such subsequent interest payment date shall be automatically increased to such maximum permissible amount, provided that at no time shall the aggregate amount by which interest paid for the account of any Lender has been increased pursuant to this sentence exceed the aggregate amount by which interest paid for its account has theretofore been reduced pursuant to the previous sentence.

Section 2.06Interest Rate Determination.

(a)The Agent shall give prompt notice to the Borrower and the Lenders of the applicable interest rate determined by the Agent for purposes of Section 2.05(a).

(b)If the Required Lenders determine that for any reason in connection with any request for a Eurodollar Rate Loan or a Conversion to or continuation thereof that (a) Dollar deposits are not being offered to banks in the London interbank eurodollar market for the applicable amount and Interest Period of such Eurodollar Rate Loan, (b) adequate and reasonable means do not exist for determining the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Rate Loan, or (c) the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Rate Loan does not adequately and fairly reflect the cost to such Lenders of funding such Loan, the Agent will promptly so notify the Borrower and each Lender, whereupon each Eurodollar Rate Loan will automatically on the last day of the then existing Interest Period therefor Convert into a Base Rate Loan. Thereafter, the obligation of the Lenders to make or maintain Eurodollar Rate Loans shall be suspended until the Agent (upon the instruction of the Required Lenders) revokes such notice. Upon receipt of such notice, the Borrower may revoke any pending request for a Borrowing of, Conversion to or continuation of Eurodollar Rate Loans or, failing that, will be deemed to have Converted such request into a request for a Base Rate Loan in the amount specified therein.

(c)If the Borrower shall fail to select the duration of any Interest Period for any Eurodollar Rate Loans in accordance with the provisions contained in the definition of “Interest

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Period” in Section 1.01, the Agent will forthwith so notify the Borrower and the Lenders and such Loans will automatically, on the last day of the then existing Interest Period therefor, Convert into Base Rate Loans.

(d)On the date on which the aggregate unpaid principal amount of Eurodollar Rate Loans comprising any Borrowing shall be reduced, by payment or prepayment or otherwise, to less than $5,000,000, such Loans shall automatically Convert into Base Rate Loans.

(e)Upon the occurrence and during the continuance of any Event of Default,

(i)with respect to Eurodollar Rate Loans, each such Loan will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Loan (or if such Loan is then a Base Rate Loan, will continue as a Base Rate Loan); and

(ii)the obligation of the Lenders to Convert Loans into Eurodollar Rate Loans shall be suspended until the Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist.

Section 2.07Optional Conversion of Loans. The Borrower may on any Business Day, upon notice given to the Agent (in the form of an Interest Election Request duly completed and executed by the Borrower) not later than 12:00 noon on the third Business Day prior to the date of the proposed Conversion and subject to the provisions of Sections 2.06 and 2.10, Convert all or any portion of the Loans of one Type comprising the same Borrowing into Loans of the other Type; provided, however, that (a) any Conversion of Eurodollar Rate Loans into Base Rate Loans shall be made only on the last day of an Interest Period for such Eurodollar Rate Loans, (b) any Conversion of Base Rate Loans into Eurodollar Rate Loans shall be in an amount not less than the minimum amount specified in Section 2.02(b) and (c) no Conversion of any Loans shall result in more separate Borrowings than permitted under Section 2.02(b). Each such notice of a Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Loans to be Converted and (iii) if such Conversion is into Eurodollar Rate Loans, the duration of the initial Interest Period for each such Loan. Each Interest Election Request shall be irrevocable and binding on the Borrower.

Section 2.08Prepayments of Loans.

(a)Optional. At any time and from time to time, the Borrower shall have the right to prepay the Loans, in whole or in part, without premium or penalty (except as provided in clause (z) below), upon notice at least two Business Days’ prior to the date of such prepayment, in the case of Eurodollar Rate Loans, and not later than 11:00 a.m. on the date of such prepayment, in the case of Base Rate Loans, to the Agent, which notice shall be in writing or by facsimile in substantially the form of Exhibit E hereto and shall specify the proposed date of such prepayment and the aggregate principal amount and Type of the Loans to be prepaid (and, in the case of Eurodollar Rate Loans, the Interest Period of the Borrowing pursuant to which made); provided, however, that (x) each partial prepayment shall be in an aggregate principal amount of $5,000,000 or an integral multiple of $1,000,000 in excess thereof, (y) accrued interest to the date of prepayment on the principal amount prepaid shall be payable by the Borrower on the date of such prepayment, and (z) in the event of any such prepayment of a Eurodollar Rate Loan, the Borrower shall be obligated to

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reimburse the Lenders in respect thereof pursuant to Section 8.04(e). Each prepayment of Loans shall be applied ratably to the outstanding principal amount of each Lender’s Loan in accordance with such Lender’s Ratable Share.

(b)Mandatory. The Borrower shall prepay the aggregate principal amount of the Loans, together with accrued interest to the date of prepayment on the principal amount prepaid, without requirement of demand therefor, or shall pay or prepay any other Indebtedness then outstanding at any time, when and to the extent required to comply with applicable Laws of any Governmental Authority, including the 2013 Order and/or any Subsequent Order, or applicable resolutions of the Board of Directors of the Borrower.

Section 2.09Increased Costs.

(a)Increased Costs Generally. If any Change in Law shall:

(i)impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender (except any reserve requirement contemplated by Section 2.09(e));

(ii)impose on any Lender or the London interbank market any other condition, cost or expense affecting this Agreement or Eurodollar Rate Loans made by such Lender; or

(iii)subject the Agent or any Lender to any Taxes (other than (A) Indemnified Taxes, (B) Excluded Taxes and (C) Other Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

and the result of any of the foregoing shall be to increase the cost to the Agent or such Lender of making or maintaining any Loan (or of maintaining its obligation to make any such Loan), or to reduce the amount of any sum received or receivable by the Agent or such Lender hereunder (whether of principal, interest or any other amount) then, upon request of the Agent or such Lender, the Borrower will pay to the Agent or such Lender such additional amount or amounts as will compensate the Agent or such Lender for such additional costs incurred or reduction suffered.

(b)Capital Requirements. If any Lender determines that any Change in Law affecting such Lender or any Applicable Lending Office of such Lender or such Lender’s holding company, if any, regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Loans made by such Lender, to a level below that which such Lender or such Lender’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy and liquidity), then from time to time the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.

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(c)Certificates for Reimbursement. A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in subsection (a) or (b) of this Section and delivered to the Borrower shall be conclusive and binding upon all parties absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 30 days after receipt thereof.

(d)Delay in Requests. Failure or delay on the part of any Lender to demand compensation pursuant to the foregoing provisions of this Section shall not constitute a waiver of such Lender’s right to demand such compensation, provided that the Borrower shall not be required to compensate a Lender pursuant to the foregoing provisions of this Section for any increased costs incurred or reductions suffered more than three months prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s intention to claim compensation therefor (except that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the three-month period referred to above shall be extended to include the period of retroactive effect thereof).

(e)Reserves on Eurodollar Rate Loans. The Borrower shall pay to each Lender, as long as such Lender shall be required to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency funds or deposits (currently known as “Eurocurrency liabilities”), additional interest on the unpaid principal amount of each Eurodollar Rate Loan equal to the actual costs of such reserves allocated to such Loan by such Lender (as determined by such Lender in good faith, which determination shall be conclusive absent manifest error), which shall be due and payable on each date on which interest is payable on such Loan, provided the Borrower shall have received at least 30 days’ prior notice (with a copy to the Agent) of such additional interest from such Lender. If a Lender fails to give notice 30 days prior to the relevant interest payment date, such additional interest shall be due and payable 30 days from receipt of such notice.

Section 2.10Illegality. If any Lender shall have determined in good faith that the introduction of or any change in any applicable Law or in the interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof, or compliance with any guideline or request from any such Governmental Authority (whether or not having the force of law), makes it unlawful for any Lender or its Applicable Lending Office to make, maintain or fund Eurodollar Rate Loans, or to determine or charge interest rates based upon the Eurodollar Rate, or any Governmental Authority has imposed material restrictions on the authority of such Lender to purchase or sell, or to take deposits of, Dollars in the London interbank market, then, on notice thereof by such Lender to the Borrower through the Agent, any obligation of such Lender to make or continue Eurodollar Rate Loans or to Convert Base Rate Loans to Eurodollar Rate Loans shall be suspended until such Lender notifies the Agent and the Borrower that the circumstances giving rise to such determination no longer exist. Upon receipt of such notice, the Borrower shall, upon demand from such Lender (with a copy to the Agent), prepay or, if applicable, Convert all Eurodollar Rate Loans of such Lender to Base Rate Loans, either on the last day of the Interest Period therefor, if such Lender may lawfully continue to maintain such Eurodollar Rate Loans to such day, or immediately, if such Lender may not lawfully continue to maintain such Eurodollar Rate Loans. Upon any such prepayment or Conversion, the Borrower shall also pay accrued interest on the amount so prepaid or Converted.

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Section 2.11Payments and Computations.

(a)All payments to be made by the Borrower shall be made without condition or deduction for any counterclaim, defense, recoupment or setoff. The Borrower shall make each payment hereunder not later than 1:00 p.m. on the day when due in Dollars to the Agent at the Agent’s Account in same day funds. The Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal, interest or fees ratably (other than amounts payable pursuant to Section 2.09, 2.10, 2.12, 2.17 or 8.04(e)) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other amount payable to any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Assumption and recording of the information contained therein in the Register pursuant to Section 8.07(c), from and after the effective date specified in such Assignment and Assumption, the Agent shall make all payments hereunder and under the Notes in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Assumption shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.

(b)All computations of interest based on the Base Rate (when the Base Rate is based on the Prime Rate) shall be made by the Agent on the basis of a year of 365 or 366 days, as the case may be, and all other computations of interest and fees hereunder (including computations of interest based on the Eurodollar Rate and the Federal Funds Rate) shall be made by the Agent on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest or fees are payable. Each determination by the Agent of an interest rate hereunder shall be conclusive and binding for all purposes, absent manifest error.

(c)Whenever any payment hereunder or under the Notes shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or fees, as the case may be; provided, however, that, if such extension would cause payment of interest on or principal of Eurodollar Rate Loans to be made in the next following calendar month, such payment shall be made on the next preceding Business Day.

(d)Unless the Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Lenders hereunder that the Borrower will not make such payment in full, the Agent may assume that the Borrower has made such payment in full to the Agent on such date and the Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due to such Lender. If and to the extent the Borrower shall not have so made such payment in full to the Agent, each Lender shall repay to the Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Agent, at the Federal Funds Rate.

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Section 2.12Taxes.

(a)Payments Free of Taxes; Obligation to Withhold; Payments on Account of Taxes.

(i)Any and all payments by or on account of any obligation of the Borrower hereunder or under any other Loan Document shall to the extent permitted by applicable Laws be made free and clear of and without reduction or withholding for any Taxes. If, however, applicable Laws require the Borrower or the Agent to withhold or deduct any Tax, such Tax shall be withheld or deducted in accordance with such Laws as determined by the Borrower or the Agent, as the case may be, upon the basis of the information and documentation to be delivered pursuant to subsection (e) below.

(ii)If the Borrower or the Agent shall be required by the Internal Revenue Code to withhold ordeduct any Taxes, including both United States of America Federal backup withholding and withholding Taxes, from any payment, then (A) the Agent shall withhold or make such deductions as are determined by the Agent to be required based upon the information and documentation it has received pursuant to subsection (e) below, (B) the Agent shall timely pay the full amount withheld or deducted to the relevant Governmental Authority in accordance with the Internal Revenue Code, and (C) to the extent that the withholding or deduction is made on account of Indemnified Taxes or Other Taxes, the sum payable by the Borrower shall be increased as necessary so that after any required withholding or the making of all required deductions (including deductions applicable to additional sums payable under this Section) the Agent or each Lender, as the case may be, receives an amount equal to the sum it would have received had no such withholding or deduction been made.

(b)Payment of Other Taxes by the Borrower. Without limiting the provisions of subsection (a) above, the Borrower shall timely pay any Other Taxes to the relevant Governmental Authority in accordance with applicable Laws.

(c)Tax Indemnifications.

(i)Without limiting the provisions of subsection (a) or (b) above, the Borrower shall, and does hereby, indemnify the Agent and each Lender, and shall make payment in respect thereof within 30 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) withheld or deducted by the Borrower or the Agent or paid by the Agent or such Lender, as the case may be, and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. The Borrower shall also, and does hereby, indemnify the Agent, and shall make payment in respect thereof within 10 days after demand therefor, for any amount which a Lender for any reason fails to pay indefeasibly to the Agent as required by clause (ii) of this subsection. A certificate as to the amount of any such payment or liability delivered to the Borrower by a Lender (with a copy to the Agent), or

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by the Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(ii)Each Lender shall severally indemnify the Agent, within 30 days after demand therefor, for (i) any Indemnified Taxes and Other Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Agent for such Indemnified Taxes and Other Taxes and without limiting the obligation of the Borrower to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 8.07(d) relating to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Agent to set off and apply any and all amounts at any time owing to such Lender under any Loan Document or otherwise payable by the Agent to the Lender from any other source against any amount due to the Agent under this clause (ii).

(d)Evidence of Payments. Upon request by the Borrower or the Agent, as the case may be, after any payment of Taxes by the Borrower or by the Agent to a Governmental Authority as provided in this Section 2.12, the Borrower shall deliver to the Agent or the Agent shall deliver to the Borrower, as the case may be, the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by Laws to report such payment or other evidence of such payment reasonably satisfactory to the Borrower or the Agent, as the case may be.

(e)Status of Lenders; Tax Documentation.

(i)Each Lender shall deliver to the Borrower and to the Agent, at the time or times prescribed by applicable Laws or when reasonably requested by the Borrower or the Agent, such properly completed and executed documentation prescribed by applicable Laws or by the taxing authorities of any jurisdiction and such other reasonably requested information as will permit the Borrower or the Agent, as the case may be, to determine (A) whether or not payments made hereunder or under any other Loan Document are subject to Taxes, (B) if applicable, the required rate of withholding or deduction, and (C) such Lender’s entitlement to any available exemption from, or reduction of, applicable Taxes in respect of all payments to be made to such Lender by the Borrower pursuant to this Agreement or otherwise to establish such Lender’s status for withholding tax purposes in the applicable jurisdiction.

(ii)Without limiting the generality of the foregoing, if the Borrower is resident for tax purposes in the United States of America,

(A)any Lender that is a “United States person” within the meaning of Section 7701(a)(30) of the Internal Revenue Code shall deliver to the Borrower and

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the Agent executed originals of Internal Revenue Service Form W-9 or such other documentation or information prescribed by applicable Laws or reasonably requested by the Borrower or the Agent as will enable the Borrower or the Agent, as the case may be, to determine whether or not such Lender is subject to backup withholding or information reporting requirements; and

(B)each Foreign Lender that is entitled under the Internal Revenue Code or any applicable treaty to an exemption from or reduction of withholding tax with respect to payments hereunder or under any other Loan Document shall deliver to the Borrower and the Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the request of the Borrower or the Agent, but only if such Foreign Lender is legally entitled to do so), whichever of the following is applicable:

(1)executed originals of Internal Revenue Service Form W-8BEN or Form W-8BEN-E claiming eligibility for benefits of an income tax treaty to which the United States of America is a party,

(2)executed originals of Internal Revenue Service Form W-8ECI,

(3)executed originals of Internal Revenue Service Form W-8IMY and all required supporting documentation,

(4)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under section 881(c) of the Internal Revenue Code, (x) a certificate to the effect that such Foreign Lender is not (A) a “bank” within the meaning of section 881(c)(3)(A) of the Internal Revenue Code, (B) a “10 percent shareholder” of the Borrower within the meaning of section 881(c)(3)(B) of the Internal Revenue Code, or (C) a “controlled foreign corporation” described in section 881(c)(3)(C) of the Internal Revenue Code and (y) executed originals of Internal Revenue Service Form W-8BEN or Form W-8BEN-E, or

(5)executed originals of any other form prescribed by applicable Laws as a basis for claiming exemption from or a reduction in United States of America Federal withholding tax together with such supplementary documentation as may be prescribed by applicable Laws to permit the Borrower or the Agent to determine the withholding or deduction required to be made.

(iii)Each Lender shall promptly (A) notify the Borrower and the Agent of any change in circumstances which would modify or render invalid any claimed exemption or reduction, and (B) take such steps as shall not be materially disadvantageous to it, in the reasonable judgment of such Lender, and as may be reasonably necessary (including the re-

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designation of its Applicable Lending Office) to avoid any requirement of applicable Laws of any jurisdiction that the Borrower or the Agent make any withholding or deduction for taxes from amounts payable to such Lender.

(iv)If a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Internal Revenue Code, as applicable), such Lender shall deliver to each of the Borrower and the Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Internal Revenue Code) and such additional documentation reasonably requested by the Borrower or the Agent as may be necessary for the Borrower and the Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (iv), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

(f)Treatment of Certain Refunds. Unless required by applicable Laws, at no time shall the Agent have any obligation to file for or otherwise pursue on behalf of a Lender, or have any obligation to pay to any Lender, any refund of Taxes withheld or deducted from funds paid for the account of such Lender. If the Agent or any Lender determines, in its sole discretion, that it has received a refund of any Taxes or Other Taxes as to which it has been indemnified by the Borrower or with respect to which the Borrower has paid additional amounts pursuant to this Section, it shall pay to the Borrower an amount equal to such refund (but only to the extent of indemnity payments made, or additional amounts paid, by the Borrower under this Section with respect to the Taxes or Other Taxes giving rise to such refund), net of all reasonable out-of-pocket expenses incurred by the Agent or such Lender, as the case may be, and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund), provided that the Borrower, upon the request of the Agent or such Lender, agrees to repay the amount paid over to the Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Agent or such Lender in the event the Agent or such Lender is required to repay such refund to such Governmental Authority. This subsection shall not be construed to require the Agent or any Lender to make available its tax returns (or any other information relating to its taxes that it deems confidential) to the Borrower or any other Person.

(g)Payments. Failure or delay on the part of the Agent or any Lender to demand compensation pursuant to the foregoing provisions of this Section 2.12 shall not constitute a waiver of the Agent’s or such Lender’s right to demand such compensation, provided that the Borrower shall not be required to compensate the Agent or a Lender pursuant to the foregoing provisions of this Section 2.12 for any Indemnified Taxes or Other Taxes imposed or asserted by the relevant Governmental Authority more than three months prior to the date that the Agent or such Lender, as the case may be, claims compensation with respect thereto (except that, if a Change in Law giving rise to such Indemnified Taxes or Other Taxes is retroactive, then the three-month period referred to above shall be extended to include the period of retroactive effect thereof).

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(h)The Agent and each Lender agrees to cooperate with any reasonable request made by the Borrower in respect of a claim of a refund in respect of Indemnified Taxes as to which it has been indemnified by the Borrower or with respect to which the Borrower has paid additional amounts pursuant to this Section 2.12 if (i) the Borrower has agreed in writing to pay all of the Agent’s or such Lender’s reasonable out-of-pocket costs and expenses relating to such claim, (ii) the Agent or such Lender determines, in its good faith judgment, that it would not be disadvantaged, unduly burdened or prejudiced as a result of such claim and (iii) the Borrower furnishes, upon request of the Agent or such Lender, an opinion of tax counsel (such opinion, which can be reasoned, and such counsel to be reasonably acceptable to such Lender or the Agent) that the Borrower is likely to receive a refund or credit.

Section 2.13Sharing of Payments, Etc. If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Loans owing to it (other than pursuant to Section 2.09, 2.10, 2.12, 2.17 or 8.04(e) or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans to any assignee or participant, other than to the Borrower or any Subsidiary thereof if permitted hereby (as to which the provisions of this Section 2.13 shall apply) in excess of its Ratable Share of payments on account of the Loans obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders (for cash at face value) such participations in the Loans owing to them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender’s ratable share (according to the proportion of (i) the amount of such Lender’s required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.13 may, to the fullest extent permitted by Law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation.

Section 2.14Evidence of Debt.

(a)Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan owing to such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder in respect of Loans. The Borrower agrees that upon notice by any Lender to the Borrower (with a copy of such notice to the Agent) to the effect that a Note is required or appropriate in order for such Lender to evidence (whether for purposes of pledge, enforcement or otherwise) the Loans owing to, or to be made by, such Lender, the Borrower shall promptly execute and deliver to such Lender a Note payable to the order of such Lender in a principal amount equal to the Loans owing to, or to be made by, such Lender.

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(b)The Register maintained by the Agent pursuant to Section 8.07(c) shall include a control account, and a subsidiary account for each Lender, in which accounts (taken together) shall be recorded (i) the date and amount of each Borrowing made hereunder, the Type of Loans comprising such Borrowing and, if appropriate, the Interest Period applicable thereto, (ii) the terms of each Assignment and Assumption delivered to and accepted by it, (iii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iv) the amount of any sum received by the Agent from the Borrower hereunder and each Lender’s share thereof.

(c)Entries made in good faith by the Agent in the Register pursuant to subsection (b) above, and by each Lender in its account or accounts pursuant to subsection (a) above, shall be primafacie evidence of the amount of principal and interest due and payable or to become due and payable from the Borrower to, in the case of the Register, each Lender and, in the case of such account or accounts, such Lender, under this Agreement, absent manifest error; provided, however, that the failure of the Agent or such Lender to make an entry, or any finding that an entry is incorrect, in the Register or such account or accounts shall not limit or otherwise affect the obligations of the Borrower under this Agreement.

Section 2.15Use of Proceeds. The proceeds of the Loans shall be available (and the Borrower agrees that it shall use such proceeds) solely to repay and refinance existing Indebtedness of the Borrower from time to time and in accordance with Section 4.01(p), subject to such restrictions that are imposed in the 2013 Order and/or any Subsequent Order.

Section 2.16Affected Lenders. Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes an Affected Lender, then the following provisions shall apply for so long as such Lender is an Affected Lender:

(a)the outstanding principal amount of the Loans of such Affected Lender shall not be included in determining whether the Required Lenders have taken or may take any action hereunder (including any consent to any amendment or waiver pursuant to Section 8.01), other than any waiver, amendment or modification requiring the consent of all Lenders or of each Lender affected;

(b)to the extent the Agent receives any payments or other amounts for the account of an Affected Lender under this Agreement, such Affected Lender shall be deemed to have requested that the Agent use such payment or other amount to fulfill such Affected Lender’s previously unsatisfied obligations to fund a Loan under Section 2.01 or any other unfunded payment obligation of such Affected Lender under this Agreement; and

(c)for the avoidance of doubt, the Borrower, the Agent and each other Lender shall retain and reserve its other rights and remedies respecting each Affected Lender.

In the event that the Agent and the Borrower each agrees that an Affected Lender has adequately remedied all matters that caused such Lender to be an Affected Lender, then this Section 2.16 will no longer apply to such Lender.

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Section 2.17Replacement of Lenders. If any Lender requests compensation under Section 2.09, or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.12, or if any Lender is an Affected Lender, then the Borrower may, at its sole expense and effort, upon notice to such Lender and the Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in, and consents required by, Section 8.07), all of its interests, rights and obligations under this Agreement and the related Loan Documents to one or more assignees that shall assume such obligations (which any such assignee may be another Lender (other than an Affected Lender), if such Lender accepts such assignment), provided that:

(a)the Borrower shall have paid to the Agent the assignment fee specified in Section 8.07(b);

(b)such Lender shall have received payment of an amount equal to the outstanding principal amount of its Loans, accrued interest thereon, accrued fees and all other amounts payable to it hereunder and under the other Loan Documents (including any amounts under Section 8.04(e)) from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts);

(c)in the case of any such assignment resulting from a claim for compensation under Section 2.09 or payments required to be made pursuant to Section 2.12, such assignment will result in a reduction in such compensation or payments thereafter; and

(d)such assignment does not conflict with applicable Laws.

A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.

ARTICLE IIICONDITIONS PRECEDENT

Section 3.01Conditions Precedent to Effectiveness. This Agreement shall become effective on and as of the first date (the “Effective Date”) on which the following conditions precedent have been satisfied:

(a)The Lenders shall have been given such access to the management, records, books of account, contracts and properties of the Borrower and its Subsidiaries as they shall have requested.

(b)The Borrower shall have paid all accrued fees and agreed expenses of the Agent, the Arrangers and the Lenders, including but not limited to all fees payable pursuant to the Fee Letter, and the reasonable accrued fees and expenses of counsel to the Agent that have been invoiced at least one Business Day prior to the Effective Date.

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(c)On the Effective Date, the following statements shall be true and the Agent shall have received a certificate signed by a duly authorized officer of the Borrower, dated the Effective Date, stating that:

(i)The representations and warranties contained in Section 4.01 are true and correct on and as of the Effective Date, both before and after giving effect to the Initial Borrowing and the application of the proceeds thereof, as though made on and as of such date; and

(ii)No event has occurred and is continuing, or would result from the Initial Borrowing or the application of the proceeds thereof, that constitutes a Default.

(d)The Agent shall have received the Notice of Initial Borrowing pursuant to Section 2.02.

(e)The Agent shall have received on or before the Effective Date the following, each dated such day, in form and substance satisfactory to the Agent and the Lenders:

(i)Receipt by the Agent of executed counterparts of this Agreement properly executed by a duly authorized officer of the Borrower and by each Lender.

(ii)The Notes, payable to the order of the Lenders to the extent requested by any Lender pursuant to Section 2.14(a).

(iii)The articles of incorporation of the Borrower certified to be true and complete as of a recent date by the appropriate governmental authority of the state or other jurisdiction of its incorporation and certified by a secretary, assistant secretary or associate secretary of the Borrower to be true and correct as of the Effective Date.

(iv)The bylaws of the Borrower certified by a secretary, assistant secretary or associate secretary of the Borrower to be true and correct as of the Effective Date.

(v)Certified copies of the resolutions of the Board of Directors of the Borrower approving this Agreement and the Notes, and of all documents evidencing other necessary corporate action, third party consents and governmental approvals, if any, with respect to this Agreement and the Notes.

(vi)A certificate of the secretary, assistant secretary or associate secretary of the Borrower certifying the names and true signatures of the officers of the Borrower authorized to sign this Agreement and the Notes and the other documents to be delivered hereunder.

(vii)A certificate as of a recent date from the Borrower’s state of incorporation evidencing that the Borrower is in good standing in such state.

(viii)A favorable opinion of counsel for the Borrower, in form and substance reasonably acceptable to the Lenders.

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(ix)A written opinion of Sidley Austin LLP, special New York counsel for the Agent, addressed to the Agent and the Lenders, with respect to the enforceability of this Agreement and the Notes, if any, issued on the Effective Date, in form and substance reasonably acceptable to the Agent.

(x)A written certificate of an Authorized Officer certifying (i) all required regulatory authorizations including the 2013 Order and/or any Subsequent Order in respect of such Credit Extension have been obtained, are in full force and effect and, before and after giving effect to the Borrowing on the Closing Date and to the application of the proceeds thereform, the Borrower is in compliance with the provisions of the applicable order; and (ii) before and after giving effect to the Borrowing on the Closing Date and to the application of the proceeds thereform, as though made on and as of such date, the Indebtedness of the Borrower does not exceed that permitted by (a) applicable resolutions of the Board of Directors of the Borrower, (b) applicable Arizona Law, or (c) the 2013 Order or any Subsequent Order, whichever is in force and effect at such time.

(k)PATRIOT Act. The Borrower shall have provided to the Agent and the Lenders the documentation and other information reasonably requested by the Agent in order to comply with requirements of the PATRIOT Act.

Section 3.02Determinations Under Section 3.01. For purposes of determining compliance with the conditions specified in Section 3.01 and the satisfaction of each Lender with respect to letters delivered to it from the Borrower as set forth in Sections 4.01(a), 4.01(e) and 4.01(f), each Lender that has signed this Agreement shall be deemed to have consented to, approved or accepted or to be satisfied with each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to the Lenders unless an officer of the Agent responsible for the transactions contemplated by this Agreement shall have received notice from such Lender prior to the date that the Borrower designates as the proposed Effective Date, specifying its objection thereto. The Agent shall promptly notify the Lenders and the Borrower of the occurrence of the Effective Date.

ARTICLE IVREPRESENTATIONS AND WARRANTIES

Section 4.01Representations and Warranties of the Borrower. The Borrower represents and warrants as follows:

(a)Each of the Borrower and each Material Subsidiary: (i) is a corporation or other entity duly organized and validly existing under the Laws of the jurisdiction of its incorporation or organization; (ii) has all requisite corporate or if the Material Subsidiary is not a corporation, other comparable power necessary to own its assets and carry on its business as presently conducted; (iii) has all governmental licenses, authorizations, consents and approvals necessary to own its assets and carry on its business as presently conducted, if the failure to have any such license, authorization, consent or approval is reasonably likely to have a Material Adverse Effect and except as disclosed to the Agent in the SEC Reports or by means of a letter from the Borrower to the Lenders (such

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letter, if any, to be delivered to the Agent for prompt distribution to the Lenders) delivered prior to the execution and delivery of this Agreement (which, in each case, shall be satisfactory to each Lender in its sole discretion) and except that (A) the Borrower from time to time may make minor extensions of its lines, plants, services or systems prior to the time a related franchise, certificate of convenience and necessity, license or permit is procured, (B) from time to time communities served by the Borrower may become incorporated and considerable time may elapse before such a franchise is procured, (C) certain such franchises may have expired prior to the renegotiation thereof, (D) certain minor defects and exceptions may exist which, individually and in the aggregate, are not material and (E) certain franchises, certificates, licenses and permits may not be specific as to their geographical scope); and (iv) is qualified to do business in all jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure so to qualify is reasonably likely to have a Material Adverse Effect.

(b)The execution, delivery and performance by the Borrower of this Agreement and the other Loan Documents, and the consummation of the transactions contemplated hereby and thereby, are within the Borrower’s corporate powers, have been duly authorized by all necessary corporate action, and do not or did not (i) contravene the Borrower’s articles of incorporation or by-laws, (ii) contravene any Law (including without limitation the 2013 Order and/or any Subsequent Order), decree, writ, injunction or determination of any Governmental Authority, in each case applicable to or binding upon the Borrower or any of its properties, (iii) contravene any contractual restriction binding on or affecting the Borrower or (iv) cause the creation or imposition of any Lien upon the assets of the Borrower or any Material Subsidiary, except for Liens created under this Agreement and except where such contravention or creation or imposition of such Lien is not reasonably likely to have a Material Adverse Effect.

(c)No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority is required for the due execution, delivery and performance by the Borrower of this Agreement or the Notes to be delivered by it, except for the 2013 Order or any Subsequent Order, which has been duly obtained and is in full force and effect, and any notices or compliance filings required therein.

(d)This Agreement has been, and each of the other Loan Documents upon execution and delivery will have been, duly executed and delivered by the Borrower. This Agreement is, and each of the other Loan Documents upon execution and delivery will be, the legal, valid and binding obligation of the Borrower enforceable against the Borrower in accordance with their respective terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar Laws affecting creditors’ rights generally.

(e)(i) The Consolidated balance sheet of the Borrower as of December 31, 2014, and the related Consolidated statements of income and cash flows of the Borrower for the fiscal year then ended, accompanied by an opinion thereon of Deloitte & Touche LLP, independent registered public accountants, and the Consolidated balance sheet of the Borrower as of March 31. 2015, and the related Consolidated statements of income and cash flows of the Borrower for the three months then ended, duly certified by the chief financial officer of the Borrower, copies of which have been

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furnished to the Agent, fairly present in all material respects, subject, in the case of said balance sheet as of March 31, 2015, and said statements of income and cash flows for the three months then ended, to year-end audit adjustments, the Consolidated financial condition of the Borrower as at such dates and the Consolidated results of the operations of the Borrower for the periods ended on such dates, all in accordance with GAAP (except as disclosed therein); and (ii) except as disclosed to the Agent in the SEC Reports or by means of a letter from the Borrower to the Lenders (such letter, if any, to be delivered to the Agent for prompt distribution to the Lenders) delivered prior to the execution and delivery of this Agreement (which, in each case, shall be satisfactory to each Lender in its sole discretion), since December 31, 2014, there has been no Material Adverse Effect.

(f)There is no pending or, to the knowledge of an Authorized Officer of the Borrower, threatened action, suit, investigation, litigation or proceeding, including, without limitation, any Environmental Action, affecting the Borrower or any of its Subsidiaries before any court, governmental agency or arbitrator that (i) purports to affect the legality, validity or enforceability of this Agreement or any other Loan Document or the consummation of the transactions contemplated hereby or (ii) would be reasonably likely to have a Material Adverse Effect (except as disclosed to the Agent in the SEC Reports or by means of a letter from the Borrower to the Lenders (such letter, if any, to be delivered to the Agent for prompt distribution to the Lenders) delivered prior to the execution and delivery of this Agreement (which, in each case, shall be satisfactory to each Lender in its sole discretion)), and there has been no adverse change in the status, or financial effect on the Borrower or any of its Subsidiaries, of such disclosed litigation that would be reasonably likely to have a Material Adverse Effect.

(g)No proceeds of any Loan will be used to acquire any equity security not issued by the Borrower of a class that is registered pursuant to Section 12 of the Securities Exchange Act of 1934.

(h)The Borrower is not engaged in the business of extending credit for the purpose of purchasing or carrying margin stock (within the meaning of Regulation U issued by the Board of Governors of the Federal Reserve System), and no proceeds of any Loan will be used to purchase or carry any margin stock or to extend credit to others for the purpose of purchasing or carrying any margin stock, in any case in violation of Regulation U. After application of the proceeds of any Loan, not more than 25% of the value of the assets subject to any restriction under this Agreement on the right to sell, pledge, transfer, or otherwise dispose of such assets is represented by margin stock.

(i)The Borrower and its Subsidiaries have filed all United States of America Federal income Tax returns and all other material Tax returns which are required to be filed by them and have paid all Taxes due pursuant to such returns or pursuant to any assessment received by the Borrower or any of its Subsidiaries, except to the extent that (i) such Taxes are being contested in good faith and by appropriate proceedings and that appropriate reserves for the payment thereof have been maintained by the Borrower and its Subsidiaries in accordance with GAAP or (ii) the failure to make such filings or such payments is not reasonably likely to have a Material Adverse Effect. The charges, accruals and reserves on the books of the Borrower and its Material Subsidiaries as set forth in the most recent financial statements of the Borrower delivered to the Agent pursuant

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to Section 4.01(e) or Section 5.01(h)(i) or (ii) hereof in respect of Taxes and other governmental charges are, in the opinion of the Borrower, adequate.

(j)Set forth on Schedule 4.01(j) hereto (as such schedule may be modified from time to time by the Borrower by written notice to the Agent) is a complete and accurate list of all the Subsidiaries of the Borrower and, as of the Effective Date, no such Subsidiary of the Borrower is a Material Subsidiary.

(k)Set forth on Schedule 4.01(k) hereto is a complete and accurate list identifying any Indebtedness of the Borrower outstanding in a principal amount equal to or exceeding $5,000,000 and which is not described in the financial statements referred to in Section 4.01(e).

(l)The Borrower is not an “investment company”, or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended.

(m)No report, certificate or other written information furnished by the Borrower or any of its Subsidiaries to the Agent, any Arranger or any Lender in connection with the transactions contemplated hereby and the negotiation of this Agreement or delivered hereunder or any other Loan Document (as modified or supplemented by other information so furnished) at the time so furnished, when taken together as a whole with all such written information so furnished, contains an untrue statement of a material fact or omits to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, except as would not reasonably be expected to result in a Material Adverse Effect; provided that with respect to any projected financial information, forecasts, estimates or forward-looking information, the Borrower represents only that such information and materials have been prepared in good faith on the basis of assumptions believed to be reasonable at the time of preparation of such forecasts, and no representation or warranty is made as to the actual attainability of any such projections, forecasts, estimates or forward-looking information.

(n)Neither the Borrower nor any of its Subsidiaries or, to the knowledge of the Borrower, any of their respective Affiliates over which any of the foregoing exercises management control (each, a “Controlled Affiliate”) or any director or officer of the Borrower, any of its Subsidiaries or any of their respective Controlled Affiliates (each, a “Manager”) is a Prohibited Person, and the Borrower, its Subsidiaries and, to the knowledge of the Borrower, such Controlled Affiliates are in compliance with all applicable orders, rules and regulations of OFAC.

(o)Neither the Borrower nor any of its Subsidiaries or, to the knowledge of the Borrower, any of their respective Controlled Affiliates or Managers: (i) is the target of Sanctions; (ii) is owned or controlled by, or acts on behalf of, any Person that is targeted by United States or multilateral economic or trade sanctions currently in force; (iii) is, or is owned or controlled by, a Person who is located, organized or resident in a country or territory that is, or whose government is, the subject of Sanctions, including, without limitation, Cuba, Iran, North Korea, Sudan and Syria, or (iv) is named, identified or described on any list of Persons with whom United States Persons may not conduct business, including any such blocked persons list, designated nationals list, denied persons list, entity list, debarred party list, unverified list, sanctions list or other such lists published or

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maintained by the United States, including OFAC, the United States Department of Commerce or the United States Department of State.

(p)None of the Borrower’s or its Subsidiaries’ assets constitute property of, or are beneficially owned, directly or indirectly, by any Person that is the target of Sanctions, including but not limited to, the International Emergency Economic Powers Act, 50 U.S.C. §§ 1701 et seq., The Trading with the Enemy Act, 50 U.S.C. App. 1 et seq. (the “Trading With the Enemy Act”), any of the foreign assets control regulations of the Treasury (31 C.F.R., Subtitle B, Chapter V, as amended) (the “Foreign Assets Control Regulations”) or any enabling legislation or regulations promulgated thereunder or executive order relating thereto (which includes, without limitation, (i) Executive Order No. 13224, effective as of September 24, 2001, and relating to Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten to Commit, or Support Terrorism (66 Fed. Reg. 49079 (2001)) (the “Executive Order”) and (ii) the PATRIOT Act), if the result of such ownership would be that any Borrowing made by any Lender would be in violation of law (“Embargoed Person”); (a) no Embargoed Person has any interest of any nature whatsoever in the Borrower if the result of such interest would be that any Borrowing would be in violation of law; (b) the Borrower has not engaged in business with Embargoed Persons if the result of such business would be that any Borrowing made by any Lender would be in violation of law; (c) the Borrower will not, directly or indirectly, use the proceeds of the Borrowing, or lend, contribute or otherwise make available such proceeds to any subsidiary, joint venture partner or other Person, (i) to fund any activities or business of or with any Person, or in any country or territory, that, at the time of such funding, is, or whose government is, the subject of Sanctions, or (ii) in any other manner that would result in a violation of Sanctions or Anti-Corruption Laws by any Person (including any Person participating in the Borrowing, whether as a Lender or otherwise), and (d) neither the Borrower nor any Controlled Affiliate (i) is or will become a “blocked person” as described in the Executive Order, the Trading With the Enemy Act or the Foreign Assets Control Regulations or (ii) to the knowledge of the Borrower, engages in any dealings or transactions, or be otherwise associated, with any such “blocked person”. For purposes of determining whether or not a representation is true under this Section 4.01(p), with respect to the securities of the Borrower, the Borrower shall not be required to make any investigation into (x) the ownership of publicly traded stock or other publicly traded securities or (y) the beneficial ownership of any collective investment fund.

(q)Neither the Borrower nor any of its Subsidiaries or, to the knowledge of the Borrower and its Subsidiaries, any of their respective Managers, has failed to comply with the U.S. Foreign Corrupt Practices Act, as amended from time to time (the “FCPA”), or any other applicable Anti-Corruption Law, and it and they have not made, offered, promised or authorized, and will not make, offer, promise or authorize, whether directly or indirectly, any payment, of anything of value to a Government Official while knowing or having a reasonable belief that all or some portion will be used for the purpose of: (a) influencing any act, decision or failure to act by a Government Official in his or her official capacity, (b) inducing a Government Official to use his or her influence with a government or instrumentality to affect any act or decision of such  government or entity or (c) securing an improper advantage, in each case in order to obtain, retain or direct business.

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ARTICLE VCOVENANTS OF THE BORROWER

Section 5.01Affirmative Covenants. So long as any Loan or any other Obligations shall remain unpaid, the Borrower shall:

(a)Compliance with Laws, Etc. (i) Comply, and cause each of its Material Subsidiaries to comply, in all material respects, with all applicable Laws of Governmental Authorities, such compliance to include, without limitation, compliance with ERISA and Environmental Laws, unless the failure to so comply is not reasonably likely to have a Material Adverse Effect and (ii) comply at all times with the 2013 Order, any Subsequent Order, Arizona Revised Statutes, Section 40-302 and all similar or comparable Laws, orders, decrees, writs, injunctions or determinations of any Governmental Authority relating to the incurrence or maintenance of Indebtedness by the Borrower, such compliance to include, without limitation, compliance with the PATRIOT Act, all applicable orders, rules and regulations of OFAC, the FCPA, the Racketeer Influenced and Corrupt Organizations Chapter of the Organized Crime Control Act of 1970 and other Anti-Corruption Laws, except (other than in the case of the PATRIOT Act, the applicable orders, rules and regulations of OFAC, or the FCPA) to the extent that the failure to do so could not reasonably be expected to have a Material Adverse Effect.

(b)Payment of Taxes, Etc. Pay and discharge, and cause each of its Subsidiaries to pay and discharge, before the same shall become delinquent, all Taxes, imposed upon it or upon its property; provided, however, that neither the Borrower nor any of its Subsidiaries shall be required to pay or discharge any such Tax (i) that is being contested in good faith and by proper proceedings and as to which appropriate reserves are being maintained in accordance with GAAP or (ii) if the failure to pay such Tax is not reasonably likely to have a Material Adverse Effect.

(c)Maintenance of Insurance. Maintain, and cause each of its Material Subsidiaries to maintain, insurance with responsible and reputable insurance companies or associations in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties in the same general areas in which the Borrower or such Material Subsidiary operates; provided, however, that the Borrower and its Subsidiaries may self-insure to the same extent as other companies engaged in similar businesses and owning similar properties in the same general areas in which the Borrower or such Subsidiary operates and to the extent consistent with prudent business practice.

(d)Preservation of Corporate Existence, Etc. Preserve and maintain, and cause each of its Material Subsidiaries to preserve and maintain, its corporate existence, rights (charter and statutory) and franchises (other than “franchises” as described in Arizona Revised Statutes, Section 40-283 or any successor provision) reasonably necessary in the normal conduct of its business, if the failure to maintain such rights or privileges is reasonably likely to have a Material Adverse Effect, and will use its commercially reasonable efforts to preserve and maintain such franchises reasonably necessary in the normal conduct of its business, except that (i) the Borrower from time to time may make minor extensions of its lines, plants, services or systems prior to the time a related franchise, certificate of convenience and necessity, license or permit is procured, (ii) from time to

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time communities served by the Borrower may become incorporated and considerable time may elapse before such a franchise is procured, (iii) certain such franchises may have expired prior to the renegotiation thereof, (iv) certain minor defects and exceptions may exist which, individually and in the aggregate, are not material and (v) certain franchises, certificates, licenses and permits may not be specific as to their geographical scope; provided, however, that the Borrower and its Subsidiaries may consummate any merger or consolidation permitted under Section 5.02(b).

(e)Visitation Rights. At any reasonable time and from time to time, permit and cause each of its Subsidiaries to permit the Agent or any of the Lenders or any agents or representatives thereof, to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, the Borrower and any of its Subsidiaries, and to discuss the affairs, finances and accounts of the Borrower and any of its Subsidiaries with any of their officers or directors; provided, however, that the Borrower and its Subsidiaries reserve the right to restrict access to any of its properties in accordance with reasonably adopted procedures relating to safety and security; and providedfurther that the costs and expenses incurred by such Lender or its agents or representatives in connection with any such examinations, copies, abstracts, visits or discussions shall be, upon the occurrence and during the continuation of a Default, for the account of the Borrower and, in all other circumstances, for the account of such Lender.

(f)Keeping of Books. Keep, and cause each of its Material Subsidiaries to keep, proper books of record and account, in which full and correct entries shall be made of all financial transactions and the assets and business of the Borrower and each such Subsidiary in a manner that permits the preparation of financial statements in accordance with GAAP.

(g)Maintenance of Properties, Etc. Keep, and cause each Material Subsidiary to keep, all property useful and necessary in its business in good working order and condition (ordinary wear and tear excepted), if the failure to do so is reasonably likely to have a Material Adverse Effect, it being understood that this covenant relates only to the working order and condition of such properties and shall not be construed as a covenant not to dispose of properties.

(h)Reporting Requirements. Furnish to the Agent:

(i)as soon as available and in any event within 50days after the end of each of the first three fiscal quarters of each fiscal year of the Borrower commencing with the fiscal quarter ending June 30, 2015, (A) for each such fiscal quarter of the Borrower, Consolidated statements of income and cash flows of the Borrower for such fiscal quarter and the related Consolidated balance sheet of the Borrower as of the end of such fiscal quarter setting forth in each case in comparative form the corresponding figures for the corresponding fiscal quarter in (or, in the case of the balance sheet, as of the end of) the preceding fiscal year and (B) for the period commencing at the end of the previous fiscal year and ending with the end of such fiscal quarter, Consolidated statements of income and cash flows of the Borrower for such period setting forth in each case in comparative form the corresponding figures for the corresponding period in the preceding fiscal year; provided that so long as the Borrower remains subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the Borrower may provide, in satisfaction of the requirements of this first sentence of this Section 5.01(h)(i), its report on Form 10-Q for such fiscal quarter. Each set of financial

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statements provided under this Section 5.01(h)(i) shall be accompanied by a certificate of an Authorized Officer, which certificate shall state that said Consolidated financial statements fairly present in all material respects the Consolidated financial condition and results of operations and cash flows of the Borrower in accordance with GAAP (except as disclosed therein), as at the end of, and for, such period (subject to normal year-end audit adjustments) and shall set forth reasonably detailed calculations demonstrating compliance with Section 5.03;

(ii)as soon as available and in any event within 90 days after the end of each fiscal year of the Borrower, commencing with the fiscal year ending December 31, 2015, audited Consolidated statements of income and cash flows of the Borrower for such year and the related Consolidated balance sheet of the Borrower as at the end of such year, setting forth in each case in comparative form the corresponding figures for the preceding fiscal year; provided that, so long as the Borrower remains subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the Borrower may provide, in satisfaction of the requirements of this first sentence of this Section 5.01(h)(ii), its report on Form 10-K for such fiscal year. Each set of financial statements provided pursuant to this Section 5.01(h)(ii) shall be accompanied by (A) an opinion thereon of independent certified public accountants of recognized national standing, which opinion shall state that said Consolidated financial statements fairly present in all material respects the Consolidated financial condition and results of operations of the Borrower as at the end of, and for, such fiscal year, in accordance with GAAP (except as disclosed therein) and (B) a certificate of an Authorized Officer, which certificate shall set forth reasonably detailed calculations demonstrating compliance with Section 5.03;

(iii)as soon as possible and in any event within five days after any Authorized Officer of the Borrower knows of the occurrence of each Default continuing on the date of such statement, a statement of an Authorized Officer of the Borrower setting forth details of such Default and the action that the Borrower has taken and proposes to take with respect thereto;

(iv)promptly after the sending or filing thereof, copies of all reports and registration statements (other than exhibits thereto and registration statements on Form S-8 or its equivalent) that the Borrower or any Subsidiary files with the Securities and Exchange Commission;

(v)promptly after an Authorized Officer becomes aware of the commencement thereof, notice of all actions and proceedings before any court, governmental agency or arbitrator affecting the Borrower or any of its Subsidiaries of the type described in Section 4.01(f), except, with respect to any matter referred to in Section 4.01(f)(ii), to the extent disclosed in a report on Form 8-K, Form 10-Q or Form 10-K of the Borrower;

(vi)promptly after (A) any amendment or modification of the 2013 Order, (B) any amendment or modification of Arizona Revised Statutes, Section 40-302, or the promulgation, amendment or modification of any successor or similar statute, or (C) the promulgation, amendment or modification of any Subsequent Order by the Arizona

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Corporation Commission or any successor thereto, in any case if such amendment, modification or promulgation could affect the validity or enforceability of the indebtedness of the Borrower pursuant to this Agreement, a copy thereof;

(vii)promptly after an Authorized Officer becomes aware of the occurrence thereof, notice of any change by Moody’s or S&P of its respective Public Debt Rating or of the cessation (or subsequent commencement) by Moody’s or S&P of publication of its respective Public Debt Rating;

(viii)promptly after the occurrence thereof, notice of the occurrence of any ERISA Event, together with (x) a written statement of an Authorized Officer of the Borrower specifying the details of such ERISA Event and the action that the Borrower has taken and proposes to take with respect thereto, (y) a copy of any notice with respect to such ERISA Event that may be required to be filed with the PBGC and (z) a copy of any notice delivered by the PBGC to the Borrower or an ERISA Affiliate with respect to such ERISA Event; and

(ix)such other information respecting the Borrower or any of its Subsidiaries as any Lender through the Agent may from time to time reasonably request.

Information required to be delivered pursuant to Sections 5.01(h)(i), (ii) and (iv) above shall be deemed to have been delivered on the date on which the Borrower provides notice to the Agent that such information has been posted on the Borrower’s parent’s website on the Internet at www.pinnaclewest.com, at sec.gov/edaux/searches.htm or at another website identified in such notice and accessible by the Lenders without charge; provided that (i) such notice may be included in a certificate delivered pursuant to Section 5.01(h)(i) or (ii) and (ii) the Borrower shall deliver paper copies of the information referred to in Section 5.01(h)(i), (ii), and (iv) to any Lender which requests such delivery.

(i)Change in Nature of Business. Conduct the same general type of business conducted on the date hereof.

Section 5.02Negative Covenants. So long as Loan or any other Obligations shall remain unpaid, the Borrower shall not:

(a)Liens, Etc. Create or suffer to exist, or permit any of its Material Subsidiaries to create or suffer to exist, any Lien on or with respect to any of its properties, whether now owned or hereafter acquired, or assign, or permit any of its Material Subsidiaries to assign, any right to receive income, other than:

(i)Permitted Liens;

(ii)Liens upon or in, or conditional sales agreements or other title retention agreements with respect to, any real or personal property acquired or held by the Borrower or any Subsidiary in the ordinary course of business to secure the purchase price of such property, or the construction of or improvements to such property, or to secure Indebtedness incurred solely for the purpose of financing the acquisition, construction or improvement

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of such property to be subject to such Liens (including any Liens placed on such property within 180 days after the latest of the acquisition, completion of construction or improvement of such property), or Liens existing on such property at the time of its acquisition (other than any such Liens created in contemplation of such acquisition that were not incurred to finance the acquisition of such property) or extensions, renewals, refundings or replacements of any of the foregoing for the same or a lesser amount, provided, however, that no such Lien shall extend to or cover any properties of any character other than the property being acquired, constructed or improved and proceeds, improvements and replacements thereof and no such extension, renewal, refunding or replacement shall extend to or cover any properties not theretofore subject to the Lien being extended, renewed, refunded or replaced;

(iii)assignments of the right to receive income, and Liens on property, of a Person existing at the time such Person is merged into or consolidated with the Borrower or any Subsidiary of the Borrower or becomes a Subsidiary of the Borrower;

(iv)Liens with respect to the leases and related documents entered into by the Borrower in connection with PVNGS Unit 2 and Liens with respect to the leased interests and related rights if the Borrower reacquires ownership in any of those interests or acquires any of the equity or owner participants’ interests in the trusts that hold title to such leased interests, whether or not it also directly assumes the Sale Leaseback Obligation Bonds, and Liens on the Borrower’s interests in the trusts that hold title to such leased interests and related rights in the event that the Borrower acquires any of the equity or owner participants’ interests in such trusts pursuant to a “special transfer” under the Borrower’s existing PVNGS Unit 2 sale and leaseback transactions and any Liens resulting or deemed to have resulted if the PVNGS Unit 2 leases are required to be accounted for as capital leases in accordance with GAAP;

(v)other assignments of the right to receive income and Liens securing Indebtedness or claims in an aggregate principal amount not to exceed 20% of the Borrower’s total assets as stated on the most recent balance sheet of the Borrower provided pursuant to Section 4.01(e)(i) or 5.01(h)(ii) hereof at any time outstanding; and

(vi)the replacement, extension or renewal of any Lien permitted by clause (iii) or (iv) above upon or in the same property theretofore subject thereto or the replacement, extension or renewal (without increase in the amount or change in any direct or contingent obligor) of the Indebtedness secured thereby.

(b)Mergers, Etc. Merge or consolidate with or into any Person, or permit any of its Material Subsidiaries to do so, except that (i) any Material Subsidiary of the Borrower may merge or consolidate with or into any other Material Subsidiary of the Borrower, (ii) any Subsidiary of the Borrower may merge into the Borrower or any Material Subsidiary of the Borrower and (iii) the Borrower or any Material Subsidiary may merge with any other Person so long as the Borrower or such Material Subsidiary is the surviving corporation, provided, in each case, that no Default shall have occurred and be continuing at the time of such proposed transaction or would result therefrom.

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(c)Sales, Etc. of Assets. Sell, lease, transfer or otherwise dispose of, or permit any of its Material Subsidiaries to sell, lease, transfer or otherwise dispose of, any assets, or grant any option or other right to purchase, lease or otherwise acquire any assets to any Person other than the Borrower or any Subsidiary of the Borrower, except (i) dispositions in the ordinary course of business, including, without limitation, sales or other dispositions of electricity and related and ancillary services, other commodities, emissions credits and similar mechanisms for reducing pollution, and damaged, obsolete, worn out or surplus property no longer required or useful in the business or operations of the Borrower or any of its Subsidiaries, (ii) sale or other disposition of patents, copyrights, trademarks or other intellectual property that are, in the Borrower’s reasonable judgment, no longer economically practicable to maintain or necessary in the conduct of the business of the Borrower or its Subsidiaries and any license or sublicense of intellectual property that does not interfere with the business of the Borrower or any Material Subsidiary, (iii) in a transaction authorized by subsection (b) of this Section, (iv) individual dispositions occurring in the ordinary course of business which involve assets with a book value not exceeding $5,000,000, (v) sales, leases, transfers or other dispositions of assets during the term of this Agreement having an aggregate book value not to exceed 30% of the total of all assets properly appearing on the most recent balance sheet of the Borrower provided pursuant to Section 4.01(e) or 5.01(h)(ii) hereof, (vi) at any time following the consummation of the Four Corners Acquisition, which occurred on December 30, 2013 and the closure by the Borrower of Units 1, 2 and 3 of the Four Corners Power Plant near Farmington, New Mexico, as described in the SEC Reports, disposition of all or any portion of the Borrower’s interests in such Units 1, 2 and 3, and (vii) any Lien permitted under Section 5.02(a).

Section 5.03Financial Covenant. So long as any Loan or any other Obligations shall remain unpaid, the Borrower will maintain a ratio of (a) Consolidated Indebtedness to (b) the sum of Consolidated Indebtedness plus Consolidated Net Worth of not greater than 0.65 to 1.

ARTICLE VIEVENTS OF DEFAULT

Section 6.01Events of Default. If any of the following events (“Events of Default”) shall occur and be continuing:

(a)The Borrower shall fail to pay when due (i) any principal of any Loan or (ii) any interest on any Loan or any fees or other amounts payable under this Agreement or any other Loan Documents, and (in the case of this clause (ii) only) such failure shall continue for a period of three Business Days; or

(b)Any representation or warranty made by the Borrower herein or by the Borrower (or any of its officers) in any certificate or other document delivered in connection with this Agreement or any other Loan Document shall prove to have been incorrect in any material respect when made or deemed made or furnished; or

(c)(i) The Borrower shall fail to perform or observe any term, covenant or agreement contained in Section 2.15, Section 5.01(d) (as to the corporate existence of the Borrower), Section 5.01(h)(iii), Section 5.01(h)(vi), Section 5.02 or Section 5.03; or (ii) the Borrower shall fail to

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perform or observe any term, covenant or agreement contained in Section 5.01(e) if such failure shall remain unremedied for 15 days after written notice thereof shall have been given to the Borrower by the Agent or any Lender; or (iii) the Borrower shall fail to perform or observe any other term, covenant or agreement contained in this Agreement or any other Loan Document on its part to be performed or observed if such failure shall remain unremedied for 30 days after written notice thereof shall have been given to the Borrower by the Agent or any Lender; or

(d)(i) The Borrower or any of its Material Subsidiaries shall fail to pay (A) any principal of or premium or interest on any Indebtedness that is outstanding in a principal amount of at least $35,000,000 in the aggregate (but excluding Indebtedness outstanding hereunder), or (B) an amount, or post collateral as contractually required in an amount, of at least $35,000,000 in respect of any Hedge Agreement, of the Borrower or such Material Subsidiary (as the case may be), in each case, when the same becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Indebtedness or Hedge Agreement; or (ii) any event of default shall exist under any agreement or instrument relating to any such Indebtedness and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such event is to accelerate, or to permit the acceleration of, the maturity of such Indebtedness; or

(e)The Borrower or any of its Material Subsidiaries shall fail to pay any principal of or premium or interest in respect of any operating lease in respect of which the payment obligations of the Borrower have a present value of at least $35,000,000, when the same becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in such operating lease, if the effect of such failure is to terminate, or to permit the termination of, such operating lease; or

(f)The Borrower or any of its Material Subsidiaries shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower or any of its Material Subsidiaries seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any Debtor Relief Law, or seeking the entry of an order for relief or the appointment of a receiver, trustee, custodian or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it), either such proceeding shall remain undismissed or unstayed for a period of 60 days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or the Borrower or any of its Material Subsidiaries shall take any corporate action to authorize any of the actions set forth above in this subsection (f); or

(g)Judgments or orders for the payment of money that exceed any applicable insurance coverage (the insurer of which shall be rated at least “A” by A.M. Best Company) by more than

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$35,000,000 in the aggregate shall be rendered against the Borrower or any Material Subsidiary and such judgments or orders shall continue unsatisfied or unstayed for a period of 45 days; or

(h)(i) Any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, but excluding any employee benefit plan of such person or its subsidiaries, and any person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan) becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934), directly or indirectly, of 30% or more of the equity securities of PWCC entitled to vote for members of the board of directors of PWCC; or (ii) during any period of 24 consecutive months, a majority of the members of the board of directors of PWCC cease (other than due to death or disability) to be composed of individuals (A) who were members of that board on the first day of such period, (B) whose election or nomination to that board was approved by individuals referred to in clause (A) above constituting at the time of such election or nomination at least a majority of that board or (C) whose election or nomination to that board was approved by individuals referred to in clauses (A) and (B) above constituting at the time of such election or nomination at least a majority of that board; or (iii) PWCC shall cease for any reason to own, directly or indirectly, 80% of the Voting Stock of the Borrower; or

(i)(i) An ERISA Event occurs with respect to a Pension Plan or Multiemployer Plan which has resulted or could reasonably be expected to result in liability of the Borrower under Title IV of ERISA to the Pension Plan, Multiemployer Plan or the PBGC in an aggregate amount in excess of $35,000,000; or (ii) the Borrower or any ERISA Affiliate fails to pay when due, after the expiration of any applicable grace period, any installment payment with respect to its withdrawal liability under Section 4201 of ERISA under a Multiemployer Plan in an aggregate amount in excess of $35,000,000;

then, and in any such event, the Agent shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, (i) declare the Loans, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon the Loans, all such interest and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower; provided, however, that in the event of an actual or deemed entry of an order for relief with respect to the Borrower under the Bankruptcy Code of the United States of America, the Loans, all such interest and all such amounts shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower, and (ii) exercise all rights and remedies available to it under this Agreement, the other Loan Documents and applicable Law.

ARTICLE VIITHE AGENT

Section 7.01Appointment and Authority. Each of the Lenders hereby irrevocably appoints Toronto Dominion (Texas) LLC to act on its behalf as the Agent hereunder and under the other Loan Documents and authorizes the Agent to take such actions on its behalf and to exercise such powers as are delegated to the Agent by the terms hereof or thereof, together with such actions and

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powers as are reasonably incidental thereto. Except as set forth in Section 7.06, the provisions of this Article are solely for the benefit of the Agent and the Lenders, and neither the Borrower nor any of its Affiliates shall have rights as a third party beneficiary of any of such provisions.

Section 7.02Rights as a Lender. The Person serving as the Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Agent and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context otherwise requires, include the Person serving as the Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, act as the financial advisor or in any other advisory capacity for and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if such Person were not the Agent hereunder and without any duty to account therefor to the Lenders.

Section 7.03Exculpatory Provisions. The Agent shall not have any duties or obligations except those expressly set forth herein and in the other Loan Documents. Without limiting the generality of the foregoing, the Agent:

(a)shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing;

(b)shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein), provided that the Agent shall not be required to take any action that, in its opinion or the opinion of its counsel, may expose the Agent to liability or that is contrary to any Loan Document or applicable Law; and

(c)shall not, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Affiliates that is communicated to or obtained by the Person serving as the Agent or any of its Affiliates in any capacity.

The Agent shall not be liable for any action taken or not taken by it (i) with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary, or as the Agent shall believe in good faith shall be necessary, under the circumstances as provided in Section 6.01 and Section 8.01) or (ii) in the absence of its own gross negligence or willful misconduct. The Agent shall be deemed not to have knowledge of any Default unless and until notice describing such Default is given to the Agent by the Borrower or a Lender.

The Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document or (v) the satisfaction of

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any condition set forth in Article III or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Agent.

Section 7.04Reliance by Agent. The Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of any Loan that by its terms must be fulfilled to the satisfaction of a Lender, the Agent may presume that such condition is satisfactory to such Lender unless the Agent shall have received notice to the contrary from such Lender prior to the making of such Loan. The Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in good faith in accordance with the advice of any such counsel, accountants or experts.

Section 7.05Delegation of Duties. The Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub-agents appointed by the Agent. The Agent and any such sub-agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Article shall apply to any such sub-agent and to the Related Parties of the Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Agent.

Section 7.06Resignation of Agent. The Agent may at any time give notice of its resignation to the Lenders and the Borrower. Upon receipt of any such notice of resignation, the Required Lenders shall have the right, with the consent of the Borrower so long as no Event of Default has occurred and is continuing, to appoint a successor, which shall be a bank with an office in the United States of America, or an Affiliate of any such bank with an office in the United States of America. If no such successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 45 days after the retiring Agent gives notice of its resignation, then the retiring Agent may, on behalf of the Lenders, appoint a successor Agent meeting the qualifications set forth above; provided that if the Agent shall notify the Borrower and the Lenders that no qualifying Person has accepted such appointment, then such resignation shall nonetheless become effective in accordance with such notice and (1) the retiring Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents (except that in the case of any collateral security held by the Agent on behalf of the Lenders under any of the Loan Documents, the retiring Agent shall continue to hold such collateral security until such time as a successor Agent is appointed) and (2) all payments, communications and determinations provided to be made by, to or through the Agent shall instead be made by or to each Lender directly, until such time as the Required Lenders appoint a successor Agent as provided for above in this Section. Upon the acceptance of a successor’s appointment as Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired)

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Agent, and the retiring Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents (if not already discharged therefrom as provided above in this Section). The fees payable by the Borrower to a successor Agent shall be as agreed between the Borrower and such successor. After the retiring Agent’s resignation hereunder and under the other Loan Documents, the provisions of this Article and Section 8.04 shall continue in effect for the benefit of such retiring Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Agent was acting as Agent.

Section 7.07Non-Reliance on Agent and Other Lenders. Each Lender acknowledges that it has, independently and without reliance upon the Agent or any other Lender or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Agent or any other Lender or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder.

Section 7.08No Other Duties, Etc. Anything herein to the contrary notwithstanding, none of the Arrangers, the Syndication Agent or any other agents listed on the cover page hereof shall have any powers, duties or responsibilities under this Agreement or any of the other Loan Documents, except in its capacity, as applicable, as the Agent or a Lender hereunder.

ARTICLE VIIIMISCELLANEOUS

Section 8.01Amendments, Etc. No amendment or waiver of any provision of this Agreement or any other Loan Document, nor consent to any departure by the Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Required Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall

(a)unless agreed to by each Lender directly affected thereby, (i) reduce or forgive the principal amount of any Loan, reduce the rate of or forgive any interest thereon (provided that only the consent of the Required Lenders shall be required to waive the applicability of any post-default increase in interest rates), or reduce or forgive any fees hereunder (other than fees payable to the Agent or the Arrangers for their own respective accounts), (ii) extend the final scheduled maturity date or any other scheduled date for the payment of any principal of or interest on any Loan, or extend the time of payment of any fees hereunder (other than fees payable to the Agent or the Arrangers for their own respective accounts), or (iii) increase any Commitment of any such Lender over the amount thereof in effect or extend the maturity thereof (it being understood that a waiver of any Default, if agreed to by the Required Lenders or all Lenders (as may be required hereunder with respect to such waiver), shall not constitute such an increase);

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(b)unless agreed to by all of the Lenders, (i) reduce the percentage of the aggregate Commitments or of the aggregate unpaid principal amount of the Loans, or the number or percentage of Lenders, that shall be required for the Lenders or any of them to take or approve, or direct the Agent to take, any action hereunder or under any other Loan Document (including as set forth in the definition of “Required Lenders”), (ii) change any other provision of this Agreement or any of the other Loan Documents requiring, by its terms, the consent or approval of all the Lenders for any amendment, modification, waiver, discharge or termination thereof or any consent to any departure by the Borrower therefrom, or (iii) change or waive any provision of Section 2.13, any other provision of this Agreement or any other Loan Document requiring pro rata treatment of any Lenders, or this Section 8.01 or Section 2.17(b); and

(c)unless agreed to by the Agent in addition to the Lenders required as provided hereinabove to take such action, affect the respective rights or obligations of the Agent hereunder or under any of the other Loan Documents.

(d)If, in connection with any proposed amendment, waiver or consent requiring the consent of “each Lender” or “each Lender directly affected thereby,” the consent of the Required Lenders is obtained, but the consent of other necessary Lenders is not obtained (any such Lender whose consent is necessary but not obtained being referred to herein as a “Non-Consenting Lender”), then the Borrower may elect to replace a Non-Consenting Lender as a Lender party to this Agreement, provided that, concurrently with such replacement, (i) another bank or other entity which is reasonably satisfactory to the Borrower and the Agent shall agree, as of such date, to purchase for cash the Loans and other Obligations due to the Non-Consenting Lender pursuant to an Assignment and Assumption and to become a Lender for all purposes under this Agreement and to assume all obligations of the Non-Consenting Lender to be terminated as of such date and to comply with the requirements of clause (b) of Section 8.07, and (ii) the Borrower shall pay to such Non-Consenting Lender in same day funds on the day of such replacement (1) all interest, fees and other amounts then accrued but unpaid to such Non-Consenting Lender by the Borrower hereunder to and including the date of termination, including without limitation payments due to such Non-Consenting Lender under Sections 2.09 and 2.12, and (2) an amount, if any, equal to the payment which would have been due to such Lender on the day of such replacement under Section 8.04(e) had the Loans of such Non-Consenting Lender been prepaid on such date rather than sold to the replacement Lender.

Section 8.02Notices, Etc.

(a)All notices and other communications provided for hereunder shall be either (x) in writing (including facsimile communication) and mailed, faxed or delivered or (y) delivered, furnished, distributed or made available as and to the extent set forth in Sections 8.02(b) and (c), if to the Borrower, at the address specified on Schedule 8.02; if to any Lender, at its Domestic Lending Office; and if to the Agent, at the address specified on Schedule 8.02; or, as to the Borrower or the Agent, at such other address as shall be designated by such party in a written notice to the other parties and, as to each other party, at such other address as shall be designated by such party in a written notice to the Borrower and the Agent. All such notices and communications shall, when mailed or faxed, be effective when deposited in the mails or faxed, respectively, except that notices and communications to the Agent pursuant to Article II, III or VII shall not be effective until received

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by the Agent. Delivery by facsimile of an executed counterpart of any amendment or waiver of any provision of this Agreement or the Notes or of any Exhibit hereto to be executed and delivered hereunder shall be effective as delivery of a manually executed counterpart thereof. Notices delivered through electronic communications to the extent provided in subsection (b) below, shall be effective as provided in such subsection (b). Upon request of the Borrower, the Agent will provide to the Borrower (i) copies of each Administrative Questionnaire or (ii) the address of each Lender.

(b)Notices and other communications to the Lenders and the Agent hereunder may be delivered or furnished by electronic communication (including e-mail and Internet or intranet websites) pursuant to procedures approved by the Agent and agreed to by the Borrower, provided that the foregoing shall not apply to notices to any Lender pursuant to Article II if such Lender has notified the Agent and the Borrower that it is incapable of receiving notices under such Article by electronic communication. The Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it, provided that approval of such procedures may be limited to particular notices or communications. Unless the Agent and the Borrower otherwise agree, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next Business Day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.

(c)The Borrower agrees that the Agent may make materials delivered to the Agent pursuant to Sections 5.01(h)(i), (ii) and (iv), as well as any other written information, documents, instruments and other material relating to the Borrower or any of its Subsidiaries and relating to this Agreement, the Notes or the transactions contemplated hereby, or any other materials or matters relating to this Agreement, the Notes or any of the transactions contemplated hereby (collectively, the “Communications”) available to the Lenders by posting such notices on Intralinks or a substantially similar electronic system (the “Platform”). The Borrower acknowledges that (i) the distribution of material through an electronic medium is not necessarily secure and that there are confidentiality and other risks associated with such distribution, (ii) the Platform is provided “as is” and “as available” and (iii) neither the Agent nor any of its Affiliates warrants the accuracy, adequacy or completeness of the Communications or the Platform and each expressly disclaims liability for errors or omissions in the Communications or the Platform. No warranty of any kind, express, implied or statutory, including, without limitation, any warranty of merchantability, fitness for a particular purpose, non-infringement of third party rights or freedom from viruses or other code defects, is made by the Agent or any of its Affiliates in connection with the Platform.

(d)Each Lender agrees that notice to it (as provided in the next sentence) (a “Notice”) specifying that any Communications have been posted to the Platform shall constitute effective

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delivery of such information, documents or other materials to such Lender for purposes of this Agreement; provided that if requested by any Lender the Agent shall deliver a copy of the Communications to such Lender by e-mail, facsimile or mail. Each Lender agrees (i) to notify the Agent in writing of such Lender’s e-mail address to which a Notice may be sent by electronic transmission (including by electronic communication) on or before the date such Lender becomes a party to this Agreement (and from time to time thereafter to ensure that the Agent has on record an effective e-mail address for such Lender) and (ii) that any Notice may be sent to such e-mail address.

(e)The Borrower hereby acknowledges that certain of the Lenders may be “public-side” Lenders (i.e., Lenders that do not wish to receive material non-public information with respect to the Borrower or its securities) (each, a “Public Lender”). The Borrower hereby agrees that (w) all Communications that are to be made available to Public Lenders shall be clearly and conspicuously marked “PUBLIC” which shall mean that the word “PUBLIC” shall appear prominently on the first page thereof; (x) by marking Communications “PUBLIC,” the Borrower shall be deemed to have authorized the Agent, the Arrangers and the Lenders to treat such Communications as not containing any material non-public information with respect to the Borrower or its securities for purposes of United States of America federal and state securities laws; (y) all Communications marked “PUBLIC” are permitted to be made available through a portion of the Platform designated as “Public Investor;” and (z) the Agent and the Arrangers shall be entitled to treat any Communications that are not marked “PUBLIC” as being suitable only for posting on a portion of the Platform not marked as “Public Investor.” Notwithstanding the foregoing, the Borrower shall be under no obligation to mark any Communications “PUBLIC.” Notwithstanding anything to the contrary herein, the Borrower and the Agent need not provide to any Public Lender any information, notice, or other document hereunder that is not public information, including without limitation, the Notice of Initial Borrowing and any notice of Default.

Section 8.03No Waiver; Cumulative Remedies; Enforcement. No failure by any Lender or the Agent to exercise, and no delay by any such Person in exercising, any right, remedy, power or privilege hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by Law.

Notwithstanding anything to the contrary contained herein or in any other Loan Document, the authority to enforce rights and remedies hereunder and under the other Loan Documents against the Borrower shall be vested exclusively in, and all actions and proceedings at Law in connection with such enforcement shall be instituted and maintained exclusively by, the Agent in accordance with Article VI for the benefit of all the Lenders; provided, however, that the foregoing shall not prohibit (a) the Agent from exercising on its own behalf the rights and remedies that inure to its benefit (solely in its capacity as Agent) hereunder and under the other Loan Documents, (b) any Lender from exercising setoff rights in accordance with Section 8.05 (subject to the terms of Section 2.13), or (c) any Lender from filing proofs of claim or appearing and filing pleadings on its own behalf during the pendency of a proceeding relative to the Borrower under any Debtor Relief Law;

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and provided, further, that if at any time there is no Person acting as Agent hereunder and under the other Loan Documents, then (i) the Required Lenders shall have the rights otherwise ascribed to the Agent pursuant to Article VI and (ii) in addition to the matters set forth in clauses (b) and (c) of the preceding proviso and subject to Section 2.13, any Lender may, with the consent of the Required Lenders, enforce any rights and remedies available to it and as authorized by the Required Lenders.

Section 8.04Costs and Expenses; Indemnity; Damage Waiver.

(a)The Borrower agrees to pay on demand all costs and expenses of the Agent in connection with the administration, modification and amendment of this Agreement, the Notes and the other Loan Documents to be delivered hereunder, including, without limitation, the reasonable fees and expenses of counsel for the Agent with respect thereto and with respect to advising the Agent as to its rights and responsibilities under this Agreement. The Borrower further agrees to pay on demand all costs and expenses of the Agent and the Lenders, if any (including, without limitation, reasonable counsel fees and expenses), in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement, the Notes and the other Loan Documents to be delivered hereunder, including, without limitation, reasonable fees and expenses of counsel for the Agent and each Lender in connection with the enforcement of rights under this Section 8.04(a).

(b)The Borrower agrees to indemnify and hold harmless the Agent (and any sub-agent thereof), each Lender, each Arranger, the Syndication Agent and each Related Party of any of the foregoing (each, an “Indemnified Party”) from and against any and all claims, damages, losses, liabilities and expenses (including, without limitation, reasonable fees and expenses of counsel) incurred by or asserted or awarded against any Indemnified Party, in each case arising out of or in connection with or by reason of (including, without limitation, in connection with any investigation, litigation or proceeding or preparation of a defense in connection therewith, whether based on contract, tort or any other theory) (i) the Notes, this Agreement, any other Loan Document, any of the transactions contemplated herein or the actual or proposed use of the proceeds of any Loan, or (ii) the actual or alleged presence of Hazardous Materials on any property of the Borrower or any of its Subsidiaries or any Environmental Action relating in any way to the Borrower or any of its Subsidiaries, provided that such indemnity shall not, as to any Indemnified Party, be available to the extent (a) such fees and expenses are expressly stated in this Agreement to be payable by the Indemnified Party, included expenses payable under Section 2.12, Section 5.01(e) and Section 8.07(b) or (b) such claim, damage, loss, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence, willful misconduct or material breach of its obligations under this Agreement, in which case any fees and expenses previously paid or advanced by the Borrower to such Indemnified Party in respect of such indemnified obligation will be returned by such Indemnified Party. In the case of an investigation, litigation or other proceeding to which the indemnity in this Section 8.04(b) applies, such indemnity shall be effective whether or not such investigation, litigation or proceeding is brought by the Borrower, its directors, equityholders or creditors or an Indemnified Party or any other Person, whether or not any Indemnified Party is otherwise a party thereto, and whether or not the transactions contemplated hereby are consummated, provided that if the Borrower and such Indemnified Party are adverse parties in any such litigation or proceeding, and the Borrower prevails

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in a final, non-appealable judgment by a court of competent jurisdiction, any amounts under this Section 8.04(b) previously paid or advanced by the Borrower to such Indemnified Party pursuant to this Section 8.04(b) will be returned by such Indemnified Party.

(c)To the extent that the Borrower for any reason fails to indefeasibly pay any amount required under subsection (a) or (b) of this Section to be paid by it to the Agent (or any sub-agent thereof) or any Related Party of any of the foregoing (and without limiting its obligation to do so), each Lender severally agrees to pay to the Agent (or any such sub-agent) or such Related Party, as the case may be, such Lender’s Ratable Share (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount, provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Agent (or any such sub-agent) in its capacity as such, or against any Related Party of any of the foregoing acting for the Agent (or any such sub-agent) in connection with such capacity.

(d)Without limiting the rights of indemnification of the Indemnified Parties set forth in this Agreement with respect to liabilities asserted by third parties, each party hereto also agrees not to assert any claim for special, indirect, consequential or punitive damages against the other parties hereto, or any Related Party of any party hereto, on any theory of liability, arising out of or otherwise relating to the Notes, this Agreement, any other Loan Document, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Loans. No Indemnified Party shall be liable for any damages arising from the use by unintended recipients of any information or other materials distributed by it through telecommunications, electronic or other information transmission systems (including Intralinks, SyndTrak or similar systems) in connection with this Agreement or the other Loan Documents, provided that such indemnity shall not, as to any Indemnified Party, be available to the extent such damages are found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct.

(e)If any payment of principal of, or Conversion of, any Eurodollar Rate Loan is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such Loan, as a result of a payment or Conversion pursuant to Section 2.06(d) or (e), 2.08 or 2.10, acceleration of the maturity of the Loans pursuant to Section 6.01 or for any other reason, or by an Eligible Assignee to a Lender other than on the last day of the Interest Period for such Loan upon an assignment of rights and obligations under this Agreement pursuant to Section 8.07 as a result of a demand by the Borrower pursuant to Section 2.17, the Borrower shall, upon demand by such Lender (with a copy of such demand to the Agent), pay to the Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such payment or Conversion, including, without limitation, any loss (excluding loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Loan.

(f)Without prejudice to the survival of any other agreement of the Borrower hereunder, the agreements and obligations of the Borrower contained in Sections 2.09, 2.12 and 8.04 shall

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survive the payment in full of principal, interest and all other amounts payable hereunder and under the Notes.

Section 8.05Right of Set-off. Upon (i) the occurrence and during the continuance of any Event of Default and (ii) the making of the request or the granting of the consent specified by Section 6.01 to authorize the Agent to declare the Loans due and payable pursuant to the provisions of Section 6.01, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by Law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender or any such Affiliate to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower now or hereafter existing under this Agreement or any other Loan Document to such Lender, whether or not such Lender shall have made any demand under this Agreement or such Note and although such obligations may be contingent or unmatured or are owed to a branch or office of such Lender different from the branch or office holding such deposit or obligated on such indebtedness. Each Lender agrees promptly to notify the Borrower after any such set-off and application, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Lender may have.

Section 8.06Effectiveness; Binding Effect. Except as provided in Section 3.01, this Agreement shall become effective when it shall have been executed by the Borrower and the Agent and when the Agent shall have received counterparts hereof that, when taken together, bear the signatures of each of the other parties hereto and thereafter shall be binding upon and inure to the benefit of the Borrower, the Agent and each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of the Lenders (and any purported assignment without such consent shall be null and void).

Section 8.07Successors and Assigns.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Agent and each Lender (and any purported assignment or transfer without such consent shall be null and void) and no Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of subsection (b) of this Section, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (f) of this Section. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in subsection (d) of this Section and, to the extent expressly contemplated hereby, the Related Parties of each of the Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

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(b)Any Lender may at any time assign to one or more assignees (other than to an Ineligible Institution) all or a portion of its rights and obligations under this Agreement (including all or a portion of the Loans owing to it at such time); provided that any such assignment shall be subject to the following conditions:

(i)Minimum Amounts.

(A)in the case of an assignment of the entire principal amount of the assigning Lender’s Loans at the time owing to it or in the case of an assignment to a Lender, no minimum amount need be assigned; and

(B)in any case not described in subsection (b)(i)(A) of this Section, the aggregate outstanding principal amount of the Loans of the assigning Lender subject to each such assignment, determined as of the date the Assignment and Assumption with respect to which such assignment is delivered to the Agent or, if “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date, shall not be less than $5,000,000 unless each of the Agent and, so long as no Event of Default has occurred and is continuing, the Borrower otherwise consents (each such consent not to be unreasonably withheld or delayed).

(ii)Proportionate Amounts. Each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Loans assigned, and each such assignment shall be of a constant, and not a varying, percentage of all rights and obligations under this Agreement;

(iii)Required Consents. No consent shall be required for any assignment except to the extent required by subsection (b)(i)(B) of this Section and, in addition:

(A)the consent of the Borrower (such consent not to be unreasonably withheld or delayed; provided that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Agent within ten (10) Business Days after having received notice thereof) shall be required unless (1) an Event of Default has occurred and is continuing at the time of such assignment or (2) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; and

(B)the consent of the Agent (such consent not to be unreasonably withheld or delayed) shall be required if such assignment is to a Person that is not a Lender, an Affiliate of a Lender or an Approved Fund with respect to such Lender.

(iv)Assignment and Assumption. The parties to each assignment shall execute and deliver to the Agent an Assignment and Assumption, together with a processing and recordation fee in the amount of $3,500; provided, however, that no such fee shall be payable in the case of an assignment made at the request of the Borrower to an existing Lender. The assignee, if it is not a Lender, shall deliver to the Agent an Administrative Questionnaire.

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(v)No Assignment to Ineligible Institutions. No such assignment shall be made to any Ineligible Institution.

Subject to acceptance and recording thereof by the Agent pursuant to subsection (c) of this Section and notice thereof to the Borrower, from and after the effective date specified in each Assignment and Assumption, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.09, 2.12 and 8.04 with respect to facts and circumstances occurring prior to the effective date of such assignment. Upon request, the Borrower (at its expense) shall execute and deliver a Note to the assignee Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this subsection shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with subsection (d) of this Section.

(c)Register. The Agent shall maintain at the Agent’s Office a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, absent manifest error, and the Borrower, the Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d)Participations. Any Lender may at any time, without the consent of, or notice to, the Borrower or the Agent, sell participations to any Person (other than an Ineligible Institution) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of the Loans owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) the Borrower, the Agent and the Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement and (iv) no participant under any such participation shall have any right to approve any amendment or waiver of any provision of this Agreement or any Note, or any consent to any departure by the Borrower therefrom, except to the extent that such amendment, waiver or consent would reduce the principal of, or interest on, any Obligations or any fees or other amounts payable hereunder, in each case to the extent subject to such participation, or postpone any date fixed for any payment of principal of, or interest on, any Obligations or any fees or other amounts payable hereunder, in each case to the extent subject to such participation.

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Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, waiver or other modification addressing the matters set forth in clause (iv) above to the extent subject to such participation. Subject to subsection (e) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.09, 2.12 and 8.04(e) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section. To the extent permitted by Law, each Participant also shall be entitled to the benefits of Section 8.05 as though it were a Lender, provided such Participant agrees to be subject to Section 2.13 as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as an agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any Loans or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such Loan or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Agent (in its capacity as Agent) shall have no responsibility for maintaining a Participant Register.

(e)Limitations upon Participant Rights. A Participant shall not be entitled to receive any greater payment under Section 2.09 or 2.12 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.12 unless the Borrower is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrower, to comply with Section 2.12(e) as though it were a Lender.

(f)Certain Pledges. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement (including under its Note, if any) to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

(g)The words “execution,” “signed,” “signature,” and words of like import in any Assignment and Assumption shall be deemed to include electronic signatures or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable Law, including the Federal Electronic

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Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state Laws based on the Uniform Electronic Transactions Act.

Section 8.08Confidentiality. Neither the Agent nor any Lender may disclose to any Person any confidential, proprietary or non-public information of the Borrower furnished to the Agent or the Lenders by the Borrower (such information being referred to collectively herein as the “Borrower Information”), except that each of the Agent and each of the Lenders may disclose Borrower Information (i) to its and its Affiliates’ employees, officers, directors, agents and advisors having a need to know in connection with this Agreement (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Borrower Information and instructed to keep such Borrower Information confidential on substantially the same terms as provided herein), (ii) to the extent requested by any regulatory authority or self regulatory body, (iii) to the extent required by applicable Laws or regulations or by any subpoena or similar legal process, (iv) to any other party to this Agreement, (v) in connection with the exercise of any remedies hereunder or any suit, action or proceeding relating to this Agreement or the enforcement of rights hereunder, (vi) subject to an agreement containing provisions substantially the same as those of this Section 8.08, (A) to any assignee or participant or prospective assignee or participant, (B) to any direct, indirect, actual or prospective counterparty (and its advisor) to any swap, derivative or securitization transaction related to the obligations under this Agreement and (C) to any credit insurance provider relating to the Borrower and its Obligations, (vii) to the extent such Borrower Information (A) is or becomes generally available to the public on a non-confidential basis other than as a result of a breach of this Section 8.08 by the Agent or such Lender or their Related Parties, or (B) is or becomes available to the Agent or such Lender on a nonconfidential basis from a source other than the Borrower (provided that the source of such information was not known by the recipient after inquiry to be bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to the Borrower or any other Person with respect to such information) and (viii) with the consent of the Borrower. The obligations under this Section 8.08 shall survive for two calendar years after the date of the termination of this Agreement.

Section 8.09Governing Law. This Agreement and the Notes shall be governed by, and construed in accordance with, the Laws of the State of New York.

Section 8.10Counterparts; Integration. This Agreement may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Delivery of an executed counterpart of a signature page of this Agreement by telecopy or other electronic imaging means shall be effective as delivery of a manually executed counterpart of this Agreement. This Agreement and the other Loan Documents constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof.

Section 8.11Jurisdiction, Etc.

(e)Each of the parties hereto hereby submits to the exclusive jurisdiction of any New York State court or federal court of the United States of America sitting in the Borough of Manhattan in New York City, and any appellate court from any thereof, in any action or proceeding arising out

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of or relating to this Agreement or the other Loan Documents, or for recognition or enforcement of any judgment, and each of the parties hereto hereby agrees that all claims in respect of any such action or proceeding may be heard and determined in any such New York State court or, to the extent permitted by Law, in such federal court. Except to the extent expressly set forth in the preceding sentence, nothing in this Agreement shall affect any right that any party may otherwise have to bring any action or proceeding relating to this Agreement or the Notes in the courts of any jurisdiction.

(f)Each of the parties hereto irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection that it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the Notes in any New York State court or federal court of the United States of America sitting in the Borough of Manhattan in New York City, and any appellate court from any thereof. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by Law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

Section 8.12Payments Set Aside. To the extent that any payment by or on behalf of the Borrower is made to the Agent or any Lender, or the Agent or any Lender exercises its right of setoff, and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by the Agent or such Lender in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding under any Debtor Relief Law or otherwise, then (a) to the extent of such recovery, the obligation or part thereof originally intended to be satisfied shall be revived and continued in full force and effect as if such payment had not been made or such setoff had not occurred, and (b) each Lender severally agrees to pay to the Agent upon demand its applicable share (without duplication) of any amount so recovered from or repaid by the Agent, plus interest thereon from the date of such demand to the date such payment is made at a rate per annum equal to the Federal Funds Rate from time to time in effect. The obligations of the Lenders under clause (b) of the preceding sentence shall survive the payment in full of the Obligations and the termination of this Agreement.

Section 8.13Patriot Act. The Agent and each Lender hereby notifies the Borrower that pursuant to the requirements of the PATRIOT Act, it is required to obtain, verify and record information that identifies each borrower (including the Borrower), guarantor or grantor (the “Loan Parties”), which information includes the name and address of each Loan Party and other information that will allow such Lender to identify such Loan Party in accordance with the PATRIOT Act. The Borrower shall provide, to the extent commercially reasonable, such information and take such actions as are reasonably requested by the Agent or any Lender in order to assist the Agent and such Lender in maintaining compliance with the PATRIOT Act.

Section 8.14Waiver of Jury Trial. EACH OF THE BORROWER, THE AGENT AND THE LENDERS HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE NOTES OR ANY OTHER LOAN DOCUMENT OR THE ACTIONS OF THE BORROWER, THE AGENT

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OR ANY LENDER IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE OR ENFORCEMENT THEREOF.

Section 8.15No Advisory or Fiduciary Responsibility. In connection with all aspects of each transaction contemplated hereby, the Borrower acknowledges and agrees that: (i) the credit facilities provided for hereunder and any related arranging or other services in connection therewith (including in connection with any amendment, waiver or other modification hereof or of any other Loan Document) are an arm’s-length commercial transaction between the Borrower, on the one hand, and the Agent, each of the Lenders and each of the Arrangers, on the other hand, and the Borrower is capable of evaluating and understanding and understands and accepts the terms, risks and conditions of the transactions contemplated hereby and by the other Loan Documents (including any amendment, waiver or other modification hereof or thereof); (ii) in connection with the process leading to such transaction, each of the Agent, the Lenders and the Arrangers is and has been acting solely as a principal and is not the financial advisor, agent or fiduciary, for the Borrower or any of its Affiliates, stockholders, creditors or employees or any other Person; (iii) neither the Agent nor any Lender or Arranger has assumed or will assume an advisory, agency or fiduciary responsibility in favor of the Borrower with respect to any of the transactions contemplated hereby or the process leading thereto, including with respect to any amendment, waiver or other modification hereof or of any other Loan Document (irrespective of whether the Agent or any Lender or Arranger has advised or is currently advising the Borrower or any of its Affiliates on other matters) and neither the Agent nor any Lender or Arranger has any obligation to the Borrower with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Loan Documents; (iv) the Agent, each of the Lenders and the Arrangers and their respective Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its Affiliates, and neither the Agent nor any Lender or Arranger has any obligation to disclose any of such interests by virtue of any advisory, agency or fiduciary relationship; and (v) the Agent and each Lender and Arranger have not provided and will not provide any legal, accounting, regulatory or tax advice with respect to any of the transactions contemplated hereby (including any amendment, waiver or other modification hereof or of any other Loan Document) and the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate. The Borrower hereby waives and releases, to the fullest extent permitted by Law, any claims that it may have against the Agent and each Lender and Arranger with respect to any breach or alleged breach of agency or fiduciary duty in connection with the Loan Documents.

Section 8.16Survival of Representations and Warranties. All representations and warranties made hereunder and in any other Loan Document or other document delivered pursuant hereto or thereto or in connection herewith or therewith shall survive the execution and delivery hereof and thereof. Such representations and warranties have been or will be relied upon by the Agent and each Lender, regardless of any investigation made by the Agent or any Lender or on their behalf, and shall continue in full force and effect as long as any Loan or any other Obligation hereunder shall remain unpaid or unsatisfied.

Section 8.17Severability. If any provision of this Agreement or the other Loan Documents is held to be illegal, invalid or unenforceable, (a) the legality, validity and enforceability of the remaining provisions of this Agreement and the other Loan Documents shall not be affected or

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impaired thereby and (b) the parties shall endeavor in good faith negotiations to replace the illegal, invalid or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the illegal, invalid or unenforceable provisions. The invalidity of a provision in a particular jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK; SIGNATURE PAGES FOLLOW]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

ARIZONA PUBLIC SERVICE COMPANY

By:/s/ Lee R. Nickloy

Name: Lee R. Nickloy

Title: Vice President and Treasurer

Signature Page to

Arizona Public Service Company Term Loan Agreement

ADMINISTRATIVE AGENT:	TORONTO DOMINION (TEXAS) LLC, as Agent
	By:/s/ Wallace Wong
	Name: Wallace Wong
	Title: Authorized Signatory

Signature Page to

Arizona Public Service Company Term Loan Agreement

LENDERS:	TD BANK, N.A., as a Lender
	By:/s/ David Perlman
	Name: David Perlman
	Title: Senior Vice President

Signature Page to

Arizona Public Service Company Term Loan Agreement

CITIBANK, N.A., as Syndication Agent and as a Lender

By:/s/ Yousuf Omar

Name: Yousuf Omar

Title: Director

Signature Page to

Arizona Public Service Company Term Loan Agreement

SCHEDULE 1.01

COMMITMENTS AND RATABLE SHARES

Lender	Commitment		Ratable Share
TD Bank, N.A.	$25,000,000		50%
Citibank, N.A.	$25,000,000		50%
TOTAL		$50,000,000	100%

Signature Page to

Arizona Public Service Company Term Loan Agreement

SCHEDULE 4.01(j)

SUBSIDIARIES

1. Bixco, Inc.

2. Axiom Power Solutions, Inc.

3. PWE Newco, Inc.

SCHEDULE 4.01(k)

EXISTING INDEBTEDNESS

1. Commercial Paper.

2. Issuance of $300,000,000 of 3.15% Notes due 2025 on May 19, 2015.

3. Irrevocable Stand Letter of Credit No.: 05B15707NYA, dated June 11, 2015, by and between Citigroup Energy Inc. and the Borrower in the amount of $30,000,000.

SCHEDULE 8.02

CERTAIN ADDRESSES FOR NOTICES

BORROWER:
	Arizona Public Service Company
	400 North 5th Street
	Mail Station 9040
	Phoenix, AZ 85004
	Attention:     Treasurer
	Telephone:    (602) 250-3300
	Telecopier:    (602) 250-3902
	Electronic: lee.nickloy@pinnaclewest.com

AGENT:
Notices relating to Borrowing requests or Interest Election Requests:
	Toronto Dominion (Texas) LLC
	31 W. 52nd Street
	New York, NY 10019
	Facsimile: (416) 982-5535
	Telephone:       (416) 982-3567
	Attention: Vice President
	Electronic:       TDSAgencyAdmin@tdsecurities.com
Notices other than with respect to Borrowing requests or Interest Election Requests:
	Toronto Dominion (Texas) LLC
	31 W. 52nd Street,
	New York, NY 10019
	Facsimile:       (212) 827-7770
	Telephone:       (212) 827-7546
	Attention: Vice President & Director
	Electronic:       Kursad.Ilgar@tdsecurities.com
With a copy to Administration Team:
	Toronto Dominion (Texas) LLC
	31 W. 52nd Street,
	New York, NY 10019
	Facsimile:       (416) 982-5535
	Telephone:       (416) 982-3567
	Attention: Vice President
	Electronic:     TDSAgencyAdmin@tdsecurities.com

EXHIBIT A - FORM OF

PROMISSORY NOTE

$_____________ June 26, 2015

FOR VALUE RECEIVED, the undersigned, ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation (the “Borrower”), HEREBY UNCONDITIONALLY PROMISES TO PAY to the order of _______________ (the “Lender”) or its registered assigns, without offset or counterclaim, in lawful money of the United States of America and in same day funds, the principal amount of ________________________ DOLLARS ($___________), or, if less, the aggregate outstanding principal amount of the Loans made by the Lender to the Borrower pursuant to the Term Loan Agreement (as defined below). The principal amount hereof shall be paid in the amounts and on the dates specified in the Term Loan Agreement. The Borrower further agrees to pay interest in like money on the unpaid principal amount hereof from time to time outstanding at the rates and on the dates specified in the Term Loan Agreement. Capitalized terms used herein and not otherwise defined herein shall have the respective meanings assigned to such terms in the Term Loan Agreement.

Both principal and interest are payable to Toronto Dominion (Texas) LLC, as Agent, in accordance with Section 2.11 of the Term Loan Agreement, in same day funds. The Loans made by the Lender to the Borrower pursuant to the Term Loan Agreement, and all payments made on account of the principal amount thereof, shall be recorded by the Lender and, prior to any transfer hereof, endorsed on the grid attached hereto which is part of this Note, provided that the failure to so record any such Loan or any payment on account thereof shall not affect the payment obligations of the Borrower hereunder or under the Term Loan Agreement.

This Note (a) is one of the Notes referred to in the Term Loan Agreement, dated as of June 26, 2015 (as amended, restated, supplemented or otherwise modified from time to time, the “Term Loan Agreement”), among the Borrower, the Lenders named therein and from time to time party thereto, Citibank, N.A., as Syndication Agent, and Toronto Dominion (Texas) LLC, as Agent, (b) is subject to the provisions of the Term Loan Agreement and (c) is subject to optional and mandatory prepayment in whole or in part as provided in the Term Loan Agreement.

Upon the occurrence of any one or more Events of Default, all principal and all accrued interest then remaining unpaid on this Note shall become, or may be declared to be, immediately due and payable, as provided in the Term Loan Agreement.

All parties now and hereafter liable with respect to this Note, whether maker, principal, surety, guarantor, endorser or otherwise, hereby waive presentment, demand, protest, and all other notices of any kind. No failure to exercise, and no delay in exercising, any rights hereunder on the part of the holder hereof shall operate as a waiver of such rights.

This Note may not be transferred except pursuant to and in accordance with the terms and conditions of the Term Loan Agreement.

THIS NOTE SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

ARIZONA PUBLIC SERVICE COMPANY

By:_________________________________

      Name:

      Title:

LOANS AND PAYMENTS OF PRINCIPAL

Date Amount of Loan Amount of Principal Paid or Prepaid Unpaid Principal Balance Notation Made By

EXHIBIT B - FORM OF NOTICE OF INITIAL

BORROWING

Toronto Dominion (Texas) LLC, as Agent

for the Lenders parties

to the Term Loan Agreement

referred to below

31 W. 52^nd Street

New York, NY 10019

Facsimile No.: (416) 982-5535

Email: TDSAgencyAdmin@tdsecurities.com

Attention: Vice President

June [_], 2015

Ladies and Gentlemen:

The undersigned, Arizona Public Service Company, an Arizona corporation (the “Borrower”), refers to the draft dated June [_], 2015 of the Term Loan Agreement (document ID number: CHI 208126585v.[__]) (the “Term Loan Agreement”, the terms defined therein being used herein as therein defined) to be entered into among the Borrower, the Lenders named therein and from time to time party thereto, Citibank, N.A., as Syndication Agent, and Toronto Dominion (Texas) LLC, as Agent, and hereby gives you notice, irrevocably, pursuant to Section 2.02 of the Term Loan Agreement that the undersigned hereby requests the Initial Borrowing under the Term Loan Agreement, and in that connection sets forth below the information relating to the Initial Borrowing as required by Section 2.02(a) of the Term Loan Agreement:

(i) The Business Day of the Initial Borrowing is June [_], 2015.

(ii) The Type of Loans comprising the Initial Borrowing is Eurodollar Rate Loans.

(iii) The aggregate amount of the Initial Borrowing is $50,000,000.

(iv) The initial Interest Period for each Eurodollar Rate Loan made as part of the Initial Borrowing is one month.

The undersigned hereby certifies that the following statements will be true on the date of the Initial Borrowing:

(A)the representations and warranties contained in Section 4.01 of the Term Loan Agreement are true and correct, both before and after giving effect to the Initial Borrowing and to the application of the proceeds thereof, as though made on and as of such date;

(B)no event has occurred and is continuing, or would result from the Initial Borrowing or from the application of the proceeds therefrom, that constitutes a Default; and

(C)after giving effect to the Initial Borrowing, the Indebtedness of the Borrower does not exceed that permitted by (A) applicable resolutions of the Board of Directors of the Borrower or (B) applicable Laws of any Governmental Authority.

The Borrower hereby acknowledges and agrees as follows:

1. This Notice of Initial Borrowing is irrevocable.

2. The Borrower shall indemnify each Lender against any loss (excluding loss of anticipated profits), cost or expense incurred by such Lender as a result of any failure by the Borrower (a) to execute and deliver the Term Loan Agreement on or before June 26, 2015, (b) to fulfill the applicable conditions set forth in Article III of the Term Loan Agreement on June 26, 2015 or (c) to otherwise borrow the Eurodollar Rate Loans requested by the Borrower in this Notice of Initial Borrowing on June 26, 2015, in each case in accordance with Section 8.04(e) of the Term Loan Agreement (the terms of which Section are hereby incorporated by reference into this Notice of Initial Borrowing to the same extent and with the same force as if fully set forth herein).

3. The terms of paragraphs 1 and 2 above are not conditioned upon the execution and delivery by the Borrower, the Agent or the Lenders of the Term Loan Agreement.

This Notice of Initial Borrowing shall be governed by, and construed in accordance with, the laws of the State of New York.

Very truly yours,

ARIZONA PUBLIC SERVICE COMPANY

By:______________________________

Name:

Title:

EXHIBIT C - FORM OF

ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “Assignment and Assumption”) is dated as of the Effective Date set forth below and is entered into by and between [Insert name of Assignor] (the “Assignor”) and [Insert name of Assignee] (the “Assignee”). Capitalized terms used but not defined herein shall have the meanings given to them in the Term Loan Agreement identified below (as amended, restated, supplemented or otherwise modified from time to time, the “Term Loan Agreement”), receipt of a copy of which is hereby acknowledged by the Assignee. Annex 1 attached hereto (the “Standard Terms and Conditions”) is hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with the Standard Terms and Conditions and the Term Loan Agreement, as of the Effective Date referred to below, (i) all of the Assignor’s rights and obligations in its capacity as a Lender under the Term Loan Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of the Assignor under the Term Loan Agreement (including, without limitation, all Loans owing to the Assignor) and (ii) to the extent permitted to be assigned under applicable Law, all claims, suits, causes of action and any other right of the Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Term Loan Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at Law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned pursuant to clauses (i) and (ii) above being referred to herein collectively as, the “Assigned Interest”). Such sale and assignment is without recourse to the Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by the Assignor. Assignee shall deliver (if it is not already a Lender) to the Agent an Administrative Questionnaire.

1. Assignor: ________________________________

2. Assignee: ________________________________

[and is an Affiliate of [identify Lender] Select as applicable.]

3. Borrower: Arizona Public Service Company

4. Agent: Toronto Dominion (Texas) LLC, as the agent under the Term Loan Agreement

5. Term Loan Agreement: Term Loan Agreement, dated as of June 26, 2015, among the Borrower, the Lenders named therein and from time to time party thereto, Citibank, N.A., as Syndication Agent, and Toronto Dominion (Texas) LLC, as Agent.

6. Assigned Interest:

Aggregate Principal Amount of Loans of all Lenders	Principal Amount of Loans Assigned	Percentage Assigned of Aggregate Principal Amount of Loans Outstanding
$____________	$____________	___________%

[7. Trade Date:] To be completed if the Assignor and the Assignee intend that the minimum assignment amount is to be determined as of the Trade Date.

Effective Date: ________, 20___ [TO BE INSERTED BY AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR

[NAME OF ASSIGNOR]

By:

Name:

Title:

ASSIGNEE

[NAME OF ASSIGNEE]

By:

Name:

Title:

[Consented to and] To be added only if the consent of the Agent is required by the terms of the Term Loan Agreement. Accepted:

Toronto Dominion (Texas) LLC, as Agent

By:

Name:

Title:

[Consented to:] To be added only if the consent of the Borrower is required by the terms of the Term Loan Agreement.

ARIZONA PUBLIC SERVICE COMPANY

By:

Name:

Title:

ANNEX 1 TO ASSIGNMENT AND ASSUMPTION

STANDARD TERMS AND CONDITIONS FOR

ASSIGNMENT AND ASSUMPTION

1.Representations and Warranties.

1.1Assignor. The Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim and (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Term Loan Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document or (iv) the performance or observance by the Borrower of any of its obligations under any Loan Document.

1.2Assignee. The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Term Loan Agreement, (ii) it meets all the requirements to be an Eligible Assignee under Section 8.07 of the Term Loan Agreement (subject to such consents, if any, as may be required under Section 8.07 of the Term Loan Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Term Loan Agreement as a Lender thereunder and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Term Loan Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 4.01(e) or 5.01(h) of the Term Loan Agreement, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest, (vi) it has, independently and without reliance upon the Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest, and (vii) if it is a Foreign Lender, attached to this Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Term Loan Agreement, duly completed and executed by the Assignee; (b) appoints and authorizes the Agent to take such action as agent on its behalf and to exercise such powers under the Loan Documents as are delegated to the Agent by the terms thereof, together with such powers as are reasonably incidental thereto; and (c) agrees that (i) it will, independently and without reliance on the Agent, the Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2.Payments. From and after the Effective Date, the Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, fees and other amounts) to the Assignor for amounts which have accrued to but excluding the Effective Date and to the Assignee for amounts which have accrued from and after the Effective Date.

3.General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by facsimile or other electronic transmission shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the Law of the State of New York.

EXHIBIT D - FORM OF

INTEREST ELECTION REQUEST

[Date]

Toronto Dominion (Texas) LLC, as Agent

for the Lenders parties

to the Term Loan Agreement

referred to below

31 W. 52^nd Street

New York, NY 10019

Facsimile No.: (416) 982-5535

Email: TDSAgencyAdmin@tdsecurities.com

Attention: Vice President

Ladies and Gentlemen:

The undersigned, Arizona Public Service Company, an Arizona corporation (the “Borrower”), refers to the Term Loan Agreement, dated as of June 26, 2015 (as amended, restated, supplemented, or otherwise modified from time to time, the “Term Loan Agreement”, the terms defined therein and not otherwise defined herein being used herein as therein defined), among the Borrower, the Lenders named therein and from time to time party thereto, Citibank, N.A., as Syndication Agent, and Toronto Dominion (Texas) LLC, as Agent, and hereby gives you notice, irrevocably, that the undersigned requests a [Conversion] [continuation] of a Borrowing (the “Existing Borrowing”) under the Term Loan Agreement, and in that connection has set forth below the information relating to such [Conversion] [continuation] (the “Proposed [Conversion] [Continuation]”) as required by the definition of “Interest Period” contained in Section 1.01 of the Term Loan Agreement and/or Section 2.07 of the Term Loan Agreement, as applicable:

(i)The Business Day of the Proposed [Conversion] [Continuation] is _______ ___, 20__.

(ii)The Type of Loans comprising the Existing Borrowing is [Base Rate Loans] [Eurodollar Rate Loans having an Interest Period of ____ months(s)].

(iii)The aggregate amount of the Proposed [Conversion] [Continuation] is $______________.

(iv)The type of Loans to which such Existing Borrowing is proposed to be [Converted] [continued] is [Base Rate Loans] [Eurodollar Rate Loans].

[(v)The initial Interest Period for the Eurodollar Rate Loans made as part of the Proposed [Conversion] [Continuation] is _____months(s).]

The undersigned hereby certifies that the Borrower’s request for the Proposed [Conversion] [Continuation] is made in compliance with the definition of “Interest Period” contained in Section

1.01 of the Term Loan Agreement and with Sections 2.06 and 2.07 of the Term Loan Agreement. [The undersigned hereby acknowledges that the delivery of this Interest Election Request shall constitute a representation and warranty by the Borrower that, on the date of the Proposed [Conversion] [Continuation], no Event of Default has occurred and is continuing (unless the Borrower informs the Agent otherwise prior to the date of the Proposed [Conversion] [Continuation], in which case the Proposed [Conversion] [Continuation] shall not be made.]

Very truly yours,

ARIZONA PUBLIC SERVICE COMPANY

By:______________________________

Name:

Title:

EXHIBIT E - PREPAYMENT NOTICE

[____________], 20[__]

Toronto Dominion (Texas) LLC, as Administrative Agent

Address: 31 W. 52^nd Street

New York, NY 10019

Facsimile No.: (212) 827-7770

Email: Kursad.Ilgar@tdsecurities.com

Attention: Vice President & Director

with a copy to

Toronto Dominion (Texas) LLC, as Administrative Agent

Address: 31 W. 52^nd Street

New York, NY 10019

Facsimile No.: (416) 982-5535

Telephone No.: (416) 982-3567

Email: TDSAgencyAdmin@tdsecurities.com

Attention: Vice President

Ladies and Gentlemen:

Pursuant to Section 2.08(a) of that certain Term Loan Credit Agreement, dated as of June 26, 2015, by and among Arizona Public Service Company (the “Company”), the lenders party thereto, Toronto Dominion (Texas) LLC, as agent and Citibank, N.A., as syndication agent (as amended, restated, supplemented or otherwise modified prior to the date hereof, the “Term Loan Agreement”), we hereby notify you that on [_______________], 20[__] we intend to repay [an aggregate principal amount of [Eurodollar Rate][Base Rate] Loans equal to $[____________][, constituting Eurodollar Rate Loans having an Interest Period ending on [_________________], 20[__][all outstanding Loans under the Term Loan Agreement in full]. Such prepayments shall be accompanied by accrued and unpaid interest to the extent required by Section 2.08 of the Term Loan Agreement and any funding indemnification amounts required by Section 8.04(e) of the Term Loan Agreement.

ARIZONA PUBLIC SERVICE COMPANY

By:______________________________

Name:

Title:

EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Six Months Ended June 30,		Twelve Months Ended December 31,
	2015		2014		2013		2012		2011		2010
Earnings:
Income from continuing operations attributable to common shareholders	$	139,024	$	397,595	$	406,074	$	387,380	$	328,110	$	324,688
Income taxes	75,318		220,705		230,591		237,317		183,604		160,869
Fixed charges	100,580		208,226		206,089		219,437		246,462		248,664
Total earnings	$	314,922	$	826,526	$	842,754	$	844,134	$	758,176	$	734,221
Fixed Charges:
Interest expense	$	96,727	$	200,950	$	201,888	$	214,616	$	241,995	$	244,174
Estimated interest portion of annual rents	3,853		7,276		4,201		4,821		4,467		4,490
Total fixed charges	$	100,580	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Ratio of Earnings to Fixed Charges (rounded down)	3.13		3.96		4.08		3.84		3.07		2.95

EX-12.2

Exhibit 12.2

ARIZONA PUBLIC SERVICE COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Six Months Ended June 30,		Twelve Months Ended December 31,
	2015		2014		2013		2012		2011		2010
Earnings:
Income from continuing operations attributable to common shareholders	$	145,230	$	421,219	$	424,969	$	395,497	$	336,249	$	335,663
Income taxes	78,780		237,360		245,095		244,396		192,542		170,465
Fixed charges	99,056		204,198		202,457		214,227		238,286		234,184
Total earnings	$	323,066	$	862,777	$	872,521	$	854,120	$	767,077	$	740,312
Fixed Charges:
Interest charges	$	93,133	$	193,119	$	194,616	$	205,533	$	229,326	$	225,269
Amortization of debt discount	2,237		4,168		4,046		4,215		4,616		4,559
Estimated interest portion of annual rents	3,686		6,911		3,795		4,479		4,344		4,356
Total fixed charges	$	99,056	$	204,198	$	202,457	$	214,227	$	238,286	$	234,184
Ratio of Earnings to Fixed Charges (rounded down)	3.26		4.22		4.30		3.98		3.21		3.16

EX-12.3

Exhibit 12.3

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED

STOCK DIVIDEND REQUIREMENTS

(dollars in thousands)

	Six Months Ended June 30,		Twelve Months Ended December 31,
	2015		2014		2013		2012		2011		2010
Earnings:
Income from continuing operations attributable to common shareholders	$	139,024	$	397,595	$	406,074	$	387,380	$	328,110	$	324,688
Income taxes	75,318		220,705		230,591		237,317		183,604		160,869
Fixed charges	100,580		208,226		206,089		219,437		246,462		248,664
Total earnings	$	314,922	$	826,526	$	842,754	$	844,134	$	758,176	$	734,221
Fixed Charges:
Interest expense	$	96,727	$	200,950	$	201,888	$	214,616	$	241,995	$	244,174
Estimated interest portion of annual rents	3,853		7,276		4,201		4,821		4,467		4,490
Total fixed charges	$	100,580	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	214,342	$	618,300	$	636,665	$	624,697	$	511,714	$	485,557
Net income from continuing operations attributable to common shareholders	139,024		397,595		406,074		387,380		328,110		324,688
Ratio of income before income taxes to net income	1.54		1.56		1.57		1.61		1.56		1.50
Preferred stock dividends	—		—		—		—		—		—
Preferred stock dividend requirements — ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	100,580	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Preferred stock dividend requirements	—		—		—		—		—		—
Total	$	100,580	$	208,226	$	206,089	$	219,437	$	246,462	$	248,664
Ratio of Earnings to Fixed Charges (rounded down)	3.13		3.96		4.08		3.84		3.07		2.95

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Donald E. Brandt, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:    July 30, 2015

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James R. Hatfield, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:    July 30, 2015

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Donald E. Brandt, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:    July 30, 2015

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

1

EX-31.4

Exhibit 31.4

CERTIFICATION

I, James R. Hatfield, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:    July 30, 2015

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

1

EX-32.1

Exhibit 32.1

CERTIFICATION

OF

CHIEF EXECUTIVE OFFICER

AND

CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended June 30, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:      July 30, 2015

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the quarter ended June 30, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:     July 30, 2015

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

OF

CHIEF EXECUTIVE OFFICER

AND

CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended June 30, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:      July 30, 2015

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the quarter ended June 30, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:      July 30, 2015

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

XML

Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 3,669	$ 3,415
Fair Value	3,943	3,839
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	125	125
Fair Value	125	125
Arizona Public Service Company
Estimated fair value of long-term debt, including current maturities
Carrying Amount	3,544	3,290
Fair Value	$ 3,818	$ 3,714

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Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)				3 Months Ended	6 Months Ended
	Jun. 01, 2015 USD ($)	Mar. 11, 2015 USD ($)	Aug. 18, 2014 USD ($)	Jun. 30, 2015 USD ($) power_plant	Jun. 30, 2015 USD ($) power_plant	Dec. 31, 1986 Trust
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount		$ 42,000,000	$ 57,400,000
Arizona Public Service Company
Commitments and Contingencies
Maximum insurance against public liability per occurrence for a nuclear incident					$ 13,400,000,000
Maximum available nuclear liability insurance					375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program					12,980,000,000
Maximum retrospective premium assessment per reactor for each nuclear liability incident					127,300,000
Annual limit per incident with respect to maximum retrospective premium assessment					$ 19,000,000
Number of VIE lessor trusts				3	3	3
Maximum potential retrospective assessment per incident of APS					$ 111,000,000
Annual payment limitation with respect to maximum potential retrospective premium assessment					16,500,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde					2,750,000,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment					23,100,000
Collateral assurance provided based on rating triggers					$ 61,700,000
Period to provide collateral assurance based on rating triggers					20 days
Arizona Public Service Company | Gas Generation Projects
Commitments and Contingencies
Increase in contractual obligations				$ 170,000,000
Contractual Obligations
2015				26,000,000	$ 26,000,000
2016				89,000,000	89,000,000
2017				46,000,000	46,000,000
2018				$ 9,000,000	$ 9,000,000
Arizona Public Service Company | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount		$ 12,200,000	$ 16,700,000
Arizona Public Service Company | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | Regulatory Liability
Commitments and Contingencies
Proceeds from legal settlements	$ 12,200,000

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Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) $ in Thousands		3 Months Ended		6 Months Ended
	Jul. 07, 2014 Lease	Jun. 30, 2015 USD ($) power_plant	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($) power_plant	Jun. 30, 2014 USD ($)	Dec. 31, 1986 Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts		$ 4,605	$ 8,926	$ 9,210	$ 17,851
Arizona Public Service Company
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts		3		3		3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts		$ 4,605	8,926	$ 9,210	17,851
Arizona Public Service Company | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts		$ 5,000	$ 9,000	9,000	$ 18,000
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events				114,000
VIE debt to be assumed upon the occurrence of certain unlikely events				1,000
Arizona Public Service Company | Consolidation of VIEs | Through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease	1
Arizona Public Service Company | Consolidation of VIEs | Through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease	2
Arizona Public Service Company | Consolidation of VIEs | 2015
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments				49,000
Arizona Public Service Company | Consolidation of VIEs | Period 2016 through 2023
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments				23,000
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments				$ 16,000
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033 | Maximum
Palo Verde Sale Leaseback Variable Interest Entities
Lease period				2 years

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Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) $ in Millions				6 Months Ended
	Jun. 24, 2015 USD ($) power_plant	Aug. 06, 2013 Defendant	Sep. 08, 2011 kV Customer	Jun. 30, 2015 USD ($)
Arizona Public Service Company
Loss Contingencies [Line Items]
Capacity of transmission line that tripped out of service (in kV) | kV			500
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost			10 minutes
Number of customers losing service in Yuma area | Customer			69,700
Arizona Public Service Company | Contaminated groundwater wells
Loss Contingencies [Line Items]
Costs related to investigation and study under Superfund site				$ 2.0
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant		24
Arizona Public Service Company | Clean Air Act Citizen Lawsuit
Loss Contingencies [Line Items]
Public comment period	30 days
Number of power plants in lawsuit | power_plant	2
Litigation settlement percent	15.00%
Four Corners | Clean Air Act Citizen Lawsuit
Loss Contingencies [Line Items]
Civil penalty amount	$ 1.5
Environmental mitigation project cost	$ 6.2

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Income Taxes (Details) - USD ($)		6 Months Ended
	Sep. 13, 2013	Jun. 30, 2015
Income Taxes
Increase (decrease) in deferred income taxes due to adoption of regulations	$ 82,000,000
Consolidation of VIEs
Income Taxes
Income tax expense associates with the VIE's		$ 0

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

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

The following table presents the fair value at June 30, 2015, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at June 30, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	16		$	30		$	(13	)	(b)	$	33
Nuclear decommissioning trust:
U.S. commingled equity funds	—		314			—			—				314
Cash and cash equivalent funds	—		11			—			(4		)	(c)	7
Fixed income securities:
U.S. Treasury	93		2			—			—				95
Corporate debt	—		116			—			—				116
Mortgage-backed securities	—		87			—			—				87
Municipal bonds	—		86			—			—				86
Other	—		19			—			—				19
Subtotal nuclear decommissioning trust	93		635			—			(4		)		724
Total	$	93	$	651		$	30		$	(17	)		$	757
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(103	)	$	(73	)	$	28		(b)	$	(148	)

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

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

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

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

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at December 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	33		$	(23	)	(b)	$	31
Nuclear decommissioning trust:
U.S. commingled equity funds	—		310			—			—				310
Fixed income securities:
U.S. Treasury	119		—			—			—				119
Cash and cash equivalent funds	—		11			—			(7		)	(c)	4
Corporate debt	—		109			—			—				109
Mortgage-backed securities	—		89			—			—				89
Municipal bonds	—		69			—			—				69
Other	—		14			—			—				14
Subtotal nuclear decommissioning trust	119		602			—			(7		)		714
Total	$	119	$	623		$	33		$	(30	)		$	745
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(95	)	$	(74	)	$	59		(b)	$	(110	)

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

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

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

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

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2015 and December 31, 2014:

	June 30, 2015 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	28	$	57	Discounted cash flows	Electricity forward price (per MWh)	$21.07 - $67.74	$	31.46
Option Contracts (b)	—		12		Option model	Electricity forward price (per MWh)	$32.85 - $67.74	$	46.13
						Electricity price volatilities	26% - 115%	68		%
						Natural gas price volatilities	27% - 42%	31		%
Natural Gas:
Forward Contracts (a)	2		4		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.69 - $3.61	$	3.23
Total	$	30	$	73

(a) Includes swaps and physical and financial contracts.

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

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

(a) Includes swaps and physical and financial contracts.

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

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

The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2015 and 2014 (dollars in millions):

	Three Months Ended   June 30,						Six Months Ended   June 30,
Commodity Contracts	2015			2014			2015			2014
Net derivative balance at beginning of period	$	(49	)	$	(49	)	$	(41	)	$	(49	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	6			3			(5		)	6
Settlements	5			4			5			5
Transfers into Level 3 from Level 2	(4		)	1			(4		)	(2		)
Transfers from Level 3 into Level 2	(1		)	—			2			(1		)
Net derivative balance at end of period	$	(43	)	$	(41	)	$	(43	)	$	(41	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

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Other Income and Other Expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Other income:
Interest income	$ 184	$ 495	$ 294	$ 746
Miscellaneous	(9)	2,286	116	4,402
Total other income	175	2,781	410	5,148
Other expense:
Non-operating costs	(1,952)	(2,620)	(4,200)	(4,992)
Investment losses — net	(650)	(105)	(1,145)	(246)
Miscellaneous	(7)	2,217	(1,550)	46
Total other expense	(2,609)	(508)	(6,895)	(5,192)
Arizona Public Service Company
Other income:
Interest income	6	417	73	554
Gain on disposition of property	478	328	685	645
Miscellaneous	226	2,476	591	4,784
Total other income	710	3,221	1,349	5,983
Other expense:
Non-operating costs	(1,878)	(2,868)	(4,395)	(5,455)
Loss on disposition of property	(251)	(285)	(894)	(468)
Miscellaneous	(320)	1,676	(2,514)	(610)
Total other expense	$ (2,449)	$ (1,477)	$ (7,803)	$ (6,533)

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Consolidation and Nature of Operations (Tables)

6 Months Ended

Jun. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of supplemental cash flow information

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

	Six Months Ended   June 30,
	2015		2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$	1,834	$	(131,154	)
Interest, net of amounts capitalized	84,008		90,707
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	38,985	$	19,668
Dividends accrued but not yet paid	65,933		62,656

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Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - 6 months ended Jun. 30, 2015 - Commodity Contracts MMcf in Thousands	GWh MMcf
Outstanding gross notional amount of derivatives
Power | GWh	3,808
Gas	188

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Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Detail of regulatory assets
Regulatory assets, current	$ 135,000	$ 138,000
Regulatory assets, non-current	1,081,113	1,054,087
Pension benefits
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	505,000	485,000
Income taxes — allowance for funds used during construction (AFUDC) equity
Detail of regulatory assets
Regulatory assets, current	5,000	5,000
Regulatory assets, non-current	122,000	118,000
Deferred fuel and purchased power — mark-to-market (Note 7)
Detail of regulatory assets
Regulatory assets, current	53,000	51,000
Regulatory assets, non-current	62,000	46,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000	9,000
Regulatory assets, non-current	0	5,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	6,000	7,000
Palo Verde VIEs (Note 6)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	26,000	35,000
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	36,000	34,000
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	0	7,000
Regulatory assets, non-current	0	0
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	2,000	2,000
Regulatory assets, non-current	13,000	14,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000	1,000
Regulatory assets, non-current	16,000	16,000
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	2,000	2,000
Regulatory assets, non-current	46,000	46,000
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	0	4,000
Regulatory assets, non-current	0	0
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	7,000	7,000
Regulatory assets, non-current	67,000	70,000
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	45,000	38,000
Regulatory assets, non-current	0	0
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	10,000	10,000
Regulatory assets, non-current	131,000	136,000
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	40,000	30,000
Other
Detail of regulatory assets
Regulatory assets, current	1,000	2,000
Regulatory assets, non-current	11,000	12,000
Arizona Public Service Company
Detail of regulatory assets
Regulatory assets, non-current	$ 1,081,113	$ 1,054,087

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Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$ 1,834	$ (131,154)
Interest, net of amounts capitalized	84,008	90,707
Significant non-cash investing and financing activities:
Accrued capital expenditures	38,985	19,668
Dividends accrued but not yet paid	$ 65,933	$ 62,656

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Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Commodity Contracts
Assets
Gross Recognized Derivatives	$ 46,045	$ 53,372
Amounts Offset	(17,712)	(22,317)
Net Recognized Derivatives	28,333	31,055
Other	4,902	350
Amount Reported on Balance Sheet	33,235	31,405
Liabilities
Gross Recognized Derivatives	(175,678)	(169,052)
Amounts Offset	35,412	66,217
Net Recognized Derivatives	(140,266)	(102,835)
Other	(8,096)	(7,443)
Amount Reported on Balance Sheet	(148,362)	(110,278)
Assets and Liabilities
Gross Recognized Derivatives	(129,633)	(115,680)
Amounts Offset	17,700	43,900
Net Recognized Derivatives	(111,933)	(71,780)
Other	(3,194)	(7,093)
Amount Reported on Balance Sheet	(115,127)	(78,873)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	25,485	28,562
Amounts Offset	(12,925)	(15,127)
Net Recognized Derivatives	12,560	13,435
Other	2,162	350
Amount Reported on Balance Sheet	14,722	13,785
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	20,560	24,810
Amounts Offset	(4,787)	(7,190)
Net Recognized Derivatives	15,773	17,620
Other	2,740	0
Amount Reported on Balance Sheet	18,513	17,620
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(83,203)	(86,062)
Amounts Offset	30,626	33,829
Net Recognized Derivatives	(52,577)	(52,233)
Other	(8,096)	(7,443)
Amount Reported on Balance Sheet	(60,673)	(59,676)
Assets and Liabilities
Amounts Offset		43,900
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(92,475)	(82,990)
Amounts Offset	4,786	32,388
Net Recognized Derivatives	(87,689)	(50,602)
Other	0	0
Amount Reported on Balance Sheet	(87,689)	(50,602)
Designated as Hedging Instruments
Liabilities
Gross Recognized Derivatives	$ (4,000)	$ (4,000)

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Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net derivative beginning balance	$ (49,000)	$ (49,000)	$ (41,000)	$ (49,000)
Deferred as a regulatory asset or liability	6,000	3,000	(5,000)	6,000
Settlements	5,000	4,000	5,000	5,000
Transfers into Level 3 from Level 2	(4,000)	1,000	(4,000)	(2,000)
Transfers from Level 3 into Level 2	(1,000)	0	2,000	(1,000)
Net derivative ending balance	(43,000)	(41,000)	(43,000)	(41,000)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0	$ 0	$ 0

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Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$ 119,320	$ 121,255
Current maturities of long-term debt	102,723	383,570
Equity — Noncontrolling interests	132,807	151,609
Arizona Public Service Company
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	119,320	121,255
Current maturities of long-term debt	102,723	383,570
Equity — Noncontrolling interests	132,807	151,609
Arizona Public Service Company | Consolidation of VIEs
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	119,000	121,000
Current maturities of long-term debt	1,000	13,000
Equity — Noncontrolling interests	$ 133,000	$ 152,000

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Consolidation and Nature of Operations

6 Months Ended

Jun. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation and Nature of Operations

Consolidation and Nature of Operations

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

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

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

Supplemental Cash Flow Information

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

	Six Months Ended   June 30,
	2015		2014
Cash paid (received) during the period for:
Income taxes, net of refunds	$	1,834	$	(131,154	)
Interest, net of amounts capitalized	84,008		90,707
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	38,985	$	19,668
Dividends accrued but not yet paid	65,933		62,656

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Nuclear Decommissioning Trusts (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Nuclear decommissioning trust fund assets
Fair Value	$ 723,582		$ 723,582		$ 713,866
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities			225,779	$ 199,224
Fair value of fixed income securities, summarized by contractual maturities
Total	723,582		723,582		713,866
Arizona Public Service Company
Nuclear decommissioning trust fund assets
Fair Value	723,582		723,582		713,866
Unrealized Gains	173,000		173,000		176,000
Unrealized Losses	(3,000)		(3,000)		(1,000)
Net payables for securities purchases	(4,000)		(4,000)		(7,000)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	1,000	$ 1,000	2,000	2,000
Realized losses	(1,000)	(1,000)	(2,000)	(3,000)
Proceeds from the sale of securities	110,000	$ 96,000	225,779	$ 199,224
Fair value of fixed income securities, summarized by contractual maturities
Total	723,582		723,582		713,866
Arizona Public Service Company | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	314,000		314,000		310,000
Unrealized Gains	160,000		160,000		159,000
Fair value of fixed income securities, summarized by contractual maturities
Total	314,000		314,000		310,000
Arizona Public Service Company | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	414,000		414,000		411,000
Unrealized Gains	13,000		13,000		17,000
Unrealized Losses	(3,000)		(3,000)		(1,000)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	13,000		13,000
1 year - 5 years	111,000		111,000
5 years - 10 years	123,000		123,000
Greater than 10 years	167,000		167,000
Total	$ 414,000		$ 414,000		$ 411,000

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Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Detail of regulatory liabilities
Regulatory liabilities, current	$ 152,000	$ 131,000
Regulatory liabilities, non-current	1,016,991	1,051,196
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	44,000	31,000
Regulatory liabilities, non-current	245,000	273,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	272,000	296,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	29,000	25,000
Regulatory liabilities, non-current	20,000	23,000
Income taxes — change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	1,000	0
Regulatory liabilities, non-current	71,000	72,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	3,000	5,000
Regulatory liabilities, non-current	68,000	66,000
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,000	2,000
Regulatory liabilities, non-current	7,000	8,000
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	3,000	4,000
Regulatory liabilities, non-current	92,000	93,000
Deferred fuel and purchased power
Detail of regulatory liabilities
Regulatory liabilities, current	16,000	0
Regulatory liabilities, non-current	0	0
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	8,000	31,000
Regulatory liabilities, non-current	27,000	0
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	33,000	32,000
Regulatory liabilities, non-current	189,000	199,000
Other
Detail of regulatory liabilities
Regulatory liabilities, current	13,000	1,000
Regulatory liabilities, non-current	$ 26,000	$ 21,000

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2015

Variable Interest Entities [Abstract]

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

Our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):

	June 30, 2015		December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	119	$	121
Current maturities of long-term debt	1		13
Equity — Noncontrolling interests	133		152

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Retirement Plans and Other Benefits (Tables)

6 Months Ended

Jun. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)

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

	Pension Benefits												Other Benefits
	Three Months Ended   June 30,						Six Months Ended   June 30,						Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost — benefits earned during the period	$	14		$	12		$	30		$	27		$	4		$	5		$	8		$	9
Interest cost on benefit obligation	31			33			62			65			7			11			14			23
Expected return on plan assets	(45		)	(39		)	(90		)	(79		)	(9		)	(13		)	(18		)	(25		)
Amortization of:
Prior service cost	—			—			—			—			(9		)	—			(19		)	—
Net actuarial loss	8			3			16			5			—			—			2			—
Net periodic benefit cost	$	8		$	9		$	18		$	18		$	(7	)	$	3		$	(13	)	$	7
Portion of cost charged to expense	$	5		$	5		$	11		$	11		$	(2	)	$	3		$	(4	)	$	5

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Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions		6 Months Ended
	May. 23, 2013 USD ($)	Jun. 30, 2015 USD ($) Letter_of_credit
Four Corners | New Mexico Tax Matter
Environmental Matters
Coal severance surtax, penalty, and interest	$ 30
Arizona Public Service Company | Letters of Credit Expiring in 2016
Financial Assurances
Number of letters of credit expiring | Letter_of_credit		2
Arizona Public Service Company | Letters of Credit Expiring in 2017
Financial Assurances
Number of letters of credit expiring | Letter_of_credit		1
Arizona Public Service Company | Letter of Credit
Financial Assurances
Outstanding letters of credit		$ 76
Arizona Public Service Company | Equity Lessors in Palo Verde sale leaseback transactions
Financial Assurances
Outstanding letters of credit		20
Arizona Public Service Company | Natural gas tolling contract obligations
Financial Assurances
Outstanding letters of credit		$ 35
Arizona Public Service Company | Four Corners | New Mexico Tax Matter
Environmental Matters
Share of the assessment	$ 12
Regional Haze Rules | Arizona Public Service Company | Four Corners Units 4 and 5
Environmental Matters
Percentage of share of cost of control		63.00%
Expected environmental cost		$ 400
Regional Haze Rules | Arizona Public Service Company | Natural gas tolling contract obligations | Four Corners Units 4 and 5
Environmental Matters
Additional percentage share of cost of control		7.00%
Regional Haze Rules | Arizona Public Service Company | Four Corners | Four Corners Units 4 and 5
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate		$ 45
Regional Haze Rules | Arizona Public Service Company | Navajo Plant
Environmental Matters
Expected environmental cost		200
Regional Haze Rules | Arizona Public Service Company | Cholla
Environmental Matters
Expected environmental cost		200
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Navajo Plant
Environmental Matters
Expected environmental cost		1
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Cholla Units 2 And 3
Environmental Matters
Expected environmental cost		130
Coal combustion waste | Arizona Public Service Company | Four Corners
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate		15
Coal combustion waste | Arizona Public Service Company | Navajo Plant
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate		1
Coal combustion waste | Arizona Public Service Company | Cholla
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate		$ 85

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Retirement Plans and Other Benefits - Narrative (Details) - USD ($)	1 Months Ended	3 Months Ended		6 Months Ended
	Jul. 31, 2012	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Regulatory Assets
Regulatory asset amortization period	3 years
Amortization of regulatory asset		$ 2,000,000	$ 2,000,000	$ 4,000,000	$ 4,000,000
Pension Benefits
Contributions
Voluntary employer contributions to pension plan				80,000,000
Minimum employer contributions for the next three years				0
Maximum employer contributions for the next three years				300,000,000
Other Benefits
Other Postretirement Benefit Plan Remeasurement
Other postretirement plan benefit remeasurement, amount seeking approval to move to separate account to Pay Union employee medical costs				100,000,000
Contributions
2015				1,000,000
2016				1,000,000
2017				1,000,000
Maximum | Pension Benefits
Contributions
2015				100,000,000
2016				100,000,000
2017				$ 100,000,000

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Derivative Accounting (Tables)

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

As of June 30, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	3,808	GWh
Gas	188	Billion cubic feet

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

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   June 30,						Six Months Ended   June 30,
Commodity Contracts		2015			2014			2015			2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	41		$	66		$	(286	)	$	243
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(1,430		)	(3,216		)	(3,773		)	(7,654		)

(a) During the three and six months ended June 30, 2015 and 2014, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

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

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   June 30,					Six Months Ended June 30,
Commodity Contracts		2015			2014		2015			2014
Net gain (loss) recognized in income	Operating revenues (a)	$	(66	)	$	155	$	(114	)	$	63
Net gain (loss) recognized in income	Fuel and purchased power (a)	10,613			4,805		(34,190		)	22,912
Total		$	10,547		$	4,960	$	(34,304	)	$	22,975

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

Schedule of offsetting assets

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, 2015 and December 31, 2014.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2015: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance  Sheet
Current assets	$	25,485		$	(12,925	)	$	12,560		$	2,162		$	14,722
Investments and other assets	20,560			(4,787		)	15,773			2,740			18,513
Total assets	46,045			(17,712		)	28,333			4,902			33,235
Current liabilities	(83,203		)	30,626			(52,577		)	(8,096		)	(60,673		)
Deferred credits and other	(92,475		)	4,786			(87,689		)	—			(87,689		)
Total liabilities	(175,678		)	35,412			(140,266		)	(8,096		)	(148,362		)
Total	$	(129,633	)	$	17,700		$	(111,933	)	$	(3,194	)	$	(115,127	)

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

(b) Includes cash collateral provided to counterparties of $17,700.

(c) Represents cash collateral, cash margin and option premiums that are not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $8,096, cash margin provided to counterparties of $2,162 and option premiums of $2,740.

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

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

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

(c) Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,443, and cash margin provided to counterparties of $350.

Schedule of offsetting liabilities

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, 2015 and December 31, 2014.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2015: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance  Sheet
Current assets	$	25,485		$	(12,925	)	$	12,560		$	2,162		$	14,722
Investments and other assets	20,560			(4,787		)	15,773			2,740			18,513
Total assets	46,045			(17,712		)	28,333			4,902			33,235
Current liabilities	(83,203		)	30,626			(52,577		)	(8,096		)	(60,673		)
Deferred credits and other	(92,475		)	4,786			(87,689		)	—			(87,689		)
Total liabilities	(175,678		)	35,412			(140,266		)	(8,096		)	(148,362		)
Total	$	(129,633	)	$	17,700		$	(111,933	)	$	(3,194	)	$	(115,127	)

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

(b) Includes cash collateral provided to counterparties of $17,700.

(c) Represents cash collateral, cash margin and option premiums that are not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $8,096, cash margin provided to counterparties of $2,162 and option premiums of $2,740.

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

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

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

(c) Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,443, and cash margin provided to counterparties of $350.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2015 (dollars in millions):

	June 30, 2015
Aggregate fair value of derivative instruments in a net liability position	$	176
Cash collateral posted	18
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	89

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

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Other Income and Other Expense (Tables)

6 Months Ended

Jun. 30, 2015

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

Detail of other income and other expense

The following table provides detail of other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Other income:
Interest income	$	184		$	495		$	294		$	746
Miscellaneous	(9		)	2,286			116			4,402
Total other income	$	175		$	2,781		$	410		$	5,148
Other expense:
Non-operating costs	$	(1,952	)	$	(2,620	)	$	(4,200	)	$	(4,992	)
Investment losses — net	(650		)	(105		)	(1,145		)	(246		)
Miscellaneous	(7		)	2,217			(1,550		)	46
Total other expense	$	(2,609	)	$	(508	)	$	(6,895	)	$	(5,192	)

Arizona Public Service Company

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

Detail of other income and other expense

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Other income:
Interest income	$	6		$	417		$	73		$	554
Gain on disposition of property	478			328			685			645
Miscellaneous	226			2,476			591			4,784
Total other income	$	710		$	3,221		$	1,349		$	5,983
Other expense:
Non-operating costs (a)	$	(1,878	)	$	(2,868	)	$	(4,395	)	$	(5,455	)
Loss on disposition of property	(251		)	(285		)	(894		)	(468		)
Miscellaneous	(320		)	1,676			(2,514		)	(610		)
Total other expense	$	(2,449	)	$	(1,477	)	$	(7,803	)	$	(6,533	)

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

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) - USD ($) $ in Thousands		Total	Common Stock	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	Arizona Public Service Company	Arizona Public Service Company Common Stock	Arizona Public Service Company Additional Paid-in Capital	Arizona Public Service Company Retained Earnings	Arizona Public Service Company Accumulated Other Comprehensive Income (Loss)	Arizona Public Service Company Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2013			110,280,703	98,944					71,264,947
Beginning balance at Dec. 31, 2013		$ 4,340,460	$ 2,491,558	$ (4,308)	$ 1,785,273	$ (78,053)	$ 145,990	$ 4,454,874	$ 178,162	$ 2,379,696	$ 1,804,398	$ (53,372)	$ 145,990
Increase (Decrease) in Shareholders' Equity
Net income		166,075			148,224		17,851	172,285			154,434		17,851
Other comprehensive income		3,836				3,836		3,972				3,972
Dividends on common stock		(125,265)			(125,265)			(125,200)			(125,200)
Other								3			3
Issuance of common stock (in shares)			149,753
Issuance of common stock		8,506	$ 8,506
Purchase of treasury stock (in shares)	[1]			(82,474)
Purchase of treasury stock	[1]	(4,535)		$ (4,535)
Stock-based compensation and other (in shares)				157,594
Stock-based compensation and other		8,654		$ 8,654
Net capital activities by noncontrolling interests		(15,869)					(15,869)	(15,869)					(15,869)
Ending balance (in shares) at Jun. 30, 2014			110,430,456	23,824					71,264,947
Ending balance at Jun. 30, 2014		$ 4,381,862	$ 2,500,064	$ (189)	1,808,232	(74,217)	147,972	4,490,065	$ 178,162	2,379,696	1,833,635	(49,400)	147,972
Beginning balance (in shares) at Dec. 31, 2014		110,649,762	110,649,762	78,400					71,264,947
Beginning balance at Dec. 31, 2014		$ 4,519,102	$ 2,512,970	$ (3,401)	1,926,065	(68,141)	151,609	4,629,852	$ 178,162	2,379,696	1,968,718	(48,333)	151,609
Increase (Decrease) in Shareholders' Equity
Net income		148,234			139,024		9,210	154,440			145,230		9,210
Other comprehensive income		2,541				2,541		2,682				2,682
Dividends on common stock		(131,833)			(131,833)			(131,800)			(131,800)
Other								2			2
Issuance of common stock (in shares)			215,268
Issuance of common stock		13,975	$ 13,975
Purchase of treasury stock (in shares)	[1]			(93,280)
Purchase of treasury stock	[1]	(6,096)		$ (6,096)
Stock-based compensation and other (in shares)				118,121
Stock-based compensation and other		7,732		$ 7,732
Net capital activities by noncontrolling interests		$ (28,012)					(28,012)	(28,012)					(28,012)
Ending balance (in shares) at Jun. 30, 2015		110,865,030	110,865,030	53,559					71,264,947
Ending balance at Jun. 30, 2015		$ 4,525,643	$ 2,526,945	$ (1,765)	$ 1,933,256	$ (65,600)	$ 132,807	$ 4,627,164	$ 178,162	$ 2,379,696	$ 1,982,150	$ (45,651)	$ 132,807

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

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

Schedule of earnings per weighted average common share outstanding

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2015 and 2014 (in thousands, except per share amounts):

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
Net income attributable to common shareholders	$	122,902	$	132,458	$	139,024	$	148,224
Weighted average common shares outstanding — basic	110,986		110,565		110,958		110,546
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	474		437		468		379
Weighted average common shares outstanding — diluted	111,460		111,002		111,426		110,925
Earnings per average common share attributable to common shareholders — basic	$	1.11	$	1.20	$	1.25	$	1.34
Earnings per average common share attributable to common shareholders — diluted	$	1.10	$	1.19	$	1.25	$	1.34

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Regulatory Matters (Details)												6 Months Ended
	Jun. 01, 2015 USD ($)	Apr. 02, 2015 USD ($) $ / kWh	Mar. 02, 2015 USD ($)	Feb. 01, 2015 $ / kWh	Jun. 01, 2014 USD ($)	Apr. 15, 2014 Customer MW	Mar. 01, 2014 USD ($)	Feb. 01, 2014 $ / kWh	Jan. 01, 2014 USD ($) $ / kWh	Jan. 06, 2012 USD ($) $ / kWh	Jun. 01, 2011 USD ($)	Jun. 30, 2015 USD ($) $ / kWh	Jun. 30, 2014 USD ($)	Jul. 01, 2015 USD ($)	Mar. 20, 2015 USD ($) project	Dec. 31, 2014 USD ($)	Jul. 01, 2014 USD ($)	Mar. 11, 2014 USD ($)	Jul. 12, 2013 USD ($)	Dec. 31, 2012 USD ($)	Jun. 01, 2012
Change in regulatory asset
Deferred fuel and purchased power costs-current period												$ (11,711,000)	$ (1,315,000)
Amounts charged to customers												(11,424,000)	(18,399,000)
APS
Change in regulatory asset
Deferred fuel and purchased power costs-current period												(11,711,000)	(1,315,000)
Amounts charged to customers												$ (11,424,000)	(18,399,000)
APS | Filing with the Arizona Corporation Commission | ACC | Retail rate case filing
Public Utilities, General Disclosures [Line Items]
Net retail rate increase											$ 95,500,000
Approximate percentage of increase in the average retail customer bill											6.60%
Settlement Agreement
Net change in base rates										$ 0
Non-fuel base rate increase										116,300,000
Fuel-related base rate decrease										$ 153,100,000
Current base fuel rate (in dollars per kWh) | $ / kWh										0.03757
Approved base fuel rate (in dollars per kWh) | $ / kWh										0.03207
Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates										$ 36,800,000
Authorized return on common equity (as a percent)										10.00%
Percentage of debt in capital structure										46.10%
Percentage of common equity in capital structure										53.90%
Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent)										25.00%
Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent)										50.00%
Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent)										75.00%
Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent)										100.00%
Elimination of the sharing provision of fuel and purchased power costs										9
Period to process the subsequent rate cases										12 months
ACC staff sufficiency findings, general period of time										30 days
APS | Filing with the Arizona Corporation Commission | ACC | Retail rate case filing | Maximum
Settlement Agreement
Annual cost recovery due to modifications to the Environmental Improvement Surcharge										$ 5,000,000
APS | RES | Cost Recovery Mechanisms | ACC
Settlement Agreement
Plan term												5 years
APS | 2014 RES | Cost Recovery Mechanisms | ACC
Settlement Agreement
Amount of proposed budget																			$ 143,000,000
APS | 2014 RES | AZ Sun Program | Filing with the Arizona Corporation Commission
Settlement Agreement
Request to build additional utility scale solar, capacity | MW						20
APS | 2014 RES | Alternative to AZ Sun Program | Filing with the Arizona Corporation Commission
Settlement Agreement
Request to build additional utility scale solar, capacity | MW						10
Additional capacity from APS-owned non AZ Sun projects, impacted customers | Customer						1,500
APS | 2014 RES | Alternative to AZ Sun Program, Phase 1 | Filing with the Arizona Corporation Commission
Settlement Agreement
Request to build additional utility scale solar, capacity | MW						8
APS | 2014 RES | Alternative to AZ Sun Program Phase 2 | Filing with the Arizona Corporation Commission
Settlement Agreement
Request to build additional utility scale solar, capacity | MW						2
APS | 2015 RES | Cost Recovery Mechanisms | ACC
Settlement Agreement
Amount of proposed budget																	$ 154,000,000
Amount of approved budget																$ 152,000,000
APS | 2016 RES | Cost Recovery Mechanisms | ACC
Settlement Agreement
Amount of proposed budget														$ 148,000,000
APS | 2013 DSMAC | Cost Recovery Mechanisms
Settlement Agreement
Amount of approved budget																		$ 68,900,000
APS | 2013 DSMAC | Cost Recovery Mechanisms | ACC
Settlement Agreement
Amount of proposed budget																				$ 87,600,000
Percentage of cumulative energy savings for current year																					5.00%
APS | 2014 DSMAC | Cost Recovery Mechanisms | ACC
Settlement Agreement
Amount of approved budget																		$ 68,900,000
APS | 2015 DSMAC | Cost Recovery Mechanisms | ACC
Settlement Agreement
Amount of proposed budget															$ 68,900,000
Number of resource savings projects | project															3
APS | 2016 DSMAC | Cost Recovery Mechanisms | ACC
Settlement Agreement
Amount of proposed budget	$ 68,900,000
Proposed rate reduction percentage	12.00%
APS | Power Supply Adjustor (PSA) | Cost Recovery Mechanisms | ACC
Change in regulatory asset
Beginning balance									$ 21,000,000			$ 7,000,000	21,000,000
Deferred fuel and purchased power costs-current period												(12,000,000)	(1,000,000)
Amounts charged to customers												(11,000,000)	(19,000,000)
Ending balance												$ (16,000,000)	$ 1,000,000
PSA rate (in dollars per kWh) | $ / kWh				0.000887
PSA rate for prior year (in dollars per kWh) | $ / kWh								0.001557
Forward component of increase in PSA (in dollars per kWh) | $ / kWh				0.001131
Historical component of increase in PSA (in dollars per kWh) | $ / kWh				(0.000244)
APS | Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters | Cost Recovery Mechanisms | FERC
Change in regulatory asset
Increase in annual wholesale transmission rates	$ 17,600,000				$ 5,900,000
APS | Lost Fixed Cost Recovery Mechanism
Change in regulatory asset
Percentage of retail revenues												1.00%
APS | Lost Fixed Cost Recovery Mechanism | Cost Recovery Mechanisms
Change in regulatory asset
Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh												0.031
Fixed costs recoverable per non-residential power lost (in dollars per kWh) | $ / kWh												0.023
Amount of adjustment approved representing prorated sales losses			$ 38,500,000				$ 25,300,000
APS | Net Metering | ACC
Change in regulatory asset
Charge on future customers who install rooftop solar panels (in dollars per kWh) | $ / kWh		0.70							0.70			0.70
Estimated monthly collection due to charge on future customers who install rooftop solar panels									$ 4.90
Proposed fixed grid access charge on new residential solar customers (in dollars per KWh) | $ / kWh		3.00
Estimated monthly collection due to charge on new residential solar customers		$ 21

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Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Millions	Jun. 30, 2015 USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	$ 176
Cash collateral posted	18
Additional cash collateral in the event credit-risk-related contingent features were fully triggered	$ 89

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
OPERATING REVENUES	$ 890,648	$ 906,264	$ 1,561,867	$ 1,592,515
OPERATING EXPENSES
Fuel and purchased power	281,477	290,854	504,714	540,640
Operations and maintenance	210,965	211,222	425,909	424,104
Depreciation and amortization	122,739	105,150	243,688	206,922
Taxes other than income taxes	43,032	44,004	86,248	89,849
Other expenses	462	921	1,651	1,717
Total	658,675	652,151	1,262,210	1,263,232
OPERATING INCOME	231,973	254,113	299,657	329,283
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	9,345	7,499	18,569	14,941
Other income (Note 9)	175	2,781	410	5,148
Other expense (Note 9)	(2,609)	(508)	(6,895)	(5,192)
Total	6,911	9,772	12,084	14,897
INTEREST EXPENSE
Interest charges	48,328	51,751	96,727	104,720
Allowance for borrowed funds used during construction	(4,322)	(3,790)	(8,538)	(7,560)
Total	44,006	47,961	88,189	97,160
INCOME BEFORE INCOME TAXES	194,878	215,924	223,552	247,020
INCOME TAXES	67,371	74,540	75,318	80,945
NET INCOME	127,507	141,384	148,234	166,075
Less: Net income attributable to noncontrolling interests (Note 6)	4,605	8,926	9,210	17,851
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 122,902	$ 132,458	$ 139,024	$ 148,224
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	110,986	110,565	110,958	110,546
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	111,460	111,002	111,426	110,925
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 1.11	$ 1.20	$ 1.25	$ 1.34
Net income attributable to common shareholders - diluted (in dollars per share)	1.10	1.19	1.25	1.34
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 1.19	$ 1.14	$ 1.19	$ 1.14
Arizona Public Service Company
ELECTRIC OPERATING REVENUES	$ 889,723	$ 905,578	$ 1,560,391	$ 1,591,123
OPERATING EXPENSES
Fuel and purchased power	281,477	290,854	504,714	540,640
Operations and maintenance	208,031	208,059	417,978	416,344
Depreciation and amortization	122,716	105,127	243,642	206,875
Income taxes	71,672	77,371	83,911	87,849
Taxes other than income taxes	43,123	43,773	86,109	89,386
Total	727,019	725,184	1,336,354	1,341,094
OPERATING INCOME	162,704	180,394	224,037	250,029
OTHER INCOME (DEDUCTIONS)
Income taxes	2,980	1,568	5,131	2,778
Allowance for equity funds used during construction	9,345	7,499	18,569	14,941
Other income (Note 9)	710	3,221	1,349	5,983
Other expense (Note 9)	(2,449)	(1,477)	(7,803)	(6,533)
Total	10,586	10,811	17,246	17,169
INTEREST EXPENSE
Interest on long-term debt	44,826	48,462	90,254	97,358
Interest on short-term borrowings	1,705	1,637	2,879	3,050
Debt discount, premium and expense	1,103	1,054	2,237	2,065
Allowance for borrowed funds used during construction	(4,311)	(3,790)	(8,527)	(7,560)
Total	43,323	47,363	86,843	94,913
NET INCOME	129,967	143,842	154,440	172,285
Less: Net income attributable to noncontrolling interests (Note 6)	4,605	8,926	9,210	17,851
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 125,362	$ 134,916	$ 145,230	$ 154,434

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Retirement Plans and Other Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Pension Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	$ 14	$ 12	$ 30	$ 27
Interest cost on benefit obligation	31	33	62	65
Expected return on plan assets	(45)	(39)	(90)	(79)
Amortization of:
Prior service cost	0	0	0	0
Net actuarial loss	8	3	16	5
Net periodic benefit cost	8	9	18	18
Portion of cost charged to expense	5	5	11	11
Other postretirement benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	4	5	8	9
Interest cost on benefit obligation	7	11	14	23
Expected return on plan assets	(9)	(13)	(18)	(25)
Amortization of:
Prior service cost	(9)	0	(19)	0
Net actuarial loss	0	0	2	0
Net periodic benefit cost	(7)	3	(13)	7
Portion of cost charged to expense	$ (2)	$ 3	$ (4)	$ 5

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares None in scaling factor is -9223372036854775296	Jun. 30, 2015	Dec. 31, 2014
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common stock, par value (in dollars per share)
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	110,865,030	110,649,762
Treasury stock at cost, shares	53,559	78,400

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Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Assets
Nuclear decommissioning trust	$ 723,582	$ 713,866
Total assets	30,000	33,000
Recurring
Assets
Derivative instruments, other	(13,000)	(23,000)
Derivative assets	33,000	31,000
Nuclear decommissioning trust, other	(4,000)	(7,000)
Nuclear decommissioning trust	724,000	714,000
Total, other	(17,000)	(30,000)
Total assets	757,000	745,000
Liabilities
Derivative instruments, other	28,000	59,000
Derivative liability	(148,000)	(110,000)
Recurring | US commingled equity funds
Assets
Nuclear decommissioning trust	314,000	310,000
Recurring | U.S. Treasury
Assets
Nuclear decommissioning trust	95,000	119,000
Recurring | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust, other	(4,000)	(7,000)
Nuclear decommissioning trust	7,000	4,000
Recurring | Corporate debt
Assets
Nuclear decommissioning trust	116,000	109,000
Recurring | Mortgage-backed securities
Assets
Nuclear decommissioning trust	87,000	89,000
Recurring | Municipality bonds
Assets
Nuclear decommissioning trust	86,000	69,000
Recurring | Other
Assets
Nuclear decommissioning trust	19,000	14,000
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Decommissioning fund investments, gross fair value	93,000	119,000
Gross assets, fair value disclosure	93,000	119,000
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	93,000	119,000
Recurring | Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	16,000	21,000
Decommissioning fund investments, gross fair value	635,000	602,000
Gross assets, fair value disclosure	651,000	623,000
Liabilities
Gross derivative liability	(103,000)	(95,000)
Recurring | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Decommissioning fund investments, gross fair value	314,000	310,000
Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	2,000
Recurring | Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds
Assets
Decommissioning fund investments, gross fair value	11,000	11,000
Recurring | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Decommissioning fund investments, gross fair value	116,000	109,000
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	87,000	89,000
Recurring | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Decommissioning fund investments, gross fair value	86,000	69,000
Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets
Decommissioning fund investments, gross fair value	19,000	14,000
Recurring | Significant Unobservable Inputs (Level 3)
Assets
Gross derivative assets	30,000	33,000
Gross assets, fair value disclosure	30,000	33,000
Liabilities
Gross derivative liability	$ (73,000)	$ (74,000)

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Changes in Accumulated Other Comprehensive Loss (Tables)

6 Months Ended

Jun. 30, 2015

Accumulated Other Comprehensive Income (Loss) [Line Items]

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

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended June 30, 2015											Three Months Ended June 30, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, April 1	$	(9,209	)		$	(57,173	)		$	(66,382	)	$	(20,364	)		$	(54,538	)		$	(74,902	)
OCI (loss) before reclassifications	25				(969		)		(944		)	40				(2,072		)		(2,032		)
Amounts reclassified from accumulated other comprehensive loss	874			(a)	852			(b)	1,726			1,955			(a)	762			(b)	2,717
Net current period OCI (loss)	899				(117		)		782			1,995				(1,310		)		685
Ending balance, June 30	$	(8,310	)		$	(57,290	)		$	(65,600	)	$	(18,369	)		$	(55,848	)		$	(74,217	)

(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.

	Six Months Ended June 30, 2015											Six Months Ended June 30, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(57,756	)		$	(68,141	)	$	(23,058	)		$	(54,995	)		$	(78,053	)
OCI (loss) before reclassifications	(775		)		(969		)		(1,744		)	(381		)		(2,072		)		(2,453		)
Amounts reclassified from accumulated other comprehensive loss	2,850			(a)	1,435			(b)	4,285			5,070			(a)	1,219			(b)	6,289
Net current period OCI (loss)	2,075				466				2,541			4,689				(853		)		3,836
Ending balance, June 30	$	(8,310	)		$	(57,290	)		$	(65,600	)	$	(18,369	)		$	(55,848	)		$	(74,217	)

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

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

Arizona Public Service Company

Accumulated Other Comprehensive Income (Loss) [Line Items]

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

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended June 30, 2015											Three Months Ended June 30, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, April 1	$	(9,209	)		$	(37,267	)		$	(46,476	)	$	(20,364	)		$	(29,747	)		$	(50,111	)
OCI (loss) before reclassifications	25				(927		)		(902		)	40				(2,041		)		(2,001		)
Amounts reclassified from accumulated other comprehensive loss	874			(a)	853			(b)	1,727			1,954			(a)	758			(b)	2,712
Net current period OCI (loss)	899				(74		)		825			1,994				(1,283		)		711
Ending balance, June 30	$	(8,310	)		$	(37,341	)		$	(45,651	)	$	(18,370	)		$	(31,030	)		$	(49,400	)

(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.

	Six Months Ended June 30, 2015											Six Months Ended June 30, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(37,948	)		$	(48,333	)	$	(23,059	)		$	(30,313	)		$	(53,372	)
OCI (loss) before reclassifications	(775		)		(927		)		(1,702		)	(381		)		(2,041		)		(2,422		)
Amounts reclassified from accumulated other comprehensive loss	2,850			(a)	1,534			(b)	4,384			5,070			(a)	1,324			(b)	6,394
Net current period OCI (loss)	2,075				607				2,682			4,689				(717		)		3,972
Ending balance, June 30	$	(8,310	)		$	(37,341	)		$	(45,651	)	$	(18,370	)		$	(31,030	)		$	(49,400	)

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

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

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Asset Retirement Obligations Roll-Forward (Details) - Arizona Public Service Company - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	$ 391
Changes attributable to:
Accretion expense	12
Settlements	(18)
Estimated cash flow revisions	24
Newly incurred liabilities	39
Asset retirement obligations at the end of year	$ 448

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Changes in Accumulated Other Comprehensive Loss

6 Months Ended

Jun. 30, 2015

Accumulated Other Comprehensive Income (Loss) [Line Items]

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended June 30, 2015											Three Months Ended June 30, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, April 1	$	(9,209	)		$	(57,173	)		$	(66,382	)	$	(20,364	)		$	(54,538	)		$	(74,902	)
OCI (loss) before reclassifications	25				(969		)		(944		)	40				(2,072		)		(2,032		)
Amounts reclassified from accumulated other comprehensive loss	874			(a)	852			(b)	1,726			1,955			(a)	762			(b)	2,717
Net current period OCI (loss)	899				(117		)		782			1,995				(1,310		)		685
Ending balance, June 30	$	(8,310	)		$	(57,290	)		$	(65,600	)	$	(18,369	)		$	(55,848	)		$	(74,217	)

(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.

	Six Months Ended June 30, 2015											Six Months Ended June 30, 2014
	Derivative Instruments				Pension and  Other Postretirement Benefits				Total			Derivative Instruments				Pension and   Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(57,756	)		$	(68,141	)	$	(23,058	)		$	(54,995	)		$	(78,053	)
OCI (loss) before reclassifications	(775		)		(969		)		(1,744		)	(381		)		(2,072		)		(2,453		)
Amounts reclassified from accumulated other comprehensive loss	2,850			(a)	1,435			(b)	4,285			5,070			(a)	1,219			(b)	6,289
Net current period OCI (loss)	2,075				466				2,541			4,689				(853		)		3,836
Ending balance, June 30	$	(8,310	)		$	(57,290	)		$	(65,600	)	$	(18,369	)		$	(55,848	)		$	(74,217	)

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

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

Arizona Public Service Company

Accumulated Other Comprehensive Income (Loss) [Line Items]

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended June 30, 2015											Three Months Ended June 30, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, April 1	$	(9,209	)		$	(37,267	)		$	(46,476	)	$	(20,364	)		$	(29,747	)		$	(50,111	)
OCI (loss) before reclassifications	25				(927		)		(902		)	40				(2,041		)		(2,001		)
Amounts reclassified from accumulated other comprehensive loss	874			(a)	853			(b)	1,727			1,954			(a)	758			(b)	2,712
Net current period OCI (loss)	899				(74		)		825			1,994				(1,283		)		711
Ending balance, June 30	$	(8,310	)		$	(37,341	)		$	(45,651	)	$	(18,370	)		$	(31,030	)		$	(49,400	)

(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.

	Six Months Ended June 30, 2015											Six Months Ended June 30, 2014
	Derivative Instruments				Pension and   Other Postretirement Benefits				Total			Derivative Instruments				Pension and  Other Postretirement Benefits				Total
Beginning balance, January 1	$	(10,385	)		$	(37,948	)		$	(48,333	)	$	(23,059	)		$	(30,313	)		$	(53,372	)
OCI (loss) before reclassifications	(775		)		(927		)		(1,702		)	(381		)		(2,041		)		(2,422		)
Amounts reclassified from accumulated other comprehensive loss	2,850			(a)	1,534			(b)	4,384			5,070			(a)	1,324			(b)	6,394
Net current period OCI (loss)	2,075				607				2,682			4,689				(717		)		3,972
Ending balance, June 30	$	(8,310	)		$	(37,341	)		$	(45,651	)	$	(18,370	)		$	(31,030	)		$	(49,400	)

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

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

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Change in asset retirement obligations

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2015 (dollars in millions): 

Asset retirement obligations at January 1, 2015	$	391
Changes attributable to:
Accretion expense	12
Settlements	(18		)
Estimated cash flow revisions	24
Newly incurred liabilities	39
Asset retirement obligations at June 30, 2015	$	448

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New Accounting Standards (Policies)

6 Months Ended

Jun. 30, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

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

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

In April 2015, the Financial Accounting Standards Board issued new guidance that changes the balance sheet presentation of debt issuance costs. Currently, debt issuance costs are presented on the balance sheet as assets. The new guidance requires us to reflect debt issuance costs as a reduction to the related debt liabilities, consistent with the presentation of debt discounts. The new guidance is effective for us during the first quarter of 2016, and must be adopted retrospectively. We do not expect these presentation changes to be material to our balance sheet. The adoption of this new guidance will not impact our results of operations or cash flows.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 148,234	$ 166,075
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	282,218	246,371
Deferred fuel and purchased power	11,711	1,315
Deferred fuel and purchased power amortization	11,424	18,399
Allowance for equity funds used during construction	(18,569)	(14,941)
Deferred income taxes	65,377	32,611
Deferred investment tax credit	(2,218)	28,875
Change in derivative instruments fair value	(225)	49
Changes in current assets and liabilities:
Customer and other receivables	(17,402)	(64,986)
Accrued unbilled revenues	(84,683)	(75,648)
Materials, supplies and fossil fuel	(18,311)	(9,435)
Income tax receivable	3,098	135,517
Other current assets	(8,728)	(14,038)
Accounts payable	36,634	30,725
Accrued taxes	15,199	30,709
Other current liabilities	(13,138)	19,978
Change in margin and collateral accounts — assets	(4,552)	(2,107)
Change in margin and collateral accounts — liabilities	26,853	(22,425)
Change in other long-term assets	(4,817)	(19,243)
Change in other long-term liabilities	(33,811)	(22,735)
Net cash flow provided by operating activities	394,294	465,066
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(531,035)	(388,752)
Contributions in aid of construction	41,010	12,646
Allowance for borrowed funds used during construction	(8,538)	(7,560)
Proceeds from nuclear decommissioning trust sales	225,779	199,224
Investment in nuclear decommissioning trust	(234,651)	(207,848)
Other	(2,068)	(678)
Net cash flow used for investing activities	(509,503)	(392,968)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	600,000	535,975
Repayment of long-term debt	(344,847)	(503,583)
Short-term borrowings and payments — net	10,100	23,525
Dividends paid on common stock	(128,241)	(125,138)
Common stock equity issuance	12,161	12,625
Distributions to noncontrolling interest	(28,012)	(15,869)
Other	1	2
Net cash flow provided by (used for) financing activities	121,162	(72,463)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,953	(365)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	7,604	9,526
CASH AND CASH EQUIVALENTS AT END OF PERIOD	13,557	9,161
Cash paid (received) during the period for:
Income taxes, net of refunds	1,834	(131,154)
Interest, net of amounts capitalized	84,008	90,707
Significant non-cash investing and financing activities:
Accrued capital expenditures	38,985	19,668
Dividends declared but not yet paid	65,933	62,656
Arizona Public Service Company
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	154,440	172,285
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	282,172	246,324
Deferred fuel and purchased power	11,711	1,315
Deferred fuel and purchased power amortization	11,424	18,399
Allowance for equity funds used during construction	(18,569)	(14,941)
Deferred income taxes	24,442	34,133
Deferred investment tax credit	(2,218)	28,875
Change in derivative instruments fair value	(225)	49
Changes in current assets and liabilities:
Customer and other receivables	(9,250)	(65,603)
Accrued unbilled revenues	(84,683)	(75,648)
Materials, supplies and fossil fuel	(18,311)	(9,435)
Income tax receivable	0	135,179
Other current assets	(8,193)	(14,120)
Accounts payable	37,656	28,465
Accrued taxes	68,382	38,381
Other current liabilities	(31,408)	31,296
Change in margin and collateral accounts — assets	(4,552)	(2,107)
Change in margin and collateral accounts — liabilities	26,853	(22,425)
Change in other long-term assets	(6,765)	(18,703)
Change in other long-term liabilities	(27,136)	(24,467)
Net cash flow provided by operating activities	405,770	487,252
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(530,850)	(388,752)
Contributions in aid of construction	41,010	12,646
Allowance for borrowed funds used during construction	(8,527)	(7,560)
Proceeds from nuclear decommissioning trust sales	225,779	199,224
Investment in nuclear decommissioning trust	(234,651)	(207,848)
Other	(614)	(678)
Net cash flow used for investing activities	(507,853)	(392,968)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	600,000	535,975
Repayment of long-term debt	(344,847)	(503,583)
Short-term borrowings and payments — net	10,100	19,650
Dividends paid on common stock	(131,700)	(125,100)
Distributions to noncontrolling interest	(28,012)	(15,869)
Net cash flow provided by (used for) financing activities	105,541	(88,927)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	3,458	5,357
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	4,515	3,725
CASH AND CASH EQUIVALENTS AT END OF PERIOD	7,973	9,082
Cash paid (received) during the period for:
Income taxes, net of refunds	184	(134,399)
Interest, net of amounts capitalized	82,651	88,461
Significant non-cash investing and financing activities:
Accrued capital expenditures	38,985	19,668
Dividends declared but not yet paid	$ 65,900	$ 62,600

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
NET INCOME	$ 127,507	$ 141,384	$ 148,234	$ 166,075
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	25	40	(775)	(381)
Reclassification of net realized loss, net of tax benefit	874	1,955	2,850	5,070
Pension and other postretirement benefits activity, net of tax benefit (expense)	(117)	(1,310)	466	(853)
Total other comprehensive income	782	685	2,541	3,836
COMPREHENSIVE INCOME	128,289	142,069	150,775	169,911
Less: Comprehensive income attributable to noncontrolling interests	4,605	8,926	9,210	17,851
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	123,684	133,143	141,565	152,060
Arizona Public Service Company
NET INCOME	129,967	143,842	154,440	172,285
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	25	40	(775)	(381)
Reclassification of net realized loss, net of tax benefit	874	1,954	2,850	5,070
Pension and other postretirement benefits activity, net of tax benefit (expense)	(74)	(1,283)	607	(717)
Total other comprehensive income	825	711	2,682	3,972
COMPREHENSIVE INCOME	130,792	144,553	157,122	176,257
Less: Comprehensive income attributable to noncontrolling interests	4,605	8,926	9,210	17,851
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 126,187	$ 135,627	$ 147,912	$ 158,406

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Other Income and Other Expense

6 Months Ended

Jun. 30, 2015

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

Other Income and Other Expense

Other Income and Other Expense

The following table provides detail of other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Other income:
Interest income	$	184		$	495		$	294		$	746
Miscellaneous	(9		)	2,286			116			4,402
Total other income	$	175		$	2,781		$	410		$	5,148
Other expense:
Non-operating costs	$	(1,952	)	$	(2,620	)	$	(4,200	)	$	(4,992	)
Investment losses — net	(650		)	(105		)	(1,145		)	(246		)
Miscellaneous	(7		)	2,217			(1,550		)	46
Total other expense	$	(2,609	)	$	(508	)	$	(6,895	)	$	(5,192	)

Arizona Public Service Company

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

Other Income and Other Expense

Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Other income:
Interest income	$	6		$	417		$	73		$	554
Gain on disposition of property	478			328			685			645
Miscellaneous	226			2,476			591			4,784
Total other income	$	710		$	3,221		$	1,349		$	5,983
Other expense:
Non-operating costs (a)	$	(1,878	)	$	(2,868	)	$	(4,395	)	$	(5,455	)
Loss on disposition of property	(251		)	(285		)	(894		)	(468		)
Miscellaneous	(320		)	1,676			(2,514		)	(610		)
Total other expense	$	(2,449	)	$	(1,477	)	$	(7,803	)	$	(6,533	)

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

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 24, 2015
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	0000764622
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		110,813,659
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Arizona Public Service Company
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	0000007286
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		71,264,947
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2

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Earnings Per Share

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2015 and 2014 (in thousands, except per share amounts):

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
Net income attributable to common shareholders	$	122,902	$	132,458	$	139,024	$	148,224
Weighted average common shares outstanding — basic	110,986		110,565		110,958		110,546
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	474		437		468		379
Weighted average common shares outstanding — diluted	111,460		111,002		111,426		110,925
Earnings per average common share attributable to common shareholders — basic	$	1.11	$	1.20	$	1.25	$	1.34
Earnings per average common share attributable to common shareholders — diluted	$	1.10	$	1.19	$	1.25	$	1.34

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net unrealized gain (loss), tax benefit (expense)	$ (16)	$ (26)	$ (489)	$ (624)
Reclassification of net realized loss, tax benefit	556	1,261	923	2,584
Pension and other postretirement benefits activity, tax benefit (expense)	74	845	(793)	128
Arizona Public Service Company
Net unrealized gain (loss), tax benefit (expense)	(16)	(26)	(489)	(624)
Reclassification of net realized loss, tax benefit	556	1,261	923	2,584
Pension and other postretirement benefits activity, tax benefit (expense)	$ 47	$ 828	$ (722)	$ 222

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Retirement Plans and Other Benefits

6 Months Ended

Jun. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Retirement Plans and Other Benefits

Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of these plan changes in 2014, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new account to pay for active union employee medical costs.

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We amortized approximately $2 million and $4 million for the three and six months ended June 30, 2015 and 2014, respectively. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):

	Pension Benefits												Other Benefits
	Three Months Ended   June 30,						Six Months Ended   June 30,						Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost — benefits earned during the period	$	14		$	12		$	30		$	27		$	4		$	5		$	8		$	9
Interest cost on benefit obligation	31			33			62			65			7			11			14			23
Expected return on plan assets	(45		)	(39		)	(90		)	(79		)	(9		)	(13		)	(18		)	(25		)
Amortization of:
Prior service cost	—			—			—			—			(9		)	—			(19		)	—
Net actuarial loss	8			3			16			5			—			—			2			—
Net periodic benefit cost	$	8		$	9		$	18		$	18		$	(7	)	$	3		$	(13	)	$	7
Portion of cost charged to expense	$	5		$	5		$	11		$	11		$	(2	)	$	3		$	(4	)	$	5

Contributions

We have made voluntary contributions of $80 million to our pension plan year-to-date in 2015. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017).  We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

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Regulatory Matters

6 Months Ended

Jun. 30, 2015

Regulated Operations [Abstract]

Regulatory Matters

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.

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

• An authorized return on common equity of 10.0%;

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

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

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

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

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

• A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below);

• Implementation of a Lost Fixed Cost Recovery ("LFCR") rate mechanism to support energy efficiency and distributed renewable generation;

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

• Modifications to the Power Supply Adjustor ("PSA"), including the elimination of the 90/10 sharing provision;

• A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge ("DSMAC") to recoup capital expenditures not required under the terms of APS’s 2009 retail rate case settlement agreement (the "2009 Settlement Agreement");

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

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

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

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

Cost Recovery Mechanisms

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

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

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.

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

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

On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million.

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

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

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

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

On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.

Electric Energy Efficiency

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

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

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2015 and 2014 (dollars in millions):

	Six Months Ended   June 30,
	2015			2014
Beginning balance	$	7		$	21
Deferred fuel and purchased power costs — current period	(12		)	(1		)
Amounts charged to customers	(11		)	(19		)
Ending balance	$	(16	)	$	1

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

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

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

Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014.

Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 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, 2015.

APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future.

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 files for a LFCR adjustment every January.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million, which was approved on March 2, 2015, effective for the first billing cycle of March.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a "market" basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and early 2015. No further action has been taken by the ACC to date.

Net Metering

On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The fixed charge does not increase APS's revenue because it is credited to the LFCR.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.  In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. 

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

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

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

Four Corners

On December 30, 2013, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $74 million as of June 30, 2015 and is being amortized in rates over 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and will actively participate in the proceeding. We cannot predict when or how this appeal will be resolved.

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

Cholla

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

If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($125 million as of June 30, 2015), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.

Regulatory Assets and Liabilities

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

	Remaining Amortization Period	June 30, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Pension benefits	(a)	$	—	$	505	$	—	$	485
Income taxes — allowance for funds used during construction ("AFUDC") equity	2044	5		122		5		118
Deferred fuel and purchased power — mark-to-market (Note 7)	2018	53		62		51		46
Transmission vegetation management	2016	9		—		9		5
Coal reclamation	2026	—		6		—		7
Palo Verde VIEs (Note 6)	2046	—		26		—		35
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		7		—
Tax expense of Medicare subsidy	2024	2		13		2		14
Loss on reacquired debt	2034	1		16		1		16
Income taxes — investment tax credit basis adjustment	2044	2		46		2		46
Pension and other postretirement benefits deferral	2015	—		—		4		—
Four Corners cost deferral	2024	7		67		7		70
Lost fixed cost recovery (b)	2016	45		—		38		—
Retired power plant costs	2033	10		131		10		136
Deferred property taxes	(d)	—		40		—		30
Other	Various	1		11		2		12
Total regulatory assets (e)		$	135	$	1,081	$	138	$	1,054

(a) This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues.  See Note 4 for further discussion.

(b) See "Cost Recovery Mechanisms" discussion above.

(c) Subject to a carrying charge.

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

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

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

	Remaining Amortization Period	June 30, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	44	$	245	$	31	$	273
Asset retirement obligations	2044	—		272		—		296
Renewable energy standard (b)	2017	29		20		25		23
Income taxes — change in rates	2043	1		71		—		72
Spent nuclear fuel	2047	3		68		5		66
Deferred gains on utility property	2019	2		7		2		8
Income taxes — deferred investment tax credit	2043	3		92		4		93
Deferred fuel and purchased power (b) (c)	2016	16		—		—		—
Demand side management (b)	2017	8		27		31		—
Other postretirement benefits	(d)	33		189		32		199
Other	Various	13		26		1		21
Total regulatory liabilities		$	152	$	1,017	$	131	$	1,051

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

(b) See "Cost Recovery Mechanisms" discussion above.

(c) Subject to a carrying charge.

(d) See Note 4.

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

In the first quarter of 2015, an updated decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the asset retirement obligation ("ARO") in the amount of $18 million.

In the second quarter of 2015, there was a revision in estimated cash flows for the Four Corners decommissioning, whichresulted in an increase to the ARO in the amount of $6 million. In addition, APS recognized an ARO for Cholla as a result of new CCR environmental rulings that were published in the Federal Register in the second quarter of 2015. See Note 8 for additional information related to the CCR environmental rulings. This resulted in an increase to the ARO in the amount of $39 million, an increase in plant in service of $23 million and a reduction of the regulatory liability of $16 million.

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2015 (dollars in millions): 

Asset retirement obligations at January 1, 2015	$	391
Changes attributable to:
Accretion expense	12
Settlements	(18		)
Estimated cash flow revisions	24
Newly incurred liabilities	39
Asset retirement obligations at June 30, 2015	$	448

Decommissioning activities for Four Corners Units 1-3 began in January 2014; thus, $29 million of the total asset retirement obligation of $448 million at June 30, 2015, is classified as a current liability on the balance sheet.

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

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Fair Value Measurements

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

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

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

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

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

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans.  See Note 7 in the 2014 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

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

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

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

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

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

Investments Held in our Nuclear Decommissioning Trust

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

Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper.  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 typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.

We price securities using information provided by our trustee for our nuclear decommissioning trust assets.  Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value.  We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.  See Note 12 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at June 30, 2015, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at June 30, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	16		$	30		$	(13	)	(b)	$	33
Nuclear decommissioning trust:
U.S. commingled equity funds	—		314			—			—				314
Cash and cash equivalent funds	—		11			—			(4		)	(c)	7
Fixed income securities:
U.S. Treasury	93		2			—			—				95
Corporate debt	—		116			—			—				116
Mortgage-backed securities	—		87			—			—				87
Municipal bonds	—		86			—			—				86
Other	—		19			—			—				19
Subtotal nuclear decommissioning trust	93		635			—			(4		)		724
Total	$	93	$	651		$	30		$	(17	)		$	757
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(103	)	$	(73	)	$	28		(b)	$	(148	)

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

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

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

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

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at December 31, 2014
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	21		$	33		$	(23	)	(b)	$	31
Nuclear decommissioning trust:
U.S. commingled equity funds	—		310			—			—				310
Fixed income securities:
U.S. Treasury	119		—			—			—				119
Cash and cash equivalent funds	—		11			—			(7		)	(c)	4
Corporate debt	—		109			—			—				109
Mortgage-backed securities	—		89			—			—				89
Municipal bonds	—		69			—			—				69
Other	—		14			—			—				14
Subtotal nuclear decommissioning trust	119		602			—			(7		)		714
Total	$	119	$	623		$	33		$	(30	)		$	745
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(95	)	$	(74	)	$	59		(b)	$	(110	)

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

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

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

Fair Value Measurements Classified as Level 3

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

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

Our option contracts classified as Level 3 primarily relate to purchase heat rate options.  The significant unobservable inputs at June 30, 2015 for these instruments include electricity prices, and volatilities. The significant unobservable inputs at December 31, 2014 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, 2015 and December 31, 2014:

	June 30, 2015 Fair Value (millions)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	28	$	57	Discounted cash flows	Electricity forward price (per MWh)	$21.07 - $67.74	$	31.46
Option Contracts (b)	—		12		Option model	Electricity forward price (per MWh)	$32.85 - $67.74	$	46.13
						Electricity price volatilities	26% - 115%	68		%
						Natural gas price volatilities	27% - 42%	31		%
Natural Gas:
Forward Contracts (a)	2		4		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.69 - $3.61	$	3.23
Total	$	30	$	73

(a) Includes swaps and physical and financial contracts.

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

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

(a) Includes swaps and physical and financial contracts.

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

The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2015 and 2014 (dollars in millions):

	Three Months Ended   June 30,						Six Months Ended   June 30,
Commodity Contracts	2015			2014			2015			2014
Net derivative balance at beginning of period	$	(49	)	$	(49	)	$	(41	)	$	(49	)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	6			3			(5		)	6
Settlements	5			4			5			5
Transfers into Level 3 from Level 2	(4		)	1			(4		)	(2		)
Transfers from Level 3 into Level 2	(1		)	—			2			(1		)
Net derivative balance at end of period	$	(43	)	$	(41	)	$	(43	)	$	(41	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

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

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

Financial Instruments Not Carried at Fair Value

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

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Derivative Accounting

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Accounting

Derivative Accounting

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

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

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value.  See Note 11 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

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

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

As of June 30, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	3,808	GWh
Gas	188	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, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   June 30,						Six Months Ended   June 30,
Commodity Contracts		2015			2014			2015			2014
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	41		$	66		$	(286	)	$	243
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(1,430		)	(3,216		)	(3,773		)	(7,654		)

(a) During the three and six months ended June 30, 2015 and 2014, we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

During the next twelve months, we estimate that a net loss of $4 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, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2015 and 2014 (dollars in thousands):

	Financial Statement Location	Three Months Ended   June 30,					Six Months Ended June 30,
Commodity Contracts		2015			2014		2015			2014
Net gain (loss) recognized in income	Operating revenues (a)	$	(66	)	$	155	$	(114	)	$	63
Net gain (loss) recognized in income	Fuel and purchased power (a)	10,613			4,805		(34,190		)	22,912
Total		$	10,547		$	4,960	$	(34,304	)	$	22,975

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

Derivative Instruments in the Condensed Consolidated Balance Sheets

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

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

The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, each include gross liabilities of $4 million of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2015 and December 31, 2014.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2015: (Dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance  Sheet
Current assets	$	25,485		$	(12,925	)	$	12,560		$	2,162		$	14,722
Investments and other assets	20,560			(4,787		)	15,773			2,740			18,513
Total assets	46,045			(17,712		)	28,333			4,902			33,235
Current liabilities	(83,203		)	30,626			(52,577		)	(8,096		)	(60,673		)
Deferred credits and other	(92,475		)	4,786			(87,689		)	—			(87,689		)
Total liabilities	(175,678		)	35,412			(140,266		)	(8,096		)	(148,362		)
Total	$	(129,633	)	$	17,700		$	(111,933	)	$	(3,194	)	$	(115,127	)

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

(b) Includes cash collateral provided to counterparties of $17,700.

(c) Represents cash collateral, cash margin and option premiums that are not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $8,096, cash margin provided to counterparties of $2,162 and option premiums of $2,740.

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

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

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

(c) Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,443, and cash margin provided to counterparties of $350.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties.  We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 81% of Pinnacle West’s $33 million of risk management assets as of June 30, 2015.  This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality.  Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2015 (dollars in millions):

	June 30, 2015
Aggregate fair value of derivative instruments in a net liability position	$	176
Cash collateral posted	18
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	89

(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 $161 million if our debt credit ratings were to fall below investment grade.

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Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015 USD ($) $ / MMBTU $ / MWh	Dec. 31, 2014 USD ($) $ / MMBTU $ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 30	$ 33
Liabilities	73	74
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	28	30
Liabilities	$ 57	$ 56
Electricity forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh	21.07	19.51
Electricity forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh	67.74	56.72
Electricity forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh	31.46	35.27
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 0	$ 0
Liabilities	$ 12	$ 15
Option Contracts | Minimum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh	32.85	32.14
Natural gas forward price (per MMbtu) | $ / MMBTU		3.18
Electricity price volatilities (as a percent)	26.00%	23.00%
Natural gas price volatilities (as a percent)	27.00%	23.00%
Option Contracts | Maximum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh	67.74	66.09
Natural gas forward price (per MMbtu) | $ / MMBTU		3.29
Electricity price volatilities (as a percent)	115.00%	63.00%
Natural gas price volatilities (as a percent)	42.00%	41.00%
Option Contracts | Weighted Average | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) | $ / MWh	46.13	45.83
Natural gas forward price (per MMbtu) | $ / MMBTU		3.25
Electricity price volatilities (as a percent)	68.00%	41.00%
Natural gas price volatilities (as a percent)	31.00%	31.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 2	$ 3
Liabilities	$ 4	$ 3
Natural gas forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu) | $ / MMBTU	2.69	2.98
Natural gas forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu) | $ / MMBTU	3.61	4.13
Natural gas forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu) | $ / MMBTU	3.23	3.45

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Income Taxes

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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

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

As of June 30, 2015, the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS.  With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2009.

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Palo Verde Sale Leaseback Variable Interest Entities

6 Months Ended

Jun. 30, 2015

Variable Interest Entities [Abstract]

Palo Verde Sale Leaseback Variable Interest Entities

Palo Verde Sale Leaseback Variable Interest Entities

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

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

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation and interest expense, resulting in an increase in net income for the three and six months ended June 30, 2015 of $5 million and $9 million, respectively, and for the three and six months ended June 30, 2014 of $9 million and $18 million, respectively, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased because of lower rent income resulting from the July 7, 2014 lease extensions.

In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions):

	June 30, 2015		December 31, 2014
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	119	$	121
Current maturities of long-term debt	1		13
Equity — Noncontrolling interests	133		152

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

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the United States Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event had occurred as of June 30, 2015, APS would have been required to pay the noncontrolling equity participants approximately $114 million and assume $1 million of debt.  Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit seeks to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016.

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

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of $12.98 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments.  The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment of approximately $16.5 million.

The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination.  APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds.  The maximum amount APS could incur under the current NEIL policies totals approximately $23.1 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 $61.7 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

During the quarter our purchase obligations have increased by about $170 million relating to gas generation projects. The expected payments to be made are $26 million in 2015, $89 million in 2016, $46 million in 2017 and $9 million in 2018.

Other than the item described above, there have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2014 Form 10-K.

Superfund-Related Matters

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

On August 6, 2013, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Southwest Power Outage

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

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

Clean Air Act Citizen Lawsuit

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review ("NSR") provisions of the Clean Air Act.  Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards ("NSPS") program.  Among other things, the environmental plaintiffs sought to have the court enjoin operations at Four Corners until APS applied for and obtained any required NSR permits and complied with the NSPS.  The plaintiffs further requested the court to order the payment of civil penalties, including a beneficial mitigation project.  The case was held in abeyance while APS negotiated a settlement with the United States Department of Justice ("DOJ") and environmental plaintiffs.  In March 2015, the parties agreed in principle on final proposed language to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On that same day, DOJ also published notice of the filing in the Federal Register, which opened a 30-day period for public comment. The settlement would resolve claims by the government and environmental plaintiffs that the co-owners violated the Clean Air Act by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement would require installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule best available retrofit technology ("BART") requirements. The settlement would also require Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.2 million for certain environmental mitigation projects to benefit the Navajo Nation. APS would be responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows. APS expects DOJ to file a motion to enter the consent decree with the court after expiration of the 30-day comment period.

Environmental Matters

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

Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners, Cholla and the Navajo Generating Station ("Navajo Plant").  EPA and ADEQ will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. 

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

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

Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million, is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program.  Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit.  Briefing in the case was completed in February 2014. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rule-making processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On June 10, 2015, ADEQ issued for public comment the draft Cholla permit, which memorializes APS's proposal, and a proposed revision to the SIP, which would incorporate the new permit terms.  APS is unable to predict when or whether APS's proposal may ultimately be approved.

Mercury and Air Toxic Standards ("MATS").  In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants.  APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS's compromise proposal discussed above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  Salt River Project Agricultural Improvement and Power District ("SRP"), the operating agent for the Navajo Plant, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. The United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS rule.  This decision does not materially impact APS.  Regardless of whether the MATS rule is ultimately vacated by the lower court, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla.

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

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

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

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

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment").  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013.  The New Mexico Taxation and Revenue Department denied the refund claim.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The New Mexico Taxation and Revenue Department has indicated it intends to appeal the decision. We cannot predict the timing or outcome of any appeal; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At June 30, 2015, 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.  Two of these letters of credit expire in 2016 and one expires in 2017.  APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $20 million at June 30, 2015.  Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including a natural gas tolling contract entered into with a third party.  At June 30, 2015, $35 million of such letters of credit were outstanding that will expire in 2015 and 2016.

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

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Asset Retirement Obligations Narrative (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Asset Retirement Obligations
Asset retirement obligation, current	$ 28,543		$ 28,543	$ 32,462
Arizona Public Service Company
Asset Retirement Obligations
Estimated cash flow revisions			24,000
Newly incurred liabilities			39,000
Asset retirement obligation, current	28,543		28,543	32,462
Asset retirement obligation	448,000		$ 448,000	$ 391,000
Arizona Public Service Company | Four Corners
Asset Retirement Obligations
Estimated cash flow revisions	6,000	$ 18,000
Arizona Public Service Company | Cholla
Asset Retirement Obligations
Newly incurred liabilities	39,000
Newly incurred liabilities, increase in plant services	23,000
Newly incurred liabilities, decrease in regulatory liabilities	$ 16,000

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Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ (66,382)	$ (74,902)	$ (68,141)	$ (78,053)
OCI (loss) before reclassifications	(944)	(2,032)	(1,744)	(2,453)
Amounts reclassified from accumulated other comprehensive loss	1,726	2,717	4,285	6,289
Total other comprehensive income	782	685	2,541	3,836
Ending balance	(65,600)	(74,217)	(65,600)	(74,217)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(9,209)	(20,364)	(10,385)	(23,058)
OCI (loss) before reclassifications	25	40	(775)	(381)
Amounts reclassified from accumulated other comprehensive loss	874	1,955	2,850	5,070
Total other comprehensive income	899	1,995	2,075	4,689
Ending balance	(8,310)	(18,369)	(8,310)	(18,369)
Pension and other postretirement benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(57,173)	(54,538)	(57,756)	(54,995)
OCI (loss) before reclassifications	(969)	(2,072)	(969)	(2,072)
Amounts reclassified from accumulated other comprehensive loss	852	762	1,435	1,219
Total other comprehensive income	(117)	(1,310)	466	(853)
Ending balance	(57,290)	(55,848)	(57,290)	(55,848)
Arizona Public Service Company
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(46,476)	(50,111)	(48,333)	(53,372)
OCI (loss) before reclassifications	(902)	(2,001)	(1,702)	(2,422)
Amounts reclassified from accumulated other comprehensive loss	1,727	2,712	4,384	6,394
Total other comprehensive income	825	711	2,682	3,972
Ending balance	(45,651)	(49,400)	(45,651)	(49,400)
Arizona Public Service Company | Derivative Instruments
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(9,209)	(20,364)	(10,385)	(23,059)
OCI (loss) before reclassifications	25	40	(775)	(381)
Amounts reclassified from accumulated other comprehensive loss	874	1,954	2,850	5,070
Total other comprehensive income	899	1,994	2,075	4,689
Ending balance	(8,310)	(18,370)	(8,310)	(18,370)
Arizona Public Service Company | Pension and other postretirement benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(37,267)	(29,747)	(37,948)	(30,313)
OCI (loss) before reclassifications	(927)	(2,041)	(927)	(2,041)
Amounts reclassified from accumulated other comprehensive loss	853	758	1,534	1,324
Total other comprehensive income	(74)	(1,283)	607	(717)
Ending balance	$ (37,341)	$ (31,030)	$ (37,341)	$ (31,030)

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Nuclear Decommissioning Trusts (Tables)

6 Months Ended

Jun. 30, 2015

Investments, Debt and Equity Securities [Abstract]

Fair value of APS's nuclear decommissioning trust fund assets

The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2015 and December 31, 2014 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2015
Equity securities	$	314		$	160	$	—
Fixed income securities	414			13		(3		)
Net payables (a)	(4		)	—		—
Total	$	724		$	173	$	(3	)

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

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

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

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

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Realized gains	$	1		$	1		$	2		$	2
Realized losses	(1		)	(1		)	(2		)	(3		)
Proceeds from the sale of securities (a)	110			96			226			199

(a) Proceeds are reinvested in the trust.

Fair value of fixed income securities, summarized by contractual maturities

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2015 is as follows (dollars in millions):

	Fair Value
Less than one year	$	13
1 year – 5 years	111
5 years – 10 years	123
Greater than 10 years	167
Total	$	414

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Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Designated as Hedging Instruments
Gains and losses from derivative instruments
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	$ 0	$ 0	$ 0	$ 0
Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(1,430,000)	(3,216,000)	(3,773,000)	(7,654,000)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net gain (loss) recognized in income	10,547,000	4,960,000	(34,304,000)	22,975,000
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net gain (loss) recognized in income	(66,000)	155,000	(114,000)	63,000
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net gain (loss) recognized in income	10,613,000	4,805,000	(34,190,000)	22,912,000
Other comprehensive income | Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain (loss) recognized in OCI on derivative instruments (effective portion)	$ 41,000	$ 66,000	$ (286,000)	$ 243,000

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New Accounting Standards

6 Months Ended

Jun. 30, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

New Accounting Standards

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

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

In April 2015, the Financial Accounting Standards Board issued new guidance that changes the balance sheet presentation of debt issuance costs. Currently, debt issuance costs are presented on the balance sheet as assets. The new guidance requires us to reflect debt issuance costs as a reduction to the related debt liabilities, consistent with the presentation of debt discounts. The new guidance is effective for us during the first quarter of 2016, and must be adopted retrospectively. We do not expect these presentation changes to be material to our balance sheet. The adoption of this new guidance will not impact our results of operations or cash flows.

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Long-Term Debt and Liquidity Matters (Tables)

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

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

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

	As of June 30, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,544		3,818		3,290		3,714
Total	$	3,669	$	3,943	$	3,415	$	3,839

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Derivative Accounting - Narrative (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2015 USD ($) Counterparty	Dec. 31, 2014 USD ($)
Derivative Accounting
Percentage of deferred unrealized gains (losses) on contracts due to PSA recovery	100.00%
Designated as Hedging Instruments
Derivative Accounting
Gross recognized derivatives	$ 4,000	$ 4,000
Commodity Contracts
Derivative Accounting
Gross recognized derivatives	$ 175,678	169,052
Concentration of credit risk, number of counterparties | Counterparty	1
Concentration of risk with two counterparties, as a percentage of risk management assets	81.00%
Risk management activities-derivative instruments: Commodity Contracts	$ 33,235	$ 31,405
Additional collateral to counterparties for energy related non-derivative instrument contracts	161,000
Commodity Contracts | Designated as Hedging Instruments
Derivative Accounting
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income	$ (4,000)
Arizona Public Service Company
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%

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Regulatory Matters - Four Corners and Cholla (Details) - APS $ in Millions			6 Months Ended
	Dec. 23, 2014 USD ($)	Dec. 30, 2013 USD ($) MW	Jun. 30, 2015 USD ($)
SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Ownership interest acquired		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1
Net receipt due to negotiation of alternate arrangement		$ 40.0
Capacity rights over the Arizona Transmission System assign to third-parties | MW		1,555
Capacity rights related to marketing and trading group for transmission of the additional power received assign to third-parties | MW		300
Four Corners cost deferral | SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Regulatory assets, non-current			$ 74.0
Regulatory noncurrent asset amortization period			10 years
Retired power plant costs
Business Acquisition [Line Items]
Net book value			$ 125.0

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 13,557	$ 7,604
Customer and other receivables	289,236	297,740
Accrued unbilled revenues	185,216	100,533
Allowance for doubtful accounts	(2,518)	(3,094)
Materials and supplies (at average cost)	231,101	218,889
Fossil fuel (at average cost)	43,196	37,097
Deferred income taxes	77,841	122,232
Income tax receivable (Note 5)	0	3,098
Assets from risk management activities (Note 7)	14,722	13,785
Deferred fuel and purchased power regulatory asset (Note 3)	0	6,926
Other regulatory assets (Note 3)	134,578	129,808
Other current assets	44,827	38,817
Total current assets	1,031,756	973,435
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	18,513	17,620
Nuclear decommissioning trust (Note 12)	723,582	713,866
Other assets	51,987	54,047
Total investments and other assets	794,082	785,533
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,926,594	15,543,063
Accumulated depreciation and amortization	(5,497,350)	(5,397,751)
Net	10,429,244	10,145,312
Construction work in progress	638,285	682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	119,320	121,255
Intangible assets, net of accumulated amortization	127,742	119,755
Nuclear fuel, net of accumulated amortization	156,608	125,201
Total property, plant and equipment	11,471,199	11,194,330
DEFERRED DEBITS
Regulatory assets (Note 3)	1,081,113	1,054,087
Assets for other postretirement benefits (Note 4)	168,755	152,290
Other	154,578	153,857
Total deferred debits	1,404,446	1,360,234
TOTAL ASSETS	14,701,483	14,313,532
CURRENT LIABILITIES
Accounts payable	326,119	295,211
Accrued taxes (Note 5)	155,812	140,613
Accrued interest	54,547	52,603
Common dividends payable	65,933	65,790
Short-term borrowings (Note 2)	157,500	147,400
Current maturities of long-term debt (Note 2)	102,723	383,570
Customer deposits	72,785	72,307
Liabilities from risk management activities (Note 7)	60,673	59,676
Deferred fuel and purchased power regulatory liability (Note 3)	16,209	0
Liabilities for asset retirements (Note 15)	28,543	32,462
Other regulatory liabilities (Note 3)	136,273	130,549
Other current liabilities	162,742	178,962
Total current liabilities	1,339,859	1,559,143
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	3,565,857	3,031,215
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,614,274	2,582,636
Regulatory liabilities (Note 3)	1,016,991	1,051,196
Liabilities for asset retirements (Note 15)	419,072	358,288
Liabilities for pension benefits (Note 4)	425,002	453,736
Liabilities from risk management activities (Note 7)	87,689	50,602
Customer advances	120,063	123,052
Coal mine reclamation	200,155	198,292
Deferred investment tax credit	176,389	178,607
Unrecognized tax benefits (Note 5)	14,311	19,377
Other	196,178	188,286
Total deferred credits and other	$ 5,270,124	$ 5,204,072
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 110,865,030 and 110,649,762 issued at respective dates	$ 2,526,945	$ 2,512,970
Treasury stock at cost; 53,559 and 78,400 shares at respective dates	(1,765)	(3,401)
Total common stock	2,525,180	2,509,569
Retained earnings	1,933,256	1,926,065
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(57,290)	(57,756)
Derivative instruments	(8,310)	(10,385)
Total accumulated other comprehensive loss	(65,600)	(68,141)
Total shareholders’ equity	4,392,836	4,367,493
Noncontrolling interests (Note 6)	132,807	151,609
Total equity	4,525,643	4,519,102
TOTAL LIABILITIES AND EQUITY	14,701,483	14,313,532
Arizona Public Service Company
CURRENT ASSETS
Cash and cash equivalents	7,973	4,515
Customer and other receivables	281,609	297,712
Accrued unbilled revenues	185,216	100,533
Allowance for doubtful accounts	(2,518)	(3,094)
Materials and supplies (at average cost)	231,101	218,889
Fossil fuel (at average cost)	43,196	37,097
Deferred income taxes	54,789	55,253
Assets from risk management activities (Note 7)	14,722	13,785
Deferred fuel and purchased power regulatory asset (Note 3)	0	6,926
Other regulatory assets (Note 3)	134,578	129,808
Other current assets	44,168	38,693
Total current assets	994,834	900,117
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)	18,513	17,620
Nuclear decommissioning trust (Note 12)	723,582	713,866
Other assets	33,976	33,362
Total investments and other assets	776,071	764,848
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	15,923,342	15,539,811
Accumulated depreciation and amortization	(5,494,236)	(5,394,650)
Net	10,429,106	10,145,161
Construction work in progress	636,927	682,807
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)	119,320	121,255
Intangible assets, net of accumulated amortization	127,587	119,600
Nuclear fuel, net of accumulated amortization	156,608	125,201
Total property, plant and equipment	11,469,548	11,194,024
DEFERRED DEBITS
Regulatory assets (Note 3)	1,081,113	1,054,087
Assets for other postretirement benefits (Note 4)	165,682	149,260
Unamortized debt issue costs	27,843	24,642
Other	125,694	128,026
Total deferred debits	1,400,332	1,356,015
TOTAL ASSETS	14,640,785	14,215,004
CURRENT LIABILITIES
Accounts payable	321,860	289,930
Accrued taxes (Note 5)	199,492	131,110
Accrued interest	54,314	52,358
Common dividends payable	65,900	65,800
Short-term borrowings (Note 2)	157,500	147,400
Current maturities of long-term debt (Note 2)	102,723	383,570
Customer deposits	72,785	72,307
Liabilities from risk management activities (Note 7)	60,673	59,676
Deferred fuel and purchased power regulatory liability (Note 3)	16,209	0
Liabilities for asset retirements (Note 15)	28,543	32,462
Other regulatory liabilities (Note 3)	136,273	130,549
Other current liabilities	132,800	167,302
Total current liabilities	1,349,072	1,532,464
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,601,294	2,571,365
Regulatory liabilities (Note 3)	1,016,991	1,051,196
Liabilities for asset retirements (Note 15)	419,072	358,288
Liabilities for pension benefits (Note 4)	397,160	424,508
Liabilities from risk management activities (Note 7)	87,689	50,602
Customer advances	120,063	123,052
Coal mine reclamation	200,155	198,292
Deferred investment tax credit	176,389	178,607
Unrecognized tax benefits (Note 5)	45,305	45,740
Other	159,574	144,823
Total deferred credits and other	$ 5,223,692	$ 5,146,473
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Total common stock	$ 178,162	$ 178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,982,150	1,968,718
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(37,341)	(37,948)
Derivative instruments	(8,310)	(10,385)
Total accumulated other comprehensive loss	(45,651)	(48,333)
Total shareholders’ equity	4,494,357	4,478,243
Noncontrolling interests (Note 6)	132,807	151,609
Total equity	4,627,164	4,629,852
Long-term debt less current maturities (Note 2)	3,440,857	2,906,215
Total capitalization	8,068,021	7,536,067
TOTAL LIABILITIES AND EQUITY	$ 14,640,785	$ 14,215,004

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Long-Term Debt and Liquidity Matters

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

Long-Term Debt and Liquidity Matters

Long-Term Debt and Liquidity Matters

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

Pinnacle West

Pinnacle West's $200 million revolving credit facility matures in May 2019.  At June 30, 2015, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the size of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At June 30, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

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

On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% Notes due May 15, 2015.

On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness.

On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

At June 30, 2015, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million facility that matures in May 2019.  APS may increase the size of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2015, APS had $158 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities.

See "Financial Assurances" in Note 8 for a discussion of APS’s separate outstanding letters of credit.

Debt Fair Value

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

	As of June 30, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,544		3,818		3,290		3,714
Total	$	3,669	$	3,943	$	3,415	$	3,839

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At June 30, 2015, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.3 billion, assuming APS’s total capitalization remains the same.

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 122,902	$ 132,458	$ 139,024	$ 148,224
Weighted average common shares outstanding - basic	110,986	110,565	110,958	110,546
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	474	437	468	379
Weighted average common shares outstanding — diluted	111,460	111,002	111,426	110,925
Earnings per average common share attributable to common shareholders -basic (in dollars per share)	$ 1.11	$ 1.20	$ 1.25	$ 1.34
Earnings per average common share attributable to common shareholders -diluted (in dollars per share)	$ 1.10	$ 1.19	$ 1.25	$ 1.34

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Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2015

Regulated Operations [Abstract]

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

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

	Six Months Ended   June 30,
	2015			2014
Beginning balance	$	7		$	21
Deferred fuel and purchased power costs — current period	(12		)	(1		)
Amounts charged to customers	(11		)	(19		)
Ending balance	$	(16	)	$	1

Schedule of regulatory assets

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

	Remaining Amortization Period	June 30, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Pension benefits	(a)	$	—	$	505	$	—	$	485
Income taxes — allowance for funds used during construction ("AFUDC") equity	2044	5		122		5		118
Deferred fuel and purchased power — mark-to-market (Note 7)	2018	53		62		51		46
Transmission vegetation management	2016	9		—		9		5
Coal reclamation	2026	—		6		—		7
Palo Verde VIEs (Note 6)	2046	—		26		—		35
Deferred compensation	2036	—		36		—		34
Deferred fuel and purchased power (b) (c)	2015	—		—		7		—
Tax expense of Medicare subsidy	2024	2		13		2		14
Loss on reacquired debt	2034	1		16		1		16
Income taxes — investment tax credit basis adjustment	2044	2		46		2		46
Pension and other postretirement benefits deferral	2015	—		—		4		—
Four Corners cost deferral	2024	7		67		7		70
Lost fixed cost recovery (b)	2016	45		—		38		—
Retired power plant costs	2033	10		131		10		136
Deferred property taxes	(d)	—		40		—		30
Other	Various	1		11		2		12
Total regulatory assets (e)		$	135	$	1,081	$	138	$	1,054

(a) This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues.  See Note 4 for further discussion.

(b) See "Cost Recovery Mechanisms" discussion above.

(c) Subject to a carrying charge.

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

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

Schedule of regulatory liabilities

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

	Remaining Amortization Period	June 30, 2015				December 31, 2014
		Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	44	$	245	$	31	$	273
Asset retirement obligations	2044	—		272		—		296
Renewable energy standard (b)	2017	29		20		25		23
Income taxes — change in rates	2043	1		71		—		72
Spent nuclear fuel	2047	3		68		5		66
Deferred gains on utility property	2019	2		7		2		8
Income taxes — deferred investment tax credit	2043	3		92		4		93
Deferred fuel and purchased power (b) (c)	2016	16		—		—		—
Demand side management (b)	2017	8		27		31		—
Other postretirement benefits	(d)	33		189		32		199
Other	Various	13		26		1		21
Total regulatory liabilities		$	152	$	1,017	$	131	$	1,051

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

(b) See "Cost Recovery Mechanisms" discussion above.

(c) Subject to a carrying charge.

(d) See Note 4.

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Long-Term Debt and Liquidity Matters - Narrative (Details)	May. 19, 2015 USD ($)	Jun. 30, 2015 USD ($) Facility	Jun. 26, 2015 USD ($)	May. 28, 2015 USD ($)	Jan. 12, 2015 USD ($)	Dec. 31, 2014 USD ($)
Debt Provisions
Total shareholder equity		$ 4,392,836,000				$ 4,367,493,000
Pinnacle West | Letter of Credit [Member] | Revolving credit facility that matures in May 2019
Long-Term Debt and Liquidity Matters
Outstanding letters of credit		0
Pinnacle West | Revolving Credit Facility | Revolving credit facility that matures in May 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility		200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		300,000,000
Outstanding borrowings		0
Pinnacle West | Commercial paper | Revolving credit facility that matures in May 2019
Long-Term Debt and Liquidity Matters
Maximum commercial paper support available under credit facility		200,000,000
Commercial paper		0
APS
Debt Provisions
Total shareholder equity		4,494,357,000				$ 4,478,243,000
APS | ACC
Debt Provisions
Total shareholder equity		4,500,000,000
Total capitalization		8,200,000,000
Dividend restrictions, shareholder equity required		$ 3,300,000,000
APS | ACC | Minimum
Debt Provisions
Required common equity ratio ordered by ACC (as a percent)		40.00%
APS | Arizona pollution control revenue refunding bond, 2009 series B, due 2029
Long-Term Debt and Liquidity Matters
Repurchased debt				$ 32,000,000
APS | Letter of Credit [Member]
Long-Term Debt and Liquidity Matters
Outstanding letters of credit		$ 76,000,000
APS | Letter of Credit [Member] | Revolving credit facilities maturing in 2018 and 2019
Long-Term Debt and Liquidity Matters
Outstanding letters of credit		0
APS | Revolving Credit Facility | Revolving credit facilities maturing in 2018 and 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility		1,000,000,000
Outstanding borrowings		$ 0
Number of line of credit facilities | Facility		2
APS | Revolving Credit Facility | Revolving credit facility maturing April 2018
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility		$ 500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		700,000,000
APS | Revolving Credit Facility | Revolving credit facility maturing May 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility		500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		700,000,000
APS | Commercial paper
Long-Term Debt and Liquidity Matters
Maximum commercial paper support available under credit facility		250,000,000
Commercial paper		$ 158,000,000
APS | Secured debt | Term loan facility maturing June 26, 2018
Long-Term Debt and Liquidity Matters
Debt issued			$ 50,000,000
APS | Senior Notes | 2.20% unsecured senior notes that mature on January 15, 2020
Long-Term Debt and Liquidity Matters
Debt issued					$ 250,000,000
Interest rate (as a percent)					2.20%
APS | Senior Notes | 3.15% unsecured senior notes that mature on May 15, 2025
Long-Term Debt and Liquidity Matters
Debt issued	$ 300,000,000
Interest rate (as a percent)	3.15%
Extinguishment of Debt, Amount	$ 300,000,000
APS | Senior Notes | 4.65% unsecured senior notes that mature on May 15, 2015
Long-Term Debt and Liquidity Matters
Interest rate (as a percent)	4.65%

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Nuclear Decommissioning Trusts

6 Months Ended

Jun. 30, 2015

Investments, Debt and Equity Securities [Abstract]

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities.  APS classifies investments in decommissioning trust funds as available for sale.  As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets.  See Note 11 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities.  The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2015 and December 31, 2014 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2015
Equity securities	$	314		$	160	$	—
Fixed income securities	414			13		(3		)
Net payables (a)	(4		)	—		—
Total	$	724		$	173	$	(3	)

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

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

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

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Realized gains	$	1		$	1		$	2		$	2
Realized losses	(1		)	(1		)	(2		)	(3		)
Proceeds from the sale of securities (a)	110			96			226			199

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2015 is as follows (dollars in millions):

	Fair Value
Less than one year	$	13
1 year – 5 years	111
5 years – 10 years	123
Greater than 10 years	167
Total	$	414