10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2016

OR

☐ 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  ☒   No ☐
ARIZONA PUBLIC SERVICE COMPANY	Yes  ☒   No ☐

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  ☒   No ☐
ARIZONA PUBLIC SERVICE COMPANY	Yes  ☒   No ☐

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 ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting company ☐

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  ☐   No ☒
ARIZONA PUBLIC SERVICE COMPANY	Yes  ☐   No ☒

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

PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of October 28, 2016: 111,306,107
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of October 28, 2016: 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	4
	Arizona Public Service Company	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	57
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	79
Item 4.	Controls and Procedures	79
Part II		80
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 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 Combined Notes to 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, 2015 ("2015 Form 10-K"), Part II, Item 1A of this report and in Part I, Item 2 — "Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, these factors include, but are not limited to:

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

• variations in demand for electricity, including those due to weather, seasonality, 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, ballot initiatives and regulation, including those relating to environmental requirements, regulatory policy, 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 and of debt and equity capital investment;

• 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, including 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, including regulation of greenhouse gas emissions;

• 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 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 2015 Form 10-K and in Part II, Item 1A of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures.  Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

2

PART I — FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

	Page
Pinnacle West Condensed Consolidated Statements of Income for Three and Nine Months Ended September 30, 2016 and 2015	4
Pinnacle West Condensed Consolidated Statements of Comprehensive Income for Three and Nine Months Ended September 30, 2016 and 2015	5
Pinnacle West Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	6
Pinnacle West Condensed Consolidated Statements of Cash Flows for Nine Months Ended September 30, 2016 and 2015	8
Pinnacle West Condensed Consolidated Statements of Changes in Equity for Nine Months Ended September 30, 2016 and 2015	9
APS Condensed Consolidated Statements of Income for Three and Nine Months Ended September 30, 2016 and 2015	10
APS Condensed Consolidated Statements of Comprehensive Income for Three and Nine Months Ended September 30, 2016 and 2015	11
APS Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	12
APS Condensed Consolidated Statements of Cash Flows for Nine Months Ended September 30, 2016 and 2015	14
APS Condensed Consolidated Statements of Changes in Equity for Nine Months Ended September 30, 2016 and 2015	15
Combined Notes to Condensed Consolidated Financial Statements	16
Note 1. Consolidation and Nature of Operations	16
Note 2. Long-Term Debt and Liquidity Matters	16
Note 3. Regulatory Matters	18
Note 4. Retirement Plans and Other Postretirement Benefits	29
Note 5. Palo Verde Sale Leaseback Variable Interest Entities	30
Note 6. Derivative Accounting	31
Note 7. Commitments and Contingencies	35
Note 8. Other Income and Other Expense	44
Note 9. Earnings Per Share	45
Note 10. Fair Value Measurements	45
Note 11. Nuclear Decommissioning Trusts	52
Note 12. New Accounting Standards	53
Note 13. Changes in Accumulated Other Comprehensive Loss	54
Note 14. Asset Retirement Obligations	55

3

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
OPERATING REVENUES	$	1,166,922		$	1,199,146		$	2,759,483		$	2,761,013
OPERATING EXPENSES
Fuel and purchased power	336,120			363,847			832,253			868,561
Operations and maintenance	217,568			220,449			703,042			646,358
Depreciation and amortization	120,428			125,625			362,977			369,313
Taxes other than income taxes	41,284			43,241			125,902			129,489
Other expenses	264			873			2,141			2,524
Total	715,664			754,035			2,026,315			2,016,245
OPERATING INCOME	451,258			445,111			733,168			744,768
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	10,194			7,645			31,079			26,214
Other income (Note 8)	71			139			385			549
Other expense (Note 8)	(5,205		)	(5,538		)	(12,085		)	(12,433		)
Total	5,060			2,246			19,379			14,330
INTEREST EXPENSE
Interest charges	51,293			49,342			154,886			146,069
Allowance for borrowed funds used during construction	(4,321		)	(3,518		)	(14,849		)	(12,056		)
Total	46,972			45,824			140,037			134,013
INCOME BEFORE INCOME TAXES	409,346			401,533			612,510			625,085
INCOME TAXES	141,446			139,555			209,102			214,873
NET INCOME	267,900			261,978			403,408			410,212
Less: Net income attributable to noncontrolling interests (Note 5)	4,873			4,862			14,620			14,072
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	263,027		$	257,116		$	388,788		$	396,140
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	111,416			111,036			111,363			110,984
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,100			111,616			111,987			111,490
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	2.36		$	2.32		$	3.49		$	3.57
Net income attributable to common shareholders — diluted	$	2.35		$	2.30		$	3.47		$	3.55
DIVIDENDS DECLARED PER SHARE	$	—		$	—		$	1.25		$	1.19

The accompanying notes are an integral part of the financial statements.

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
NET INCOME	$	267,900		$	261,978		$	403,408		$	410,212
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $18, $96, ($608) and ($392) for the respective periods	(29		)	(151		)	(595		)	(926		)
Reclassification of net realized loss, net of tax benefit of $500, $567, $691 and $1,490 for the respective periods	798			892			2,564			3,742
Pension and other postretirement benefits activity, net of tax expense of $504, $553, $709 and $1,345 for the respective periods	804			869			633			1,335
Total other comprehensive income	1,573			1,610			2,602			4,151
COMPREHENSIVE INCOME	269,473			263,588			406,010			414,363
Less: Comprehensive income attributable to noncontrolling interests	4,873			4,862			14,620			14,072
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	264,600		$	258,726		$	391,390		$	400,291

The accompanying notes are an integral part of the financial statements.

5

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	September 30, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	48,267		$	39,488
Customer and other receivables	325,029			274,691
Accrued unbilled revenues	150,531			96,240
Allowance for doubtful accounts	(3,608		)	(3,125		)
Materials and supplies (at average cost)	250,789			234,234
Fossil fuel (at average cost)	34,745			45,697
Income tax receivable	—			589
Assets from risk management activities (Note 6)	6,235			15,905
Deferred fuel and purchased power regulatory asset (Note 3)	8,132			—
Other regulatory assets (Note 3)	114,088			149,555
Other current assets	43,284			37,242
Total current assets	977,492			890,516
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 6)	—			12,106
Nuclear decommissioning trust (Note 11)	779,753			735,196
Other assets	68,977			52,518
Total investments and other assets	848,730			799,820
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	16,877,695			16,222,232
Accumulated depreciation and amortization	(5,895,765		)	(5,594,094		)
Net	10,981,930			10,628,138
Construction work in progress	1,118,666			816,307
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)	114,483			117,385
Intangible assets, net of accumulated amortization	96,789			123,975
Nuclear fuel, net of accumulated amortization	133,731			123,139
Total property, plant and equipment	12,445,599			11,808,944
DEFERRED DEBITS
Regulatory assets (Note 3)	1,212,150			1,214,146
Assets for other postretirement benefits (Note 4)	191,007			185,997
Other	130,748			128,835
Total deferred debits	1,533,905			1,528,978
TOTAL ASSETS	$	15,805,726		$	15,028,258

The accompanying notes are an integral part of the financial statements.

6

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	September 30,  2016			December 31, 2015
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	248,133		$	297,480
Accrued taxes	219,432			138,600
Accrued interest	46,124			56,305
Common dividends payable	—			69,363
Short-term borrowings (Note 2)	117,300			—
Current maturities of long-term debt (Note 2)	16,870			357,580
Customer deposits	78,262			73,073
Liabilities from risk management activities (Note 6)	45,175			77,716
Liabilities for asset retirements (Note 14)	11,852			28,573
Deferred fuel and purchased power regulatory liability (Note 3)	—			9,688
Other regulatory liabilities (Note 3)	104,313			136,078
Other current liabilities	222,257			197,861
Total current liabilities	1,109,718			1,442,317
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	4,145,366			3,462,391
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,941,559			2,723,425
Regulatory liabilities (Note 3)	998,349			994,152
Liabilities for asset retirements (Note 14)	458,628			415,003
Liabilities for pension benefits (Note 4)	401,680			480,998
Liabilities from risk management activities (Note 6)	58,343			89,973
Customer advances	98,779			115,609
Coal mine reclamation	220,269			201,984
Deferred investment tax credit	180,738			187,080
Unrecognized tax benefits	9,904			9,524
Other	190,258			186,345
Total deferred credits and other	5,558,507			5,404,093
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,220,370 and 111,095,402 issued at respective dates	2,552,979			2,541,668
Treasury stock at cost; 1,900 and 115,030 shares at respective dates	(130		)	(5,806		)
Total common stock	2,552,849			2,535,862
Retained earnings	2,342,643			2,092,803
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(36,960		)	(37,593		)
Derivative instruments	(5,186		)	(7,155		)
Total accumulated other comprehensive loss	(42,146		)	(44,748		)
Total shareholders’ equity	4,853,346			4,583,917
Noncontrolling interests (Note 5)	138,789			135,540
Total equity	4,992,135			4,719,457
TOTAL LIABILITIES AND EQUITY	$	15,805,726		$	15,028,258

The accompanying notes are an integral part of the financial statements.

7

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Nine Months Ended   September 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	403,408		$	410,212
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	422,851			428,121
Deferred fuel and purchased power	(46,185		)	(137		)
Deferred fuel and purchased power amortization	28,366			19,284
Allowance for equity funds used during construction	(31,079		)	(26,214		)
Deferred income taxes	194,915			168,071
Deferred investment tax credit	(6,342		)	9,542
Change in derivative instruments fair value	(278		)	(261		)
Changes in current assets and liabilities:
Customer and other receivables	(77,908		)	(107,263		)
Accrued unbilled revenues	(54,291		)	(61,736		)
Materials, supplies and fossil fuel	(4,438		)	(22,537		)
Income tax receivable	589			3,098
Other current assets	(11,665		)	1,994
Accounts payable	(57,237		)	(53,247		)
Accrued taxes	80,925			110,066
Other current liabilities	(12,383		)	16,952
Change in margin and collateral accounts — assets	517			(1,291		)
Change in margin and collateral accounts — liabilities	18,085			30,678
Change in unrecognized tax benefits	1,628			(9,276		)
Change in other long-term assets	(59,589		)	17,753
Change in other long-term liabilities	(24,839		)	(112,436		)
Net cash flow provided by operating activities	765,050			821,373
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,014,910		)	(778,700		)
Contributions in aid of construction	39,355			33,982
Allowance for borrowed funds used during construction	(14,848		)	(12,056		)
Proceeds from nuclear decommissioning trust sales	447,419			330,304
Investment in nuclear decommissioning trust	(449,129		)	(343,488		)
Other	(18,353		)	(2,830		)
Net cash flow used for investing activities	(1,010,466		)	(772,788		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151			600,000
Repayment of long-term debt	(353,560		)	(344,847		)
Short-term borrowing and payments — net	117,300			(90,400		)
Dividends paid on common stock	(203,115		)	(192,466		)
Common stock equity issuance - net of purchases	11,790			12,543
Distributions to noncontrolling interests	(11,372		)	(28,012		)
Other	1			—
Net cash flow provided by (used for) financing activities	254,195			(43,182		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	8,779			5,403
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	39,488			7,604
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	48,267		$	13,007

The accompanying notes are an integral part of the financial statements.

8

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(dollars in thousands)

	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
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		—				—			396,140			—			14,072			410,212
Other comprehensive income		—				—			—			4,151			—			4,151
Dividends on common stock		—				—			(131,818		)	—			—			(131,818		)
Issuance of common stock	250,868	16,049				—			—			—			—			16,049
Purchase of treasury stock (a)		—		(93,280	)	(6,096		)	—			—			—			(6,096		)
Reissuance of treasury stock for stock-based compensation and other		—		118,121		7,732			—			—			—			7,732
Capital activities by noncontrolling interests		—				—			—			—			(28,013		)	(28,013		)
Balance, September 30, 2015	110,900,630	$	2,529,019	(53,559	)	$	(1,765	)	$	2,190,387		$	(63,990	)	$	137,668		$	4,791,319
Balance, January 1, 2016	111,095,402	$	2,541,668	(115,030	)	$	(5,806	)	$	2,092,803		$	(44,748	)	$	135,540		$	4,719,457
Net income		—		—		—			388,788			—			14,620			403,408
Other comprehensive income		—				—			—			2,602			—			2,602
Dividends on common stock		—				—			(138,947		)	—			—			(138,947		)
Issuance of common stock	124,968	11,311				—			—			—			—			11,311
Purchase of treasury stock (a)		—		(71,962	)	(4,880		)	—			—			—			(4,880		)
Reissuance of treasury stock for stock-based compensation and other		—		185,092		10,556			(1		)	—			—			10,555
Capital activities by noncontrolling interests		—				—			—			—			(11,371		)	(11,371		)
Balance, September 30, 2016	111,220,370	$	2,552,979	(1,900	)	$	(130	)	$	2,342,643		$	(42,146	)	$	138,789		$	4,992,135

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

The accompanying notes are an integral part of the financial statements.

9

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
ELECTRIC OPERATING REVENUES	$	1,166,359		$	1,198,380		$	2,752,748		$	2,758,771
OPERATING EXPENSES
Fuel and purchased power	339,510			363,847			835,643			868,561
Operations and maintenance	209,366			216,011			681,789			633,989
Depreciation and amortization	120,013			125,592			362,492			369,234
Income taxes	148,945			148,543			225,239			232,454
Taxes other than income taxes	40,924			43,149			125,370			129,258
Total	858,758			897,142			2,230,533			2,233,496
OPERATING INCOME	307,601			301,238			522,215			525,275
OTHER INCOME (DEDUCTIONS)
Income taxes	5,753			5,678			9,289			10,809
Allowance for equity funds used during construction	10,194			7,645			31,079			26,214
Other income (Note 8)	567			650			6,924			1,999
Other expense (Note 8)	(3,776		)	(3,965		)	(12,956		)	(11,768		)
Total	12,738			10,008			34,336			27,254
INTEREST EXPENSE
Interest on long-term debt	46,970			44,011			142,692			134,265
Interest on short-term borrowings	2,401			3,460			6,408			6,339
Debt discount, premium and expense	1,195			1,218			3,529			3,455
Allowance for borrowed funds used during construction	(4,320		)	(3,492		)	(14,359		)	(12,019		)
Total	46,246			45,197			138,270			132,040
NET INCOME	274,093			266,049			418,281			420,489
Less: Net income attributable to noncontrolling interests (Note 5)	4,873			4,862			14,620			14,072
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	269,220		$	261,187		$	403,661		$	406,417

The accompanying notes are an integral part of the financial statements.

10

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
NET INCOME	$	274,093		$	266,049		$	418,281		$	420,489
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $18, $96, ($608) and ($392) for the respective periods	(29		)	(151		)	(595		)	(926		)
Reclassification of net realized loss, net of tax benefit of $500, $567, $691 and $1,490 for the respective periods	798			892			2,564			3,742
Pension and other postretirement benefits activity, net of tax expense of $501, $553, $657 and $1,275 for the respective periods	799			870			768			1,477
Total other comprehensive income	1,568			1,611			2,737			4,293
COMPREHENSIVE INCOME	275,661			267,660			421,018			424,782
Less: Comprehensive income attributable to noncontrolling interests	4,873			4,862			14,620			14,072
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	270,788		$	262,798		$	406,398		$	410,710

The accompanying notes are an integral part of the financial statements.

11

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	September 30, 2016			December 31, 2015
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	16,764,278		$	16,218,724
Accumulated depreciation and amortization	(5,808,259		)	(5,590,937		)
Net	10,956,019			10,627,787
Construction work in progress	1,092,895			812,845
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)	114,483			117,385
Intangible assets, net of accumulated amortization	96,634			123,820
Nuclear fuel, net of accumulated amortization	133,731			123,139
Total property, plant and equipment	12,393,762			11,804,976
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 11)	779,753			735,196
Assets from risk management activities (Note 6)	—			12,106
Other assets	48,471			34,455
Total investments and other assets	828,224			781,757
CURRENT ASSETS
Cash and cash equivalents	8,027			22,056
Customer and other receivables	323,036			274,428
Accrued unbilled revenues	150,531			96,240
Allowance for doubtful accounts	(3,608		)	(3,125		)
Materials and supplies (at average cost)	249,554			234,234
Fossil fuel (at average cost)	34,745			45,697
Assets from risk management activities (Note 6)	6,235			15,905
Deferred fuel and purchased power regulatory asset (Note 3)	8,132			—
Other regulatory assets (Note 3)	114,088			149,555
Other current assets	39,981			35,765
Total current assets	930,721			870,755
DEFERRED DEBITS
Regulatory assets (Note 3)	1,212,150			1,214,146
Assets for other postretirement benefits (Note 4)	187,616			182,625
Other	125,863			127,923
Total deferred debits	1,525,629			1,524,694
TOTAL ASSETS	$	15,678,336		$	14,982,182

The accompanying notes are an integral part of the financial statements.

12

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands) 

	September 30, 2016			December 31, 2015
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	2,413,153			2,148,493
Accumulated other comprehensive (loss):
Pension and other postretirement benefits	(19,174		)	(19,942		)
Derivative instruments	(5,186		)	(7,155		)
Total shareholder equity	4,946,651			4,679,254
Noncontrolling interests (Note 5)	138,789			135,540
Total equity	5,085,440			4,814,794
Long-term debt less current maturities (Note 2)	4,020,366			3,337,391
Total capitalization	9,105,806			8,152,185
CURRENT LIABILITIES
Short-term borrowings (Note 2)	83,300			—
Current maturities of long-term debt (Note 2)	16,870			357,580
Accounts payable	241,495			291,574
Accrued taxes	252,443			144,488
Accrued interest	45,762			56,003
Common dividends payable	—			69,400
Customer deposits	78,262			73,073
Liabilities from risk management activities (Note 6)	45,175			77,716
Liabilities for asset retirements (Note 14)	11,505			28,573
Deferred fuel and purchased power regulatory liability (Note 3)	—			9,688
Other regulatory liabilities (Note 3)	104,313			136,078
Other current liabilities	186,402			180,535
Total current liabilities	1,065,527			1,424,708
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,957,021			2,764,489
Regulatory liabilities (Note 3)	998,349			994,152
Liabilities for asset retirements (Note 14)	450,508			415,003
Liabilities for pension benefits (Note 4)	380,640			459,065
Liabilities from risk management activities (Note 6)	58,343			89,973
Customer advances	98,779			115,609
Coal mine reclamation	205,126			201,984
Deferred investment tax credit	180,738			187,080
Unrecognized tax benefits	37,266			35,251
Other	140,233			142,683
Total deferred credits and other	5,507,003			5,405,289
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
TOTAL LIABILITIES AND EQUITY	$	15,678,336		$	14,982,182

The accompanying notes are an integral part of the financial statements.

13

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Nine Months Ended   September 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	418,281		$	420,489
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	422,365			428,042
Deferred fuel and purchased power	(46,185		)	(137		)
Deferred fuel and purchased power amortization	28,366			19,284
Allowance for equity funds used during construction	(31,079		)	(26,214		)
Deferred income taxes	171,000			72,737
Deferred investment tax credit	(6,342		)	9,542
Change in derivative instruments fair value	(278		)	(261		)
Changes in current assets and liabilities:
Customer and other receivables	(75,961		)	(106,236		)
Accrued unbilled revenues	(54,291		)	(61,736		)
Materials, supplies and fossil fuel	(4,368		)	(22,537		)
Other current assets	(9,857		)	2,676
Accounts payable	(56,349		)	(52,919		)
Accrued taxes	107,955			215,524
Other current liabilities	(30,973		)	7,759
Change in margin and collateral accounts — assets	517			(1,291		)
Change in margin and collateral accounts — liabilities	18,085			30,678
Change in unrecognized tax benefits	1,628			(9,276		)
Change in other long-term assets	(54,051		)	16,955
Change in other long-term liabilities	(32,146		)	(111,121		)
Net cash flow provided by operating activities	766,317			831,958
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(992,735		)	(778,207		)
Contributions in aid of construction	39,355			33,982
Allowance for borrowed funds used during construction	(14,359		)	(12,019		)
Proceeds from nuclear decommissioning trust sales	447,419			330,304
Investment in nuclear decommissioning trust	(449,129		)	(343,488		)
Other	(14,016		)	(840		)
Net cash flow used for investing activities	(983,465		)	(770,268		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151			600,000
Short-term borrowings and payments — net	83,300			(90,400		)
Repayment of long-term debt	(353,560		)	(344,847		)
Dividends paid on common stock	(208,400		)	(197,600		)
Distributions to noncontrolling interests	(11,372		)	(28,012		)
Net cash flow provided by (used for) financing activities	203,119			(60,859		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	(14,029		)	831
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	22,056			4,515
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	8,027		$	5,346
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of refunds	$	10,533		$	5,504
Interest, net of amounts capitalized	$	144,984		$	141,216
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	90,069		$	36,718

The accompanying notes are an integral part of the financial statements.

14

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, 2015	71,264,947	$	178,162	$	2,379,696	$	1,968,718		$	(48,333	)	$	151,609		$	4,629,852
Net income		—		—		406,417			—			14,072			420,489
Other comprehensive income		—		—		—			4,293			—			4,293
Dividends on common stock		—		—		(131,800		)	—			—			(131,800		)
Other		—		—		1			—			—			1
Net capital activities by noncontrolling interests		—		—		—			—			(28,013		)	(28,013		)
Balance, September 30, 2015	71,264,947	$	178,162	$	2,379,696	$	2,243,336		$	(44,040	)	$	137,668		$	4,894,822
Balance, January 1, 2016	71,264,947	$	178,162	$	2,379,696	$	2,148,493		$	(27,097	)	$	135,540		$	4,814,794
Net income		—		—		403,661			—			14,620			418,281
Other comprehensive income		—		—		—			2,737			—			2,737
Dividends on common stock		—		—		(139,001		)	—			—			(139,001		)
Net capital activities by noncontrolling interests		—		—		—			—			(11,371		)	(11,371		)
Balance, September 30, 2016	71,264,947	$	178,162	$	2,379,696	$	2,413,153		$	(24,360	)	$	138,789		$	5,085,440

The accompanying notes are an integral part of the financial statements.

15

COMBINED 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, 4C Acquisition, LLC ("4CA"), 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 5 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.

Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.

Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2015 Form 10-K.

Supplemental Cash Flow Information

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

	Nine Months Ended   September 30,
	2016		2015
Cash paid during the period for:
Income taxes, net of refunds	$	2,562	$	2,692
Interest, net of amounts capitalized	146,691		143,116
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	91,315	$	36,718

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, to refinance indebtedness, and for other general corporate purposes.

16

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West

On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $200 million facility that matures in May 2021. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At September 30, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

On August 31, 2016, PNW entered into a $75 million364-day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At September 30, 2016, Pinnacle West had $34 million outstanding under the facility.

APS

During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. Interest rates are based on APS's senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

On May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021.

On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E.

On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A.

On August 1, 2016, APS repaid at maturity APS’s $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016.

On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016.

On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B.

17

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At September 30, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At September 30, 2016, APS had $83 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.

See "Financial Assurances" in Note 7 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 presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

	As of September 30, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125,000	$	125,000	$	125,000	$	125,000
APS	4,037,236		4,609,003		3,694,971		3,981,367
Total	$	4,162,236	$	4,734,003	$	3,819,971	$	4,106,367

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At September 30, 2016, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.7 billion, assuming APS’s total capitalization remains the same.

3. Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%).

18

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The principal provisions of the application are:

• a test year ended December 31, 2015, adjusted as described below;

• an original cost rate base of $6.8 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2015;

• the following proposed capital structure and costs of capital:

	Capital Structure		Cost of Capital
Long-term debt	44.2	%	5.13	%
Common stock equity	55.8	%	10.50	%
Weighted-average cost of capital			8.13	%

• a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

• a base rate for fuel and purchased power costs of $0.029882 per kilowatt-hour (“kWh”) based on estimated 2017 prices (a decrease from the current base fuel rate of $0.03207 per kWh);

• authorization to defer for potential future recovery its share of the construction costs associated with installing selective catalytic reduction equipment at the Four Corners Power Plant (estimated at approximately $400 million in direct costs). APS proposes that the rates established in this rate case be increased through a step mechanism beginning in 2019 to reflect these deferred costs;

• authorization to defer for potential future recovery in the Company’s next general rate case the construction costs APS incurs for its Ocotillo power plant modernization project, once the project reaches commercial operation. APS estimates the direct construction costs at approximately $500 million and that the new facility will be fully in service by early 2019;

• authorization to defer until the Company’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

• updates and modifications to four of APS’s adjustor mechanisms - the Power Supply Adjustor (“PSA”), the Lost Fixed Cost Recovery Mechanism (“LFCR”), the Transmission Cost Adjustor (“TCA”) and the Environmental Improvement Surcharge (“EIS”);

• a number of proposed rate design changes for residential customers, including:

◦ change the on-peak time of use period from 12 p.m. - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;

◦ reduce the difference in the on- and off-peak energy price and lower all energy charges;

◦ offer four rate plan options, three of which have demand charges and a fourth that is available to non-partial requirements customers using less than 600 kWh on average per month; and

19

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

◦ modify the current net metering tariff to provide for a credit at the retail rate for the portion of generation by rooftop solar customers that offsets their own load, and for a credit for excess energy delivered to the grid at an export rate.

• proposed rate design changes for commercial customers, including an aggregation rider that allows certain large customers to qualify for a reduced rate, an extra-high load factor rate schedule for certain customers, and an economic development rate offering for new loads meeting certain criteria.

The Company requested that the increase become effective July 1, 2017.  On July 22, 2016, the administrative law judge set a procedural schedule for the rate proceedings. The ACC staff and interveners will begin filing their direct testimony on December 21, 2016, and the hearing will commence on March 22, 2017. The Commission staff supports completing the case within 12 months. APS cannot predict the outcome of its request.

Prior Rate Case Filing

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 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;

20

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

• 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 an LFCR rate mechanism to support energy efficiency and distributed renewable generation;

• Modifications to the 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");

• 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.

In December of 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who

21

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

cannot easily install solar through transactions with third parties. The second stage of the program, which includes an additional 2 MW of rooftop solar and energy storage, will place two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and is planned to be in operation by the end of 2016.  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, 2015, APS filed its 2016 RES Implementation Plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules.

In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the United States Environmental Protection Agency ("EPA").  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  APS cannot predict the outcome of this proceeding.

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. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from 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. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

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. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology.

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

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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 rulemaking has not been initiated and there has been no additional action on the draft to date. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others.

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 2016 and 2015 (dollars in thousands):

	Nine Months Ended   September 30,
	2016			2015
Beginning balance	$	(9,688	)	$	6,925
Deferred fuel and purchased power costs — current period	46,185			137
Amounts charged to customers	(28,365		)	(19,284		)
Ending balance	$	8,132		$	(12,222	)

The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh.  On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.

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

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

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.

Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million 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, 2016.

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.

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. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two months delay in implementation did not have an adverse effect on APS.

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

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electric 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 electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 

On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, an Administrative Law Judge (the "ALJ") issued a recommendation in the docket concerning the value and cost of distributed generation. The ALJ recommended a change to how customers are compensated for energy that they export from rooftop solar systems. Instead of retail rate net metering, the ALJ recommended that the amount of compensation be established by using both an avoided cost calculation and a grid-scale solar resource proxy calculation that would be updated in subsequent utility rate cases. The ALJ recommended that the change to how APS pays for exported rooftop solar energy apply only to those customers who apply to interconnect their distributed generation systems after a decision in APS’s currently pending rate case. The ALJ found rooftop solar customers to be partial requirements customers, but recommended that whether rooftop solar customers should be placed into a separate customer class for purposes of ratemaking be decided in individual utility rate cases. Exceptions to the ALJ recommendation are due November 15, 2016. On December 13, 2016, the ACC will discuss at an open meeting the ALJ recommendation concerning the value and cost of distributed generation.  APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company ("TEP") both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015 and February 23, 2016, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS actively participated in the related hearings held in March 2016. On August 18, 2016, the ACC issued a decision which ordered that net metering be considered in a separate, phase 2 of the UNS Electric, Inc. rate case to occur after the ACC decides issues raised in the separate, generic docket concerning the value and cost of distributed generation discussed above. APS has also intervened in the upcoming TEP rate case. On June 24, 2016, APS filed testimony in the TEP rate case in support of the TEP proposed rate design changes. In August 2016, the ACC also bifurcated the TEP rate case into two phases, the first of which will address revenue requirements and other traditional rate case issues while the second will address net metering issues. The outcomes of these proceedings will not directly impact our financial position.

Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB")

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

System Benefits Charge

The 2012 Settlement Agreement  provides that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016.  Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge.  The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through year-to-date 2016. The subpoenas request information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from company personnel having knowledge of the material, including the Chief Executive Officer, on October 6, 2016.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas, or alternatively stay APS’ obligations to comply with the subpoenas and decline to decide APS’ motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. APS and Pinnacle West cannot predict the outcome of this matter.

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 $65 million as of September 30, 2016 and is being amortized in rates over a total of 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 is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter will be resolved.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. 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. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and is seeking recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($117 million as of September 30, 2016), 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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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities

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

	Amortization Through	September 30, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	608,312	$	—	$	619,223
Retired power plant costs	2033	9,913		120,072		9,913		127,518
Income taxes — allowance for funds used during construction ("AFUDC") equity	2046	5,419		151,451		5,495		133,712
Deferred fuel and purchased power — mark-to-market (Note 6)	2019	30,748		53,350		71,852		69,697
Deferred fuel and purchased power (c) (e)	2017	8,132		—		—		—
Four Corners cost deferral	2024	6,689		58,566		6,689		63,582
Income taxes — investment tax credit basis adjustment	2045	1,852		46,699		1,766		48,462
Lost fixed cost recovery (b)	2017	55,297		—		45,507		—
Palo Verde VIEs (Note 5)	2046	—		18,620		—		18,143
Deferred compensation	2036	—		36,071		—		34,751
Deferred property taxes	(c)	—		67,547		—		50,453
Loss on reacquired debt	2034	1,592		16,521		1,515		16,375
Tax expense of Medicare subsidy	2024	1,512		10,774		1,520		12,163
Transmission vegetation management	2016	—		—		4,543		—
Mead-Phoenix transmission line CIAC	2050	332		10,791		332		11,040
Transmission cost adjustor (b)	2018	—		4,687		—		2,942
Coal reclamation	2026	418		5,286		418		6,085
Other	Various	316		3,403		5		—
Total regulatory assets (d)		$	122,220	$	1,212,150	$	149,555	$	1,214,146

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

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

(e) Subject to a carrying charge.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Amortization Through	September 30, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Asset retirement obligations	2057	$	—	$	305,862	$	—	$	277,554
Removal costs	(a)	27,626		237,885		39,746		240,367
Other postretirement benefits	(d)	33,294		146,988		34,100		179,521
Income taxes — deferred investment tax credit	2045	3,774		93,578		3,604		97,175
Income taxes — change in rates	2046	1,771		70,233		1,113		72,454
Spent nuclear fuel	2047	—		71,884		3,051		67,437
Renewable energy standard (b)	2017	28,921		1,091		43,773		4,365
Demand side management (b)	2017	4,261		21,863		6,079		19,115
Sundance maintenance	2030	—		14,885		—		13,678
Deferred fuel and purchased power (b) (c)	2017	—		—		9,688		—
Deferred gains on utility property	2019	2,063		9,335		2,062		6,001
Transmission cost adjustor (b)	2017	2,077		—		—		—
Four Corners coal reclamation	2031	—		17,213		—		8,920
Other	Various	526		7,532		2,550		7,565
Total regulatory liabilities		$	104,313	$	998,349	$	145,766	$	994,152

(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 Postretirement 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 the plan changes, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $140 million of the other postretirement benefit trust assets into a new trust 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 completed amortizing these costs as of June 30, 2015. We amortized approximately $2 million and $4 million for the three and nine months ended September 30, 2015, respectively.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 thousands):

	Pension Benefits												Other Benefits
	Three Months Ended   September 30,						Nine Months Ended   September 30,						Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
Service cost — benefits earned during the period	$	13,448		$	14,907		$	40,344		$	44,721		$	3,748		$	4,207		$	11,245		$	12,620
Interest cost on benefit obligation	32,912			30,996			98,735			92,987			7,430			7,026			22,291			21,077
Expected return on plan assets	(43,477		)	(44,808		)	(130,429		)	(134,424		)	(9,123		)	(9,214		)	(27,371		)	(27,641		)
Amortization of:
Prior service cost	132			148			395			446			(9,471		)	(9,492		)	(28,413		)	(28,476		)
Net actuarial loss	10,179			7,764			30,538			23,292			1,147			1,220			3,442			3,661
Net periodic benefit cost	$	13,194		$	9,007		$	39,583		$	27,022		$	(6,269	)	$	(6,253	)	$	(18,806	)	$	(18,759	)
Portion of cost charged to expense	$	6,476		$	4,433		$	19,427		$	15,653		$	(3,077	)	$	(3,078	)	$	(9,230	)	$	(7,348	)

Contributions

We have made voluntary contributions of $100 million to our pension plan year-to-date in 2016. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period. We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.

5. 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. APS will retain 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 $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 period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms 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.  Predominantly due to the lease terms, 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, resulting in an increase in net income for the three and nine months ended September 30, 2016 of $5 million and $15 million, respectively, and for the three and nine months ended September 30, 2015 of $5 million and

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

$14 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at September 30, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):

	September 30, 2016		December 31, 2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	114,483	$	117,385
Equity — Noncontrolling interests	138,789		135,540

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.

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 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 were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $289 million beginning in 2016, and up to $456 million over the lease terms.

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.

6. 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.

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 10 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

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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 September 30, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	1,630	GWh
Gas	193	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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Financial Statement Location	Three Months Ended   September 30,						Nine Months Ended   September 30,
Commodity Contracts		2016			2015			2016			2015
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	(47	)	$	(247	)	$	13		$	(534	)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(1,298		)	(1,459		)	(3,255		)	(5,232		)

(a) During the three and nine months ended September 30, 2016 and 2015, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

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

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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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Financial Statement Location	Three Months Ended   September 30,						Nine Months Ended September 30,
Commodity Contracts		2016			2015			2016			2015
Net gain recognized in income	Operating revenues	$	41		$	560		$	524		$	445
Net loss recognized in income	Fuel and purchased power (a)	(35,103		)	(50,909		)	(5,145		)	(85,099		)
Total		$	(35,062	)	$	(50,349	)	$	(4,621	)	$	(84,654	)

(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 September 30, 2016 and December 31, 2015, include gross liabilities of $2 million and $3 million, respectively, of derivative instruments designated as hedging instruments.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2016 and December 31, 2015.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance Sheet
Current assets	$	24,894		$	(18,816	)	$	6,078		$	157		$	6,235
Investments and other assets	4,146			(4,146		)	—			—			—
Total assets	29,040			(22,962		)	6,078			157			6,235
Current liabilities	(59,586		)	18,816			(40,770		)	(4,405		)	(45,175		)
Deferred credits and other	(62,489		)	4,146			(58,343		)	—			(58,343		)
Total liabilities	(122,075		)	22,962			(99,113		)	(4,405		)	(103,518		)
Total	$	(93,035	)	$	—		$	(93,035	)	$	(4,248	)	$	(97,283	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $4,405, and cash margin provided to counterparties of $157.

As of December 31, 2015: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	37,396		$	(22,163	)	$	15,233		$	672		$	15,905
Investments and other assets	15,960			(3,854		)	12,106			—			12,106
Total assets	53,356			(26,017		)	27,339			672			28,011
Current liabilities	(113,560		)	40,223			(73,337		)	(4,379		)	(77,716		)
Deferred credits and other	(93,827		)	3,854			(89,973		)	—			(89,973		)
Total liabilities	(207,387		)	44,077			(163,310		)	(4,379		)	(167,689		)
Total	$	(154,031	)	$	18,060		$	(135,971	)	$	(3,707	)	$	(139,678	)

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

(b) Includes cash collateral provided to counterparties of $18,060.

(c) Represents cash collateral and cash 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 $4,379, and cash margin provided to counterparties of $672.

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Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of September 30, 2016 we have no counterparties with positive exposures of greater than 10% of risk management assets. 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 September 30, 2016 (dollars in thousands):

	September 30, 2016
Aggregate fair value of derivative instruments in a net liability position	$	122,075
Cash collateral posted	—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	61,177

(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 $149 million if our debt credit ratings were to fall below investment grade.

7. 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 second 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 sought to recover damages incurred

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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's 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 the amount of reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016.

APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2016, in the amount $11.3 million (APS’s share is $3.3 million) and payment is expected in the second quarter of 2017.

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 $13 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 $18.9 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 $111.1 million, with a maximum annual retrospective premium assessment of approximately $16.6 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 $2.8 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 $23.8 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 $64 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

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Contractual Obligations

There have been no material changes, as of September 30, 2016, outside the normal course of business in contractual obligations from the information provided in our 2015 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

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 ("RI/FS").  The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by June 2017. 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.  APS responded to ADEQ on May 4, 2015. 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.  On March 2, 2016, the United States Court of Appeals for the Ninth Circuit

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unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016.

Environmental Matters

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

Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners and the Navajo Generating Station ("Navajo Plant"). EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. EPA is currently in the process of considering a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility.

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 Electric Company ("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. 4CA, a wholly-owned subsidiary of Pinnacle West, purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC provided notice of its intent to exercise the option. 4CA is negotiating a definitive purchase agreement with NTEC for the purchase by NTEC of the 7% interest. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

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 original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $100 million(excluding costs related to Cholla Unit 2, which was closed on October 1, 2015), 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 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

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future because retiring and/or 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 rulemaking 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 October 16, 2015, ADEQ issued the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program.  The proposed rule was published in the Federal Register on July 19, 2016 and the public commenting period for this proposal ended on September 2, 2016. APS and various other parties submitted comments in support of EPA's proposal, while Sierra Club submitted comments in opposition. Once EPA’s action is finalized, there may be judicial petitions for review of EPA’s final action filed in the Ninth Circuit Court of Appeals.  APS cannot predict at this time whether such petitions will be filed or if they will be successful.

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 $8 million for Cholla(excluding costs related to Cholla Unit 2, which was closed on October 1, 2015). 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. Litigation concerning the rules, including supplemental analyses EPA has prepared in support of the MATS regulation, is ongoing. These proceedings do not materially impact APS.  Regardless of the results from further judicial or administrative proceedings concerning the MATS rulemaking, 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.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is approximately in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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. Additionally, the CCR rule requires on-going groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions. Because the initial monitoring at these plants is not yet complete, at the present time expenditures related to potential corrective actions cannot be reasonably estimated.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for existing, new, modified, and reconstructed electric generating units ("EGUs"). EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO₂ performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal.

With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO₂ emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below.

Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ reports that it is continuing to assess its options while completing outreach and soliciting feedback from stakeholders. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation.

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The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such a delay.

With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances.

As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation.

Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material.

Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes.

In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, and additional information or considerations may arise that change our expectations.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and 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.

Federal Agency Environmental Lawsuit Related to Four Corners

On December 21, 2015, several environmental groups filed a notice of intent to sue with Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies under the Endangered Species Act (“ESA”) alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the United States Department of the Interior's ("DOI's") review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners.  This review process also required separate environmental impact evaluations under the National Environmental Policy Act (“NEPA”) and culminated in the issuance of a Record of Decision justifying the agency action extending the life of the plant and the adjacent mine. 

On April 20, 2016, the same environmental groups followed through with their notice of intent to sue by filing a lawsuit against OSM and other DOI federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  Expandingupon the December 2015 ESA notice, the lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. The court's consideration of this motion could affect the schedule for this litigation. We cannot predict the outcome of this matter or its potential effect on Four Corners.

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") 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 in the amount of $0.8 million and immediately filed a refund claim with respect to that partial payment in August 2013.  The NMTRD 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 NMTRD filed an appeal of the decision on August 31, 2015.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above is approximately $0.8 million.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of September 30, 2016, standby letters of credit totaled $52 million and will expire in 2016 and 2017. As of September 30, 2016, surety bonds expiring through 2019 totaled $150 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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 September 30, 2016. Effective July 6, 2016, Pinnacle West has issued two parental guarantees for 4CArelating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.

Peabody Bankruptcy

On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri.  Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona.  APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement.  

On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleges that the Buyers have breached the Agreement. Peabody requests substantial, but unspecified, monetary damages from the Buyers.  Peabody and the Buyers have agreed to pursue non-binding mediation, failing which a trial is expected to begin in February 2017.  There is insufficient information at this time to reasonably estimate any possible loss or range of loss to the Company.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Other income:
Interest income	$	65		$	127		$	370		$	422
Investment gains — net	—			—			13			—
Miscellaneous	6			12			2			127
Total other income	$	71		$	139		$	385		$	549
Other expense:
Non-operating costs	$	(2,502	)	$	(2,328	)	$	(6,636	)	$	(6,529	)
Investment losses — net	(450		)	(563		)	(1,508		)	(1,708		)
Miscellaneous	(2,253		)	(2,647		)	(3,941		)	(4,196		)
Total other expense	$	(5,205	)	$	(5,538	)	$	(12,085	)	$	(12,433	)

The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Other income:
Interest income	$	—		$	32		$	181		$	105
Gain on disposition of property	183			(58		)	5,504			627
Miscellaneous	384			676			1,239			1,267
Total other income	$	567		$	650		$	6,924		$	1,999
Other expense:
Non-operating costs (a)	$	(2,714	)	$	(2,248	)	$	(7,398	)	$	(6,643	)
Loss on disposition of property	36			(327		)	(1,048		)	(934		)
Miscellaneous	(1,098		)	(1,390		)	(4,510		)	(4,191		)
Total other expense	$	(3,776	)	$	(3,965	)	$	(12,956	)	$	(11,768	)

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

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and nine months ended September 30, 2016 and 2015 (in thousands, except per share amounts):

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2016		2015		2016		2015
Net income attributable to common shareholders	$	263,027	$	257,116	$	388,788	$	396,140
Weighted average common shares outstanding — basic	111,416		111,036		111,363		110,984
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	684		580		624		506
Weighted average common shares outstanding — diluted	112,100		111,616		111,987		111,490
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	2.36	$	2.32	$	3.49	$	3.57
Net income attributable to common shareholders — diluted	$	2.35	$	2.30	$	3.47	$	3.55

10. 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, exchange traded mutual funds, 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.  

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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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires instruments valued using NAV, as a practical expedient, to no longer be classified within the fair value hierarchy. As such, instruments valued using NAV, as a practical expedient, are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments.  See Note 7 in the 2015 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.

Coal Reclamation Trust Investments

The coal reclamation trust holds cash equivalent investments in money market funds that are valued using quoted prices in active markets, and are reported within Level 1.

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

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds.  We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled 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 funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, 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.

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. 

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 11 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at September 30, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at September 30, 2016
Assets
Cash equivalents	$	40,075	$	—		$	—		$	—			$	40,075
Coal reclamation trust - Cash equivalents (b)	14,749		—			—			—				14,749
Risk management activities — derivative instruments:
Commodity contracts	—		14,198			14,835			(22,798		)	(c)	6,235
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			340,436			(d)	340,436
Fixed income securities:
Cash and cash equivalent funds	—		—			—			5,032			(e)	5,032
U.S. Treasury	101,394		—			—			—				101,394
Corporate debt	—		112,923			—			—				112,923
Mortgage-backed securities	—		112,485			—			—				112,485
Municipal bonds	—		82,371			—			—				82,371
Other	—		25,112			—			—				25,112
Subtotal nuclear decommissioning trust	101,394		332,891			—			345,468				779,753
Total	$	156,218	$	347,089		$	14,835		$	322,670			$	840,812
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(67,692	)	$	(54,377	)	$	18,551		(c)	$	(103,518	)

(a) Primarily consists of long-dated electricity contracts.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets.

(c) Represents counterparty netting, margin and collateral. See Note 6.

(d) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.

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

The following table presents the fair value at December 31, 2015, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	22,992		$	30,364		$	(25,345	)	(b)	$	28,011
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			314,957			(c)	314,957
Fixed income securities:
Cash and cash equivalent funds	12,260		—			—			(335		)	(d)	11,925
U.S. Treasury	117,245		—			—			—				117,245
Corporate debt	—		96,243			—			—				96,243
Mortgage-backed securities	—		99,065			—			—				99,065
Municipal bonds	—		72,206			—			—				72,206
Other	—		23,555			—			—				23,555
Subtotal nuclear decommissioning trust	129,505		291,069			—			314,622				735,196
Total	$	129,505	$	314,061		$	30,364		$	289,277			$	763,207
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(144,044	)	$	(63,343	)	$	39,698		(b)	$	(167,689	)

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

(b) Represents counterparty netting, margin and collateral. See Note 6.

(c) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.

(d) 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,

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2016 and December 31, 2015 for these instruments include electricity 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 September 30, 2016 and December 31, 2015:

	September 30, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	13,726	$	36,438	Discounted cash flows	Electricity forward price (per MWh)	$18.84 - $39.44	$	29.30
Option Contracts (b)	—		1,153		Option model	Electricity forward price (per MWh)	$30.40	$	30.40
						Electricity price volatilities	86%	86		%
						Natural gas price volatilities	42%	42		%
Natural Gas:
Forward Contracts (a)	1,109		16,786		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.43 - $3.22	$	2.73
Total	$	14,835	$	54,377

(a) Includes swaps and physical and financial contracts.

(b) The remaining option contract expired on October 1, 2016; therefore there are no ranges for price and volatilities.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2015 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	24,543	$	54,679	Discounted cash flows	Electricity forward price (per MWh)	$15.92 - $40.73	$	26.86
Option Contracts (b)	—		5,628		Option model	Electricity forward price (per MWh)	$23.87 - $44.13	$	33.91
						Electricity price volatilities	40% - 59%	52		%
						Natural gas price volatilities	32% - 40%	35		%
Natural Gas:
Forward Contracts (a)	5,821		3,036		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.18 - $3.14	$	2.61
Total	$	30,364	$	63,343

(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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
Commodity Contracts	2016			2015			2016			2015
Net derivative balance at beginning of period	$	(32,380	)	$	(42,945	)	$	(32,979	)	$	(41,386	)
Total net gains (losses) realized/unrealized:
Included in OCI	(10		)	(207		)	94			(444		)
Deferred as a regulatory asset or liability	(13,499		)	(5,837		)	(21,103		)	(10,771		)
Settlements	5,424			7,572			11,691			12,424
Transfers into Level 3 from Level 2	1,343			(526		)	1,725			(4,494		)
Transfers from Level 3 into Level 2	(420		)	1,305			1,030			4,033
Net derivative balance at end of period	$	(39,542	)	$	(40,638	)	$	(39,542	)	$	(40,638	)
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

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.  See Note 2 for our long-term debt fair values.

11. 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 10 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities.  The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2016 and December 31, 2015 (dollars in thousands):

	Fair Value		Total Unrealized Gains		Total Unrealized Losses
September 30, 2016
Equity securities	$	340,436	$	176,495	$	(3	)
Fixed income securities	434,285		20,804		(465		)
Net receivables (a)	5,032		—		—
Total	$	779,753	$	197,299	$	(468	)

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2015
Equity securities	$	314,957		$	157,098	$	(115	)
Fixed income securities	420,574			11,955		(2,645		)
Net payables (a)	(335		)	—		—
Total	$	735,196		$	169,053	$	(2,760	)

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

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Realized gains	$	4,033		$	1,919		$	8,753		$	4,374
Realized losses	(3,345		)	(2,106		)	(6,481		)	(4,156		)
Proceeds from the sale of securities (a)	156,825			104,525			447,419			330,304

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2016 is as follows (dollars in thousands):

	Fair Value
Less than one year	$	8,429
1 year – 5 years	134,200
5 years – 10 years	102,835
Greater than 10 years	188,821
Total	$	434,285

12.    New Accounting Standards

In May 2014, a new revenue recognition accounting standard was issued. This standard 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. Since the issuance of the new revenue standard, additional guidance has been issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. 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. We are currently evaluating the new standard, and related amendments, and the impacts it may have on our financial statements.

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new guidance will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The

53

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

new standard will be effective for us on January 1, 2019, with early application permitted. The guidance must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In March 2016, new stock compensation accounting guidance was issued that modifies the accounting for employee share-based payments. The new guidance will require all tax benefits and deficiencies arising from share-based payments to be recognized in net income, modifies the tax withholding threshold for awards to qualify for equity classification, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. The new guidance is effective for us on January 1, 2017, with early application permitted. Certain aspects of the guidance must be adopted using a prospective approach and other aspects will be adopted using a retrospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In June 2016, new accounting guidance was issued that amends the measurement of credit losses on certain financial instruments. The new guidance will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

13.Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Balance at beginning of period	$	(43,719	)	$	(65,600	)	$	(44,748	)	$	(68,141	)
Derivative Instruments
OCI (loss) before reclassifications	(29		)	(151		)	(595		)	(926		)
Amounts reclassified from accumulated other comprehensive loss (a)	798			892			2,564			3,742
Net current period OCI (loss)	769			741			1,969			2,816
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	—			—			(1,585		)	(969		)
Amounts reclassified from accumulated other comprehensive loss (b)	804			869			2,218			2,304
Net current period OCI (loss)	804			869			633			1,335
Balance at end of period	$	(42,146	)	$	(63,990	)	$	(42,146	)	$	(63,990	)

(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 6.

(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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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Balance at beginning of period	$	(25,928	)	$	(45,651	)	$	(27,097	)	$	(48,333	)
Derivative Instruments
OCI (loss) before reclassifications	(29		)	(151		)	(595		)	(926		)
Amounts reclassified from accumulated other comprehensive loss (a)	798			892			2,564			3,742
Net current period OCI (loss)	769			741			1,969			2,816
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	—			—			(1,521		)	(927		)
Amounts reclassified from accumulated other comprehensive loss (b)	799			870			2,289			2,404
Net current period OCI (loss)	799			870			768			1,477
Balance at end of period	$	(24,360	)	$	(44,040	)	$	(24,360	)	$	(44,040	)

(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 6.

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

14. Asset Retirement Obligations

In the second quarter of 2016, APS recognized an asset retirement obligation (“ARO”) for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million.

In the third quarter of 2016, 4CA acquired El Paso Electric’s share of Four Corners Units 4 & 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million.

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COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2016 (dollars in thousands): 

Asset retirement obligations at January 1, 2016	$	443,576
Changes attributable to:
Accretion expense	19,868
Settlements	(11,891		)
Newly incurred or acquired liabilities	18,927
Asset retirement obligations at September 30, 2016	$	470,480

Decommissioning activities for Four Corners Units 1-3 began in January 2014. Decommissioning activities for Cholla Ash Ponds began in January 2015. Thus, $12 million of the total asset retirement obligation of $470 million at September 30, 2016, 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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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 Combined 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 2015 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.

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"), and EPA finalized its proposal on August 3, 2015. 

EPA’s nationwide CO₂ emissions reduction goal is 32% below 2005 emission levels.  As finalized for the state of Arizona and the Navajo Nation, compliance with the Clean Power Plan could involve a shift in generation from coal to natural gas and renewable generation.  Until implementation plans for these jurisdictions are finalized, we are unable to determine the actual impacts to APS.  (See Note 7 for information regarding challenges to the legality of the Clean Power Plan and a court-ordered stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations.) APS continually analyzes its long-range capital management plans to assess the potential effects of these changes, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to continue participation in such plants.

Cholla

On September 11, 2014, APS announced that it would close its 260 MW Unit 2 at Cholla 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 7 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 emissions control equipment. APS closed Unit 2 on October 1, 2015.

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Four Corners

Asset Purchase Agreement and Coal Supply Matters.  On December 30, 2013, APS purchased SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The final purchase price for the interest was approximately $182 million. In connection with APS’s prior 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 has intervened and is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed below. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter will be resolved.

Concurrently with the closing of the SCE transaction described above, 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 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 through 2016. Also occurring concurrently with the closing, the Four Corners’ co-owners executed the 2016 Coal Supply Agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031. 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 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 is immaterial in amount, and the purchaser will assume El Paso's reclamation and decommissioning obligations associated with the 7% interest. 4CA, a wholly-owned subsidiary of Pinnacle West, purchased the El Paso interest on July 6, 2016.

NTEC has the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. 4CA is negotiating a definitive purchase agreement with NTEC for the purchase by NTEC of the 7% interest. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not purchase the interest.

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 required the approval of the DOI, as did a related federal rights-of-way grant.  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 justifying the agency action extending the life of the plant and the adjacent mine.  

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other DOI federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC filed a motion to intervene for the purpose of dismissing the lawsuit based on

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NTEC's tribal sovereign immunity. The court's consideration of this motion could affect the schedule for this litigation. We cannot predict the outcome of this matter or its potential effect on Four Corners.

Natural Gas.  APS has six natural gas power plants located throughout Arizona, including Ocotillo. Ocotillo is a 330 MW 4-unit gas plant located in the metropolitan Phoenix area.  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, with completion targeted by summer 2019.  (See Note 3 for proposed rate recovery in our current retail rate case filing.) APS completed a competitive solicitation process in which the Ocotillo project was evaluated against other alternatives.  Consistent with the independent monitor’s report, the Ocotillo project was selected as the best alternative. APS must finalize the permitting process, including any EPA Environmental Appeals Board ("EAB") reviews, before construction can begin. On April 21, 2016, the Sierra Club filed a petition with the EAB to review the Prevention of Significant Deterioration ("PSD") permit issued by Maricopa County, Arizona for the Ocotillo project. On September 1, 2016, the EAB issued a decision regarding the petition for review that denied Sierra Club's request to remand the PSD permit. On September 9, 2016, Maricopa County issued a final permit decision based on the EAB review that finalizes the PSD authorization to construct the Ocotillo modernization project.

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 2018, along with other transmission costs for upgrades and replacements.  APS is also working to establish and expand advanced 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 manage their energy usage, minimize system outage durations and frequency, enable customer choice for behind-the-meter technologies, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions.

Energy Imbalance Market. In 2015, APS and the California Independent System Operator ("CAISO"), the operator for the majority of California's transmission grid, signed an agreement for APS to begin participation in the Energy Imbalance Market (“EIM”). APS's participation in the EIM began on October 1, 2016.  The EIM allows for rebalancing supply and demand in 15-minute blocks with dispatching every five minutes before the energy is needed, instead of the traditional one hour blocks.  APS expects that its participation in EIM will lower its fuel costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources.

Renewable Energy.  The ACC approved the RES in 2006.  The renewable energy requirement is 6% of retail electric sales in 2016 and increases annually until it reaches 15% in 2025.  In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 1,700 GWh of new renewable resources to be in service by year-end 2015, in addition to its RES renewable resource commitments.  APS met its settlement commitment and RES target for 2015. A component of the RES targets development of distributed energy systems.

In December of 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected 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 second stage of the program, which includes an additional 2 MW of rooftop solar and energy storage, will place two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements

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and system interoperability, and is planned to be in operation by the end of 2016.  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, 2015, APS filed its 2016 RES Implementation Plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules.

In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent EPA regulations.  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  APS cannot predict the outcome of this proceeding.

The following table summarizes renewable energy sources in APS's renewable portfolio that are in operation and under development as of November 3, 2016.

	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar (a)	189	50 (c)
Purchased Power Agreements:
Solar	310	—
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	629	—
Total Distributed Energy: Solar (b)	551	36 (d)
Total Renewable Portfolio	1,369	86

(a) Included in the 189 MW number is 170 MW of solar resources procured through the Company's 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.

(c) This amount represents APS-owned grid scale and distributed generation projects currently under development. Projects include the 40 MW Red Rock Solar Plant and the Solar Partner Program discussed above. Upon completion of construction, these projects will be considered "in operation" for purposes of this table.

(d) Applications received by APS that are not yet installed and online.

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APS has developed owned solar resources through the ACC-approved AZ Sun Program.  APS has invested approximately $675 million in its AZ Sun Program. 

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.

In March 2014 the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from 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. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS’s resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

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. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology.

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 rulemaking has not been initiated and there has been no additional action on the draft to date. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others.

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.

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On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). APS's application also addresses rate design changes (residential, commercial and industrial), permission to defer for potential future recovery costs associated with the Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items.  APS requested that the increase become effective July 1, 2017. On July 22, 2016, the administrative law judge set a procedural schedule for the rate proceedings. The ACC staff and interveners will begin filing their direct testimony on December 21, 2016, and the hearing will commence on March 22, 2017. The Commission staff supports completing the case within 12 months. APS cannot predict the outcome of its request.

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

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, 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.  On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement.  APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect this order in the second quarter of 2016.  On July 29, 2016, APS filed for a rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

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 electric 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 electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 

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On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, an Administrative Law Judge (the "ALJ") issued a recommendation in the docket concerning the value and cost of distributed generation. The ALJ recommended a change to how customers are compensated for energy that they export from rooftop solar systems. Instead of retail rate net metering, the ALJ recommended that the amount of compensation be established by using both an avoided cost calculation and a grid-scale solar resource proxy calculation that would be updated in subsequent utility rate cases. The ALJ recommended that the change to how APS pays for exported rooftop solar energy apply only to those customers who apply to interconnect their distributed generation systems after a decision in APS’s currently pending rate case. The ALJ found rooftop solar customers to be partial requirements customers, but recommended that whether rooftop solar customers should be placed into a separate customer class for purposes of ratemaking be decided in individual utility rate cases. Exceptions to the ALJ recommendation are due November 15, 2016. On December 13, 2016, the ACC will discuss at an opening meeting the ALJ recommendation concerning the value and cost of distributed generation. APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company ("TEP") both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015 and February 23, 2016, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS actively participated in the related hearings held in March 2016. On August 18, 2016, the ACC issued a decision which ordered that net metering be considered in a separate, phase 2 of the UNS Electric, Inc. rate case to occur after the ACC decides issues raised in the separate, generic docket concerning the value and cost of distributed generation discussed above. APS has also intervened in the upcoming TEP rate case. On June 24, 2016, APS filed testimony in the TEP rate case in support of the TEP proposed rate design changes. In August 2016, the ACC also bifurcated the TEP rate case into two phases, the first of which will address revenue requirements and other traditional rate case issues while the second will address net metering issues. The outcomes of these proceedings will not directly impact our financial position.

Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB"). In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.

System Benefits Charge. The 2012 Settlement Agreement  provides that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016.  Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge.  The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense.

Subpoena from Arizona Corporation Commissioner Robert Burns. On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current

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retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through year-to-date 2016. The subpoenas request information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from company personnel having knowledge of the material, including the Chief Executive Officer, on October 6, 2016.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas, or alternatively stay APS’ obligations to comply with the subpoenas and decline to decide APS’ motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. APS and Pinnacle West cannot predict the outcome of this matter.

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

Other Subsidiaries.

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.  TransCanyon continues to pursue transmission development opportunities in the western United States consistent with its strategy.

On March 29, 2016, TransCanyon entered into a strategic alliance agreement with Pacific Gas and Electric Company ("PG&E") to jointly pursue competitive transmission opportunities solicited by the CAISO, the operator for the majority of California's transmission grid. TransCanyon and PG&E intend to jointly engage in the development of future transmission infrastructure and compete to develop, build, own and operate transmission projects approved by the CAISO.

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.

4CA. See "Four Corners - Asset Purchase Agreement and Coal Supply Matters" above for information regarding 4CA.

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Key Financial Drivers

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

Electric Operating Revenues.  For the years 2013 through 2015, 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, and the operation of our adjustor 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 1.4% for the nine-month period ended September 30, 2016 compared with the prior-year period.  For the three years 2013 through 2015, APS’s customer growth averaged 1.3% per year. We currently expect annual customer growth to average in the range of 2.0-3.0% for 2016 through 2018 based on our assessment of modestly improving economic conditions in Arizona. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.3% for the nine-month period ended September 30, 2016 compared with the prior-year period, reflecting the effects of improving economic conditions and customer growth and an additional day of sales due to the leap year, partially offset by customer conservation and energy efficiency and distributed renewable generation initiatives.  For the three years 2013 through 2015, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average in the range of 0.5-1.5% during 2016 through 2018, 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 and Seasonality.  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. Additionally, amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption.

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

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Operations and Maintenance Expenses.  Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.

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 11.0% of the assessed value for 2015, 10.7% for 2014 and 10.5% for 2013.  We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities.  (See Note 3 for property tax deferrals contained in the 2012 Settlement Agreement.)

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

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

RESULTS OF OPERATIONS

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

Operating Results — Three-month period ended September 30, 2016 compared with three-month period ended September 30, 2015.

Our consolidated net income attributable to common shareholders for the three months ended September 30, 2016 was $263 million, compared with consolidated net income attributable to common shareholders of $257 million for the prior-year period.  The results reflect an increase of approximately $6 million for the regulated electricity segment primarily due to lower operations and maintenance expenses and higher lost fixed cost recovery revenues, partially offset by the effects of milder weather.

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

	Three Months Ended   September 30,
	2016			2015			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	827		$	835		$	(8	)
Operations and maintenance	(215		)	(220		)	5
Depreciation and amortization	(120		)	(126		)	6
Taxes other than income taxes	(41		)	(43		)	2
All other income and expenses, net	6			2			4
Interest charges, net of allowance for borrowed funds used during construction	(47		)	(46		)	(1		)
Income taxes	(142		)	(140		)	(2		)
Less income related to noncontrolling interests (Note 5)	(5		)	(5		)	—
Regulated electricity segment income	263			257			6
All other	—			—			—
Net Income Attributable to Common Shareholders	$	263		$	257		$	6

Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $8 million lower for the three months ended September 30, 2016 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	$	(22	)	$	(6	)	$	(16	)
Higher retail transmission revenues	8			—			8
Lost fixed cost recovery	10			—			10
Retail sales due to customer growth and changes in customer usage patterns and related pricing	3			—			3
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(16		)	(17		)	1
Lower demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power	(6		)	(1		)	(5		)
Palo Verde system benefits charge (offset in depreciation and amortization, see Note 3)	(5		)	—			(5		)
Miscellaneous items, net	(4		)	—			(4		)
Total	$	(32	)	$	(24	)	$	(8	)

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Operations and maintenance.  Operations and maintenance expenses decreased $5 million for the three months ended September 30, 2016 compared with the prior-year period primarily because of:

• A decrease of $4 million related to lower fossil operating costs;

• A decrease of $4 million for employee benefit costs primarily related to decreased stock compensation partially offset by other benefit costs;

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

• An increase of $2 million for corporate support costs primarily related to outside legal services; and

• An increase of $5 million related to miscellaneous other factors.

Depreciation and amortization.  Depreciation and amortization expenses were $6 million lower for the three months ended September 30, 2016 compared to the prior-year period primarily related to:

• A decrease of $5 million related to the regulatory treatment of the Palo Verde sale leaseback lease extension;

• A decrease of $4 million due to lower Palo Verde decommissioning expense recovered through the system benefits charge (offset in operating revenues); and

• An increase of $3 million due to increased plant in service.

Operating Results — Nine-month period ended September 30, 2016 compared with nine-month period ended September 30, 2015.

Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2016 was $389 million, compared with consolidated net income attributable to common shareholders of $396 million for the prior-year period.  The results reflect a decrease of approximately $7 million for the regulated electricity segment primarily due to higher operations and maintenance expenses related to employee benefit costs, transmission, distribution and customer service costs and fossil generation costs partially offset by higher retail transmission revenues, higher retail sales due to customer growth and changes in customer usage patterns and related pricing and higher lost fixed cost recovery revenues.

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

	Nine Months Ended   September 30,
	2016			2015			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,917		$	1,890		$	27
Operations and maintenance	(701		)	(646		)	(55		)
Depreciation and amortization	(362		)	(369		)	7
Taxes other than income taxes	(126		)	(129		)	3
All other income and expenses, net	27			16			11
Interest charges, net of allowance for borrowed funds used during construction	(140		)	(134		)	(6		)
Income taxes	(210		)	(216		)	6
Less income related to noncontrolling interests (Note 5)	(15		)	(14		)	(1		)
Regulated electricity segment income	390			398			(8		)
All other	(1		)	(2		)	1
Net Income Attributable to Common Shareholders	$	389		$	396		$	(7	)

Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $27 million higher for the nine months ended September 30, 2016 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)
Lost fixed cost recovery	$	12		$	—		$	12
Effects of weather	7			3			4
Transmission revenues (Note 3):
Higher retail transmission revenues	25			—			25
FERC disallowance	(12		)	—			(12		)
Higher retail sales due to customer growth and changes in customer usage patterns and related pricing	18			2			16
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(33		)	(34		)	1
Palo Verde system benefits charge (offset in depreciation and amortization, see Note 3)	(11		)	—			(11		)
Lower demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power	(9		)	—			(9		)
Miscellaneous items, net	(3		)	(4		)	1
Total	$	(6	)	$	(33	)	$	27

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Operations and maintenance.  Operations and maintenance expenses increased $55 million for the nine months ended September 30, 2016 compared with the prior-year period primarily because of:

• An increase of $22 million for employee benefit costs primarily related to increased stock compensation and other benefit costs;

• An increase of $12 million for transmission, distribution, and customer service costs primarily related to increased maintenance costs;

• An increase of $11 million in fossil generation costs primarily related to $32 million in higher planned outage costs, partially offset by $21 million of lower other fossil operating costs;

• A decrease of $9 million related to costs for demand-side management, renewable energy and similar regulatory programs, which is partially offset in operating revenues and purchased power;

• An increase of $5 million for costs to support the company's positions on a solar net metering ballot initiative in Arizona, and increased regulatory costs;

• An increase of $6 million for costs related to corporate support;

• An increase of $4 million related to higher nuclear generation costs; and

• An increase of $4 million related to miscellaneous other factors.

Depreciation and amortization.  Depreciation and amortization expenses decreased $7 million for the nine months ended September 30, 2016 compared to the prior-year period primarily related to:

• A decrease of $15 million related to the regulatory treatment of the Palo Verde sale leaseback lease extension;

• A decrease of $11 million due to lower Palo Verde decommissioning expense recovered through the system benefits charge (offset in operating revenues); and

• An increase of $19 million due to increased plant in service.

All other income and expenses, net.  All other income and expenses, net, were $11 million higher for the nine months ended September 30, 2016 compared with the prior-year period primarily due to the gain on sale of a transmission line and higher allowance for equity funds used during construction.

Interest charges, net of allowance for borrowed funds used during construction.  Interest charges, net of allowance for borrowed funds used during construction, increased $6 million for the nine months ended September 30, 2016 compared with the prior-year period, primarily because of higher debt balances in the current year.

Income Taxes.  Income taxes were $6 million lower for the nine months ended September 30, 2016 compared with the prior-year period, primarily because of lower taxable income in the current year.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Our primary sources of cash are dividends from APS and external debt and equity issuances.  An ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At September 30, 2016, APS’s common equity ratio, as defined, was 54%.  Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.2 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.7 billion, assuming APS’s total capitalization remains the same.  This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

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

Many of APS’s current capital expenditure projects qualify for bonus depreciation. On December 18, 2015, President Obama signed into law the Consolidated Appropriations Act, 2016 (H.R. 2029), which combined the tax and government funding bills (The Protecting Americans from Tax Hikes Act and Omnibus Bill) containing an extension of bonus depreciation through 2019.  Enactment of this legislation is expected to generate approximately $375-$425 million of cash tax benefits over the next three years, which is expected to be fully realized by APS and Pinnacle West Consolidated during this time frame.  The cash generated by the extension of bonus depreciation is an acceleration of the tax benefits that APS would have otherwise received over 20 years and reduces rate base for ratemaking purposes.  At Pinnacle West Consolidated, the extension of bonus depreciation will, in turn, delay until 2019 full cash realization of approximately $61 million of currently unrealized Investment Tax Credits, which are recorded as a deferred tax asset on the Condensed Consolidated Balance Sheet as of September 30, 2016.

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the nine months ended September 30, 2016 and 2015 (dollars in millions):

Pinnacle West Consolidated

	Nine Months Ended   September 30,						Net
	2016			2015			Change
Net cash flow provided by operating activities	$	765		$	821		$	(56	)
Net cash flow used for investing activities	(1,010		)	(773		)	(237		)
Net cash flow provided by (used for) financing activities	254			(43		)	297
Net increase in cash and cash equivalents	$	9		$	5		$	4

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Arizona Public Service Company

	Nine Months Ended   September 30,						Net
	2016			2015			Change
Net cash flow provided by operating activities	$	766		$	832		$	(66	)
Net cash flow used for investing activities	(983		)	(770		)	(213		)
Net cash flow provided by (used for) financing activities	203			(61		)	264
Net increase in cash and cash equivalents	$	(14	)	$	1		$	(15	)

Operating Cash Flows

Nine-month period ended September 30, 2016 compared with nine-month period ended September 30, 2015.  Pinnacle West’s consolidated net cash provided by operating activities was $765 million in 2016 compared to $821 million in 2015. The decrease of $56 million in net cash provided is primarily due to higher operating costs. 

Retirement plans and other postretirement benefits. 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 116% funded as of January 1, 2015 and 2016.  Under GAAP, the qualified pension plan was 89% funded as of January 1, 2015 and 88% funded as of January 1, 2016. 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 $100 million to our pension plan year-to-date in 2016. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period. 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

Nine-month period ended September 30, 2016 compared with nine-month period ended September 30, 2015.  Pinnacle West’s consolidated net cash used for investing activities was $1,010 million in 2016, compared to $773 million in 2015, an increase of $237 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,
	2016		2017		2018
APS
Generation:
Nuclear Fuel	$	81	$	69	$	71
Renewables	104		1		1
Environmental	224		197		103
New Gas Generation	77		234		117
Other Generation	142		151		208
Distribution	380		399		411
Transmission	136		211		136
Other (a)	89		75		77
Total APS	$	1,233	$	1,337	$	1,124

(a) Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’s existing fossil, renewable 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 capital expenditures include a grid scale solar facility. We have not included estimated costs for Cholla's compliance with 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. We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

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. On December 29, 2015, NTEC notified APS of its intent to exercise its option to purchase the 7% interest. 4CA, a wholly-owned subsidiary of Pinnacle West, purchased the El Paso interest on July 6, 2016. The table above does not include capital expenditures related to 4CA's interest in Four Corners Units 4 and 5 of approximately $30 million in 2016 and $27 million in 2017.

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

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

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Financing Cash Flows and Liquidity

Nine-month period ended September 30, 2016 compared with nine-month period ended September 30, 2015.  Pinnacle West’s consolidated net cash provided by financing activities was $254 million in 2016, compared to $43 million of net cash used for financing activities in 2015, an increase of $297 million in net cash provided.  The increase in net cash provided by financing activities is primarily due to a $208 million net increase in short-term borrowings and $93 million higher issuances of long-term debt through September 30, 2016.

Significant Financing Activities.  On October 20, 2016, the Pinnacle West Board of Directors declared a dividend of $0.655 per share of common stock, payable on December 1, 2016 to shareholders of record on November 1, 2016. This represents an increase in the indicated annual dividend from $2.50 per share to $2.62 per share.

On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. Interest rates are based on APS's senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

On May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel Pollution Control Bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E.

On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A.

On August 1, 2016, APS repaid at maturity APS’s $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016.

On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016.

On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B.

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.

During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $200 million facility that matures in May 2021. Pinnacle West has the option

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to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At September 30, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021.

On August 31, 2016, PNW entered into a $75 million 364-day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At September 30, 2016, Pinnacle West had $34 million outstanding under the facility.

At September 30, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At September 30, 2016, APS had $83 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.

 See "Financial Assurances" in Note 7 for a discussion of APS’s separate outstanding letters of credit.

Other Financing Matters. See Note 6 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 September 30, 2016, the ratio was approximately 48% for Pinnacle West and 47% 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 October 28, 2016 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
Commercial paper	P-1	A-2	F2
Outlook	Stable	Stable	Stable

Off-Balance Sheet Arrangements

See Note 5 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

Contractual Obligations

There have been no material changes, as of September 30, 2016, outside the normal course of business in contractual obligations from the information provided in our 2015 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period.  Some of those judgments can be subjective and complex, and actual results could differ from those estimates.  There have been no changes to our critical accounting policies since our 2015 Form 10-K.  See "Critical Accounting Policies" in Item 7 of the 2015 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 the following new accounting standards:

• Stock compensation guidance effective for us January 1, 2017

• Revenue recognition guidance, and related amendments, effective for us January 1, 2018

• Financial instrument recognition and measurement guidance effective for us January 1, 2018

• Lease accounting guidance effective for us January 1, 2019

• Measurement of credit losses on financial instruments effective for us on January 1, 2020

See Note 12 for additional information related to accounting matters.

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 10 and Note 11) and benefit plan assets.  The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments.  Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

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

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The following table shows the net pretax changes in mark-to-market of our derivative positions for the nine months ended September 30, 2016 and 2015 (dollars in millions):

	Nine Months Ended   September 30,
	2016			2015
Mark-to-market of net positions at beginning of year	$	(154	)	$	(115	)
Decrease (increase) in regulatory asset/liability	58			(39		)
Recognized in OCI:
Mark-to-market losses realized during the period	3			5
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(93	)	$	(149	)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at September 30, 2016 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  See Note 1, "Derivative Accounting" and "Fair Value Measurements," in Item 8 of our 2015 Form 10-K and Note 10 for more discussion of our valuation methods.

Source of Fair Value	2016			2017			2018			2019			2020			Total fair value
Observable prices provided by other external sources	$	(9	)	$	(23	)	$	(16	)	$	(5	)	$	—		$	(53	)
Prices based on unobservable inputs	(2		)	(11		)	(14		)	(11		)	(2		)	(40		)
Total by maturity	$	(11	)	$	(34	)	$	(30	)	$	(16	)	$	(2	)	$	(93	)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at September 30, 2016 and December 31, 2015 (dollars in millions):

	September 30, 2016					December 31, 2015
	Gain (Loss)					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	)	$	2	$	(2	)
Natural gas	43		(43		)	35		(35		)
Total	$	45	$	(45	)	$	37	$	(37	)

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

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Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties.  See Note 6 for a discussion of our credit valuation adjustment policy.

Item 3.        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4.         CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

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

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of September 30, 2016.  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 September 30, 2016.  Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended September 30, 2016 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 2015 Form 10-K with regard to pending or threatened litigation and other disputes.

See Note 3 for ACC and FERC-related matters.

See Note 7 for information regarding environmental matters and Superfund-related matters.

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 2015 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 2015 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

Peabody Bankruptcy

On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri.  Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona.  APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement. 

On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleges that the Buyers have breached the Agreement. Peabody requests substantial, but unspecified, monetary damages from the Buyers.  Peabody and the Buyers have agreed to pursue non-binding mediation, failing which a trial is expected to begin in February 2017.  APS cannot predict the outcome of this matter.

Subpoenas

Pinnacle West has received grand jury subpoenas issued in connection with an investigation by the office of the United States Attorney for the District of Arizona. The subpoenas seek information principally pertaining to the 2014 statewide election races in Arizona for Secretary of State and for positions on the ACC. The subpoenas request records involving certain Pinnacle West officers and employees, including the Company’s Chief Executive Officer, as well as communications between Pinnacle West personnel and a former ACC Commissioner. Pinnacle West is cooperating fully with the United States Attorney’s office in this matter.

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Item 6.                EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
10.1	Pinnacle West	364-day Credit Agreement dated as of August 31, 2016, among Pinnacle West, as Borrower, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent and Issuing Bank, and the lenders and other parties thereto
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
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

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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:	November 3, 2016	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:	November 3, 2016	By:	/s/ James R. Hatfield
			James R. Hatfield
			Executive Vice President and
			Chief Financial Officer
			(Principal Financial Officer and
			Officer Duly Authorized to sign this Report)

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EX-10.1

Exhibit 10.1

U.S. $75,000,000

364-DAY CREDIT AGREEMENT

Dated as of August 31, 2016

among

PINNACLE WEST CAPITAL CORPORATION,

asBorrower,

THE LENDERS PARTY HERETO,

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.,

asAgent and as Issuing Bank, and

JPMORGAN CHASE BANK, N.A.,

as Syndication Agent

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.,

and

JPMORGAN CHASE BANK, N.A.,

asJointLeadArrangersandJointBookRunners

TABLE OF CONTENTS

ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS

Section 1.01	Certain Defined Terms	1
Section 1.02	Other Interpretive Provisions	15
Section 1.03	Accounting Terms	16
Section 1.04	Rounding	16
Section 1.05	Times of Day	16

ARTICLE II
AMOUNTS AND TERMS OF THE ADVANCES AND
LETTERS OF CREDIT

Section 2.01	The Revolving Advances and Letters of Credit.	16
Section 2.02	Making the Revolving Advances.	17
Section 2.03	Letters of Credit.	18
Section 2.03A	Swingline Advances.	25
Section 2.04	Fees.	27
Section 2.05	Optional Termination or Reduction of the Commitments.	28
Section 2.06	Repayment of Advances	28
Section 2.07	Interest on Advances.	28
Section 2.08	Interest Rate Determination.	29
Section 2.09	Optional Conversion of Revolving Advances	30
Section 2.10	Prepayments of Advances.	31
Section 2.11	Increased Costs.	31
Section 2.12	Illegality	33
Section 2.13	Payments and Computations.	33
Section 2.14	Taxes.	34
Section 2.15	Sharing of Payments, Etc	38
Section 2.16	Evidence of Debt.	38
Section 2.17	Use of Proceeds	39
Section 2.18	Reserved	39
Section 2.19	Affected Lenders	39
Section 2.20	Replacement of Lenders	40
Section 2.21	Reserved	41

ARTICLE III
CONDITIONS PRECEDENT

Section 3.01	Conditions Precedent to Effectiveness	41
Section 3.02	Conditions Precedent to Each Credit Extension	42
Section 3.03	Determinations Under Section 3.01	43

ARTICLE IV
REPRESENTATIONS AND WARRANTIES

Section 4.01 Representations and Warranties of the Borrower 43

ARTICLE V
COVENANTS OF THE BORROWER

Section 5.01	Affirmative Covenants	47
Section 5.02	Negative Covenants	50
Section 5.03	Financial Covenant	51

ARTICLE VI
EVENTS OF DEFAULT

Section 6.01	Events of Default	51
Section 6.02	Actions in Respect of Letters of Credit upon Default	53

ARTICLE VII
THE AGENT

Section 7.01	Appointment and Authority	53
Section 7.02	Rights as a Lender	53
Section 7.03	Exculpatory Provisions	54
Section 7.04	Reliance by Agent	54
Section 7.05	Delegation of Duties	55
Section 7.06	Resignation of Agent	55
Section 7.07	Non-Reliance on Agent and Other Lenders	55
Section 7.08	No Other Duties, Etc	55
Section 7.09	Issuing Banks	56

ARTICLE VIII
MISCELLANEOUS

Section 8.01	Amendments, Etc	56
Section 8.02	Notices, Etc.	57
Section 8.03	No Waiver; Cumulative Remedies; Enforcement	58
Section 8.04	Costs and Expenses; Indemnity; Damage Waiver.	59
Section 8.05	Right of Set-off	61
Section 8.06	Effectiveness; Binding Effect	61
Section 8.07	Successors and Assigns.	61
Section 8.08	Confidentiality	65
Section 8.09	Governing Law	65
Section 8.10	Counterparts; Integration;	65
Section 8.11	Jurisdiction, Etc.	65
Section 8.12	Payments Set Aside	66
Section 8.13	Patriot Act	66
Section 8.14	Waiver of Jury Trial	66
Section 8.15	No Advisory or Fiduciary Responsibility	66
Section 8.16	Survival of Representations and Warranties	67
Section 8.17	Severability	67
Section 8.18	Acknowledgement and Consent to Bail-In of EEA Financial Institutions.	67

Schedules

Schedule 1.01 Commitments and Ratable Shares

Schedule 4.01(j) Subsidiaries

Schedule 4.01(k) Existing Indebtedness

Schedule 8.02 Certain Address for Notices

Exhibits

Exhibit A Form of Note

Exhibit B Form of Notice of Borrowing

Exhibit C Form of Assignment and Assumption

364-DAY CREDIT AGREEMENT

Dated as of August 31, 2016

PINNACLE WEST CAPITAL CORPORATION, an Arizona corporation (the “Borrower”), the banks, financial institutions and other institutional lenders (the “Initial Lenders”) and the initial issuing bank (the “Initial Issuing Bank”) listed on the signature pages hereof, the other Lenders (as hereinafter defined), THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.,as Agent for the Lenders and JPMORGAN CHASE BANK, N.A., as Syndication Agent, agree as follows:

The Borrower has requested that the Lenders provide a revolving credit 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 I

DEFINITIONS AND ACCOUNTING TERMS

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

“4C Sub” means 4C Acquisition, LLC, a Subsidiary of the Borrower formed to acquire from El Paso Electric Company and temporarily own a 7% ownership interest in Units 4 and 5 of the Four Corners Power Plant located near Farmington, New Mexico.

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

“Advance” means a Revolving Advance or a Swingline Advance.

“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 any Revolving Advance within three (3) Business Days of the date such Revolving Advances were required to be funded hereunder unless such Lender notifies the Agent and the Borrower in writing that such failure is the result of such Lender’s determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable default, shall be specifically identified in writing) has not been satisfied, or (ii) pay to the Agent, any Issuing Bank, the Swingline Lender, if any, or any other Lender any other amount required to be paid by it hereunder (including in respect of its participation in Letters of Credit and funding obligations in respect of Swingline Advances) within three (3) Business Days of the date when due, (b) has notified the Borrower, the Agent, any Issuing Bank or any Lender in writing of its intention not to fund any Revolving Advance 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,

1

by the Required Lenders, to confirm that it will comply with the terms of this Agreement relating to its obligations to fund prospective Revolving Advances and other funding obligations under this Agreement, (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) or (e) has become the subject of a Bail-In Action, 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 any 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 The Bank of Tokyo-Mitsubishi UFJ, Ltd. 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 on Schedule 8.02 under the heading “Agent’s Account” or such other account as the Agent may designate to the Lenders and the Borrower from time to time.

“Agent’s Office” means the Agent’s address and, as appropriate, the Agent’s Account, or such other address or account as the Agent may from time to time notify the Borrower and the Lenders.

“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.

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

“Applicable Rate” means, from time to time, (i) with respect to Eurodollar Rate Advances, 0.80% per annum, (ii) with respect to Base Rate Advances, 0.00% per annum, and (iii) with respect to commitment fees hereunder, 0.125% per annum.

“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.

“APS” means Arizona Public Service Company, an Arizona corporation.

“Arrangers” means, collectively, The Bank of Tokyo-Mitsubishi UFJ, Ltd. and JPMorgan Chase Bank, N.A.

“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.

“Available Amount” of any Letter of Credit means, at any time, the maximum amount available to be drawn under such Letter of Credit at such time (assuming compliance at such time with all conditions to drawing).

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

“Base Rate” means for any day a fluctuating rate per annum equal to the highest of:

(a)    the rate of interest in effect for such day as publicly announced from time to time by the Agent as its “prime rate”;

(b)    the Federal Funds Rate plus 0.50%; and

(c)    an amount equal to (i) 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 (ii) 1%;

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provided that, if the Base Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“Base Rate Advance” means a Revolving Advance that bears interest as provided in Section 2.07(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.

“Borrowing” means (a) a borrowing consisting of simultaneous Revolving Advances of the same Type made by each of the Lenders pursuant to Section 2.01(a)or (b) Swingline Advances.

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

“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 a Revolving Credit Commitment or a Letter of Credit Commitment.

“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 APS,

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“Consolidated Indebtedness” shall not include any Indebtedness or other obligations of the VIE Lessor Trusts.

“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 Revolving Advances of one Type into Revolving Advances of the other Type pursuant to Section 2.08, Section 2.09 or Section 2.12.

“Credit Extension” means each of the following: (a) a Borrowing and (b) the issuance of a Letter of Credit.

“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.

“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country

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which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent;

“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“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 Section 8.07(b)(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 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

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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.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“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 for any Interest Period as to any Eurodollar Rate Advance, (i) the rate per annum determined by the Agent to be the offered rate which appears on the page of the Reuters Screen which displays the London interbank offered rate administered by ICE Benchmark Administration Limited (such page currently being the LIBOR01 page) (the “LIBO Rate”) for deposits (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period in Dollars, determined as of approximately 11:00 a.m. (London, England time), two Business Days prior to the commencement of such Interest Period, or (ii) in the event the rate referenced in the preceding clause (i) does not appear on such page or service or if such page or service shall cease to be available, the rate determined by the Agent to be the offered rate on such other page or other service which displays the LIBO Rate for deposits (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period in Dollars, determined as of approximately 11:00 a.m. (London, England time) two Business Days prior to the commencement of such Interest Period; provided that if LIBO Rates are quoted under either of the preceding clauses (i) or (ii), but there is no such quotation for the Interest Period elected, the LIBO Rate shall be equal to the Interpolated Rate; and provided, further, that if any such rate determined pursuant to this definition is below zero, the Eurodollar Rate will be deemed to be zero.

“Eurodollar Rate Advance” means a Revolving Advance that bears interest at a rate based on the Eurodollar Rate (other than a Base Rate Advance 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, any Issuing Bank 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,

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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 2.14(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 2.20), any United Statesof 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 2.14(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 2.14(a)(i) or (ii) and (v) any United States withholding Tax imposed by FATCA.

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

“FATCA” means Section 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 rate per annum equal to the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers on such day, as published by the Federal Reserve Bank of New York on the Business Day next succeeding such day; provided that (a) if such day is not a Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day, (b) if no such rate is so published on such next succeeding Business Day, the Federal Funds Rate for such day shall be the average rate (rounded upward, if necessary, to a whole multiple of 1/100 of 1%) charged to the Agent on such day on such transactions as determined by the Agent, and (c) solely for purposes for determining the Money Market Rate, any such other publication or means of determining the rate for federal funds as agreed to between the Borrower and Swingline Lender; provided further, 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 Letters” means (a) the agent fee letter from The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent, relating to certain fees payable by the Borrower to The Bank of Tokyo-Mitsubishi UFJ, Ltd. (including in its capacity as the Initial Issuing Bank) in respect of the transactions contemplated by this Agreement and (b) any letter between the Borrower and any Issuing Bank other than the Initial Issuing Bank relating to certain fees payable to such Issuing Bank in its capacity as such, each as amended, modified, restated or supplemented from time to time.

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“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 (including such a Lender when acting in the capacity of an Issuing Bank or a Swingline Lender). 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 APS 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 APS.

“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 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.

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“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.

“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 (unless subject to a good faith dispute) of the date incurred; (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 Issuing Bank” has the meaning given to such term in the introductory paragraph hereof.

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

“Interest Period” means, for each Eurodollar Rate Advance comprising part of the same Borrowing, the period commencing on (i) the date such Eurodollar Rate Advance is disbursed, (ii) the date of the Conversion of any Base Rate Advance into such Eurodollar Rate Advance or (iii) the effective date of the most recent continuation of such Eurodollar Rate Advance, 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 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 Termination Date;

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

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(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.

“Interpolated Rate” means, in relation to the LIBO Rate, the rate which results from interpolating on a linear basis between:

(a)    the applicable LIBO Rate for the longest period (for which that LIBO Rate is available) which is less than the Interest Period of that Loan; and

(b)    the applicable LIBO Rate for the shortest period (for which that LIBO Rate is available) which exceeds the Interest Period of that Loan,

each as of approximately 11:00 a.m. (London, England time) two Business Days prior to the commencement of such Interest Period of that Loan.

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

“ISP” means, with respect to any Letter of Credit, the “International Standby Practices 1998” published by the Institute of International Banking Law & Practice, Inc. (or such later version thereof as may be in effect at the time of issuance).

“Issuing Bank” means the Initial Issuing Bank and any other Lender approved by the Borrower that may agree to issue Letters of Credit pursuant to an Assignment and Assumption or other agreement in form satisfactory to the Borrower and the Agent, so long as such Lender expressly agrees to perform in accordance with their terms all of the obligations that by the terms of this Agreement are required to be performed by it as an Issuing Bank and notifies the Agent of its Applicable Lending Office (which information shall be recorded by the Agent in the Register), for so long as such Initial Issuing Bank or Lender, as the case may be, shall have a Letter of Credit Commitment.

“L/C Advance” means, with respect to each Lender, such Lender’s funding of its participation in any L/C Borrowing in accordance with its Ratable Share.

“L/C Borrowing” means an extension of credit resulting from a drawing under any Letter of Credit which has not been reimbursed on the date when made nor refinanced as a Base Rate Advance.

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“L/C Cash Deposit Account” means an interest bearing cash deposit account to be established and maintained by the Agent, over which the Agent shall have sole dominion and control, upon terms as may be satisfactory to the Agent.

“L/C Obligations” means, as at any date of determination, the aggregate Available Amount of all outstanding Letters of Credit plus the aggregate of all Unreimbursed Amounts, including all L/C Borrowings. For all purposes of this Agreement, if on any date of determination a Letter of Credit has expired by its terms but any amount may still be drawn thereunder by reason of the operation of Rule 3.14 of the ISP, such Letter of Credit shall be deemed to be “outstanding” in the amount so remaining available to be drawn.

“L/C Related Documents” means with respect to any Letter of Credit, the Letter of Credit Application, and any other document, agreement and instrument entered into by any Issuing Bank and the Borrower or in favor of any Issuing Bank and relating to such Letter of Credit.

“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.

“Lenders” means the Initial Lenders, each Issuing Bank, the Swingline Lender, if any, and each Person that shall become a party hereto pursuant to Section 8.07.

“Letter of Credit” has the meaning specified in Section 2.01(b).

“Letter of Credit Application” means an application and agreement for the issuance or amendment of a Letter of Credit in the form from time to time in use by any Issuing Bank.

“Letter of Credit Commitment” means, with respect to each Issuing Bank, the obligation of such Issuing Bank to issue Letters of Credit for the account of the Borrower from time to time in an aggregate amount equal to (a) for the Initial Issuing Bank, $50,000,000, and (b) for any other Issuing Bank, as separately agreed to by such Issuing Bank and the Borrower. The Letter of Credit Commitment is part of, and not in addition to, the Revolving Credit Commitments.

“Letter of Credit Expiration Date” means the day that is five Business Days prior to the Termination Date.

“LIBO Rate” has the meaning specified in the definition of “Eurodollar Rate.”

“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

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encumbrance on title to real property, and any capital lease having substantially the same economic effect as any of the foregoing.

“Loan Documents” mean this Agreement, each Note, each L/C Related Document and the Fee Letters.

“Material Adverse Effect” means a material adverse effect on (a) the financial condition, operations, business or property 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 APS, at any time, and each other 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).

“Money Market Rate” means (a) the Federal Funds Rate plus (b) the Applicable Rate for Eurodollar Rate Advances.

“Money Market Rate Advance” means a Swingline Advance that bears interest at a rate based on the Money Market Rate.

“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 2.16 in substantially the form of Exhibit A hereto.

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

“Obligations” means all advances to, and debts, liabilities, obligations, covenants and duties of, the Borrower arising under any Loan Document or otherwise with respect to any Revolving Advance, Swingline Advance or Letter of Credit, 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 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.

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“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.

“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.

“Prime Rate” means the rate of interest last quoted by The Wall Street Journal as the “Prime Rate” in the U.S. or, if The Wall Street Journal ceases to quote such rate, the highest per annum interest rate published by the Federal Reserve Board in Federal Reserve Statistical Release H.15 (519) (Selected Interest Rates) as the “bank prime loan” rate or, if such rate is no longer quoted therein, any similar rate quoted therein (as determined by the Agent) or any similar release by the Federal Reserve Board (as determined by the Agent).

“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).

“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, or, if no such senior unsecured debt is outstanding at the time of determination, such rating for bank credit facilities for, the Borrower or, if any such rating agency shall have issued more than one such rating, the lowest such rating issued by such rating agency.

“PVNGS” means the Palo Verde Nuclear Generating Station.

“Ratable Share” of any amount means, with respect to any Lender at any time but subject to the provisions of Section 2.19, the product of such amount times a fraction the numerator of which is the amount of such Lender’s Revolving Credit Commitment at such time (or, if the Revolving Credit Commitments shall have been terminated pursuant to Section 2.05 or Section 6.01, such Lender’s Revolving Credit Commitment as in effect immediately prior to such termination) and the denominator of which is the aggregate amount of all Revolving Credit Commitments at such time (or, if the Revolving Credit Commitments shall have been terminated pursuant to Section 2.05 or Section 6.01, the aggregate amount of all Revolving Credit Commitments as in effect immediately prior to such termination).

“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”). 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, at any time, but subject to Section 2.19, Lenders holding in the aggregate more than 50% of (a) the Revolving Credit Commitments or (b) if the Revolving Credit Commitments have been terminated, the Total Outstandings.

“Revolving Advance” means an advance by a Lender to the Borrower as part of a Borrowing, including a Base Rate Advance made pursuant to Section 2.03(c), but excluding any L/C Advance made as part of an L/C Borrowing and any Swingline Advance, and refers to a Base Rate Advance or a Eurodollar Rate Advance (each of which shall be a Type of Revolving Advance).

“Revolving Credit Commitment” means, as to any Lender, its obligation to (a) make Revolving Advances to the Borrower pursuant to Section 2.01and Section 2.03(c), (b) purchase

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participations in L/C Obligations and (c) make Revolving Advances pursuant to Section 2.03A(c) for the purpose of repaying Swingline Advances, in an aggregate principal amount at any one time outstanding not to exceed the amount set forth opposite such Lender’s name on Schedule 1.01 under the column “Revolving Credit Commitment” or if such Lender has entered into any Assignment and Assumption, the amount set forth for such Lender in the Register, in each case as such amount may be reduced pursuant to Section 2.05.

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

“Sale Leaseback Obligation Bonds” means any bonds issued by or on behalf of the Borrower in connection with a sale/leaseback transaction and any refinancing or refunding of such obligations.

“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 Section 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 year ended December 31, 2015, (ii) Form 10-Q Reports for the quarters ended March 31, 2016 and June 30, 2016 and (iii) Form 8-K Reports filed on April 25, 2016, May 6, 2016, May 13, 2016, May 24, 2016, June 1, 2016 and August 30, 2016.

“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.

“Swingline Advance” means an advance made by the Swingline Lender, if any, to the Borrower pursuant to Section 2.03A.

“Swingline Eurodollar Rate Advance” means a Swingline Advance that bears interest at a rate equivalent to (a) clause (ii) under the definition of Eurodollar Rate, plus (b) the Applicable Rate for Eurodollar Rate Advances.

“Swingline Exposure” means, at any time, the aggregate principal amount of all Swingline Advances outstanding at such time. The Swingline Exposure of any Lender shall be its Ratable Share of the total Swingline Exposure at such time.

“Swingline Lender” means, upon notice to the Agent by such Lender and the Borrower, any Lender approved by the Borrower and the Agent from time to time that may agree to fund Swingline Advances (as of the Effective Date there shall be no Swingline Lender).

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“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.

“Termination Date” means the earlier of (a) August 30, 2017 (b) the date of termination in whole of the Commitments pursuant to Section 2.05 or Section 6.01.

“Total Outstandings” means the sum of (a) the aggregate principal amount of all Revolving Advances plus (b) all L/C Obligations outstanding plus (c) the aggregate Swingline Exposure.

“Type” means a Base Rate Advance or a Eurodollar Rate Advance.

“Unreimbursed Amount” has the meaning specified in Section 2.03(c)(i).

“Unissued Letter of Credit Commitment” means, with respect to any Issuing Bank, the obligation of such Issuing Bank to issue Letters of Credit for the account of the Borrower in an amount equal to the excess of (a) the amount of its Letter of Credit Commitment over (b) the aggregate Available Amount of all Letters of Credit issued by such Issuing Bank.

“Unused Commitment” means, with respect to each Lender at any time, (a) such Lender’s Revolving Credit Commitment at such time minus (b) the sum of (i) the aggregate principal amount of all Revolving Advances made by such Lender (in its capacity as a Lender) and outstanding at such time and (ii) such Lender’s Ratable Share of the aggregate L/C Obligations and, other than for the purposes of calculation of the commitment fees, such Lender’s Ratable Share of the aggregate Swingline Exposure outstanding at such time.

“VIE Lessor Trusts” means the three (3) separate variable-interest entity lessor trusts that purchased from, and leased back to, APS certain interests in the PVNGS Unit 2 and related common facilities, as described in Note 5 of Notes to Condensed Consolidated Financial Statements in APS’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

“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.

“Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

Section 1.02    Other 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

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“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.

Section 1.03    Accounting 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 1.04    Rounding. 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

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expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).

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

ARTICLE II

AMOUNTS AND TERMS OF THE ADVANCES AND
LETTERS OF CREDIT

Section 2.01    The Revolving Advances and Letters of Credit.

(a)    The Revolving Advances. Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Revolving Advances in Dollars to the Borrower from time to time on any Business Day during the period from the Effective Date until the Termination Date in an amount not to exceed such Lender’s Unused Commitment. Each Borrowing (other than a Swingline Advance) shall be in an aggregate amount of $1,000,000 or an integral multiple of $1,000,000 in excess thereof and shall consist of Revolving Advances of the same Type made on the same day by the Lenders ratably according to their respective Revolving Credit Commitments. Within the limits of each Lender’s Revolving Credit Commitment, and subject to the other terms and conditions hereof, the Borrower may borrow under this Section 2.01(a), prepay pursuant to Section 2.10 and reborrow under this Section 2.01(a). Any Swingline Advance shall be made and repaid in accordance with the procedures set forth in Section 2.03A.

(b)    Letters of Credit. Each Issuing Bank agrees, on the terms and conditions hereinafter set forth, in reliance upon the agreements of the other Lenders set forth in this Agreement, to issue standby letters of credit (each a “Letter of Credit”) for the account of the Borrower from time to time on any Business Day during the period from the Effective Date until 30 days before the Termination Date in an aggregate Available Amount for all Letters of Credit issued by each Issuing Bank not to exceed at any time such Issuing Bank’s Letter of Credit Commitment, provided that after giving effect to the issuance of any Letter of Credit, (i) the Total Outstandings shall not exceed the aggregate Revolving Credit Commitments and (ii) each Lender’s Ratable Share of the Total Outstandings shall not exceed such Lender’s Revolving Credit Commitment. No Letter of Credit shall have an expiration date (including all rights of the Borrower or the beneficiary to require renewal) later than the Letter of Credit Expiration Date. Within the limits referred to above, the Borrower may from time to time request the issuance of Letters of Credit under this Section 2.01(b). The terms “issue”, “issued”, “issuance” and all similar terms, when applied to a Letter of Credit, shall include any renewal, extension or amendment thereof.

Section 2.02    Making the Revolving Advances.

(a)    Except as otherwise provided in Section 2.03(c), each Borrowing (other than a Swingline Advance) shall be made on notice, given not later than (x) 12:00 noon on the third Business Day prior to the date of the proposed Borrowing in the case of a Borrowing consisting of Eurodollar Rate Advances or (y) 12:00 noon on the date of the proposed Borrowing in the case of a Borrowing

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consisting of Base Rate Advances, by the Borrower to the Agent, which shall give to each Lender prompt notice thereof by electronic communications. Each such notice of a Borrowing (a “Notice of Borrowing”) shall be in writing in substantially the form of Exhibit B hereto, specifying therein the requested (i) date of such Borrowing, (ii) Type of Revolving Advances comprising such Borrowing, (iii) aggregate amount of such Borrowing, and (iv) in the case of a Borrowing consisting of Eurodollar Rate Advances, initial Interest Period for each such Revolving Advance. Each Lender shall, in the case of a Borrowing consisting of Base Rate Advances, before 2:00 p.m. on the date of such Borrowing, and in the case of a Borrowing consisting of Eurodollar Rate Advances, before 11:00 a.m. on the date of such 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 such 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 applicable Notice of Borrowing.

(b)    Anything in subsection (a) above to the contrary notwithstanding, (i) the Borrower may not select Eurodollar Rate Advances for any Borrowing if the aggregate amount of such Borrowing is less than $1,000,000 or if the obligation of the Lenders to make Eurodollar Rate Advances shall then be suspended pursuant to Section 2.08 or Section 2.12 and (ii) at no time shall there be more than fifteen (15) different Interest Periods outstanding for Eurodollar Rate Advances.

(c)    Each Notice of Borrowing shall be irrevocable and binding on the Borrower. In the case of any Borrowing that the related Notice of Borrowing specifies is to be comprised of Eurodollar Rate Advances, the Borrower shall indemnify each Lender against any loss, cost or expense reasonably incurred by such Lender as a result of any failure to fulfill on or before the date specified in such Notice of Borrowing for such Borrowing the applicable conditions set forth in Article III, 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 Revolving Advance to be made by such Lender as part of such Borrowing when such Revolving Advance, as a result of 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 applicable Borrowing that such Lender will not make available to the Agent such Lender’s Ratable Share of such Borrowing, the Agent may assume that such Lender has made such portion available to the Agent on the date of such 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 Revolving Advances comprising such 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, the Agent shall promptly remit to the Borrower the amount of such interest paid by the Borrower

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for such period. If such Lender shall repay to the Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Revolving Advance as part of such Borrowing for purposes of this Agreement.

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

Section 2.03    Letters of Credit.

(a)    General.

(i)    No Issuing Bank shall issue any Letter of Credit, if the expiry date of such requested Letter of Credit would occur after the Letter of Credit Expiration Date, unless all the Lenders have approved such expiry date.

(ii)    No Issuing Bank shall be under any obligation to issue any Letter of Credit if:

(A)    any order, judgment or decree of any Governmental Authority or arbitrator shall by its terms purport to enjoin or restrain such Issuing Bank from issuing such Letter of Credit, or any Law applicable to such Issuing Bank or any request or directive (whether or not having the force of law) from any Governmental Authority with jurisdiction over such Issuing Bank shall prohibit, or request that such Issuing Bank refrain from, the issuance of letters of credit generally or such Letter of Credit in particular or shall impose upon such Issuing Bank with respect to such Letter of Credit any restriction, reserve or capital and liquidity requirement (for which such Issuing Bank is not otherwise compensated hereunder) not in effect on the Effective Date, or shall impose upon such Issuing Bank any unreimbursed loss, cost or expense which was not applicable on the Effective Date and which, in each such case, such Issuing Bank in good faith deems material to it;

(B)    except as otherwise agreed by the Borrower and such Issuing Bank, such Letter of Credit is in an initial stated amount less than $100,000;

(C)    such Letter of Credit is to be denominated in a currency other than Dollars;

(D)    such Letter of Credit contains any provisions for automatic reinstatement of the stated amount after any drawing thereunder;

(E)    subject to Section 2.03(b)(iii), the expiry date of such requested Letter of Credit would occur more than twelve months after the date of issuance or last extension; or

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(F)    any Lender is at such time an Affected Lender hereunder, unless the applicable Issuing Bank is satisfied that the related exposure will be 100% covered by the Commitments of the non-Affected Lenders or, if not so covered, until such Issuing Bank has entered into arrangements satisfactory to it in its sole discretion with the Borrower or such Affected Lender to eliminate such Issuing Bank’s risk with respect to such Affected Lender, and participating interests in any such newly issued Letter of Credit shall be allocated among non-Affected Lenders in a manner consistent with Section 2.19(c)(i) (and Affected Lenders shall not participate therein).

(iii)    No Issuing Bank shall amend any Letter of Credit if such Issuing Bank would not be permitted at such time to issue such Letter of Credit in its amended form under the terms hereof.

(iv)    No Issuing Bank shall be under any obligation to amend any Letter of Credit if (A) such Issuing Bank would have no obligation at such time to issue such Letter of Credit in its amended form under the terms hereof, or (B) the beneficiary of such Letter of Credit does not accept the proposed amendment to such Letter of Credit.

(b)    Procedures for Issuance and Amendment of Letters of Credit; Auto-Extension Letters of Credit.

(i)    Each Letter of Credit shall be issued or amended, as the case may be, upon the request of the Borrower as the applicant thereof (for the support of its or its Subsidiaries’ obligations) delivered to the applicable Issuing Bank (with a copy to the Agent) in the form of a Letter of Credit Application appropriately completed and signed by an Authorized Officer of the Borrower, together with agreed-upon draft language for such Letter of Credit reasonably acceptable to the applicable Issuing Bank. Such Letter of Credit Application must be received by such Issuing Bank and the Agent not later than 11:00 a.m. at least two Business Days (or such later date and time as the Agent and such Issuing Bank may agree in a particular instance in their sole discretion) prior to the proposed issuance date or date of amendment, as the case may be. In the case of a request for an initial issuance of a Letter of Credit, such Letter of Credit Application shall specify in form and detail satisfactory to the applicable Issuing Bank: (A) the proposed issuance date of the requested Letter of Credit (which shall be a Business Day); (B) the amount thereof; (C) the expiry date thereof; (D) the name and address of the beneficiary thereof; (E) the documents to be presented by such beneficiary in case of any drawing thereunder; (F) the full text of any certificate to be presented by such beneficiary in case of any drawing thereunder; (G) the purpose and nature of the requested Letter of Credit; (H) the account party to be named on the requested Letter of Credit, which shall be the Borrower or any of its Subsidiaries, and (I) such other matters as such Issuing Bank may require. In the case of a request for an amendment of any outstanding Letter of Credit, such Letter of Credit Application shall specify in form and detail satisfactory to the applicable Issuing Bank (A) the Letter of Credit to be amended; (B) the proposed date of amendment thereof (which shall be a Business Day); (C) the nature of the proposed amendment; and (D) such other matters as such Issuing Bank may require.

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Additionally, the Borrower shall furnish to the applicable Issuing Bank and the Agent such other documents and information pertaining to such requested Letter of Credit issuance or amendment, including any L/C Related Documents, as the applicable Issuing Bank or the Agent may require. In the event and to the extent that the provisions of any Letter of Credit Application or other L/C Related Document shall conflict with this Agreement, the provisions of this Agreement shall govern. Without limitation of the immediately preceding sentence, to the extent that any such Letter of Credit Application or other L/C Related Document shall impose any additional conditions on the maintenance of a Letter of Credit, any additional default provisions, collateral requirements or other obligations of the Borrower to any Issuing Bank, other than as stated in this Agreement, such additional conditions, provisions, requirements or other obligations shall not have effect so long as this Agreement shall be in effect, except to the extent as expressly agreed to by the Borrower and such Issuing Bank. The Borrower unconditionally and irrevocably agrees that, in connection with any Letter of Credit issued for the support of any Subsidiary’s obligations as provided in the first sentence of this paragraph, the Borrower will be fully responsible for the reimbursement of all L/C Obligations in accordance with the terms hereof, the payment of interest thereon and the payment of fees due hereunder to the same extent as if it were the sole account party in respect of such Letter of Credit (the Borrower hereby irrevocably waiving any defenses that might otherwise be available to it as a guarantor or surety of the obligations of such a Subsidiary that is an account party in respect of any such Letter of Credit).

(ii)    Promptly after receipt of any Letter of Credit Application, the applicable Issuing Bank will confirm with the Agent (by telephone or in writing) that the Agent has received a copy of such Letter of Credit Application from the Borrower and, if not, such Issuing Bank will provide the Agent with a copy thereof. Unless the applicable Issuing Bank has received written notice from the Required Lenders, the Agent or the Borrower, at least one Business Day prior to the requested date of issuance or amendment of the applicable Letter of Credit, that one or more applicable conditions contained in Article III shall not then be satisfied, then, subject to the terms and conditions hereof and any applicable Letter of Credit Application, such Issuing Bank shall, on the requested date, issue a Letter of Credit for the account of the Borrower or enter into the applicable amendment, as the case may be, in each case in accordance with such Issuing Bank’s usual and customary business practices. Immediately upon the issuance of each Letter of Credit, each Lender shall be deemed to, and hereby irrevocably and unconditionally agrees to, purchase from such Issuing Bank a risk participation in such Letter of Credit in an amount equal to the product of such Lender’s Ratable Share times the amount of such Letter of Credit.

(iii)    If the Borrower so requests in any applicable Letter of Credit Application, the applicable Issuing Bank may, in its sole and absolute discretion, agree to issue a Letter of Credit that has automatic extension provisions (each, an “Auto-Extension Letter of Credit”); provided that any such Auto-Extension Letter of Credit must permit such Issuing Bank to prevent any such extension at least once in each twelve-month period (commencing with the date of issuance of such Letter of Credit) by giving prior notice to the beneficiary thereof not later than a day (the “Non-Extension Notice Date”) in each such twelve-month

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period to be agreed upon at the time such Letter of Credit is issued. Unless otherwise directed by the applicable Issuing Bank, the Borrower shall not be required to make a specific request to the applicable Issuing Bank for any such extension. Once an Auto-Extension Letter of Credit has been issued, the Lenders shall be deemed to have authorized (but may not require) the applicable Issuing Bank to permit the extension of such Letter of Credit at any time to an expiry date not later than the Letter of Credit Expiration Date; provided, however, that the applicable Issuing Bank shall not permit any such extension (or may issue a Notice of Non-Extension) if (A) such Issuing Bank has determined that it would not be permitted at such time to issue such Letter of Credit in its revised form (as extended) by reason of the provisions of clause (i) of Section 2.03(a) (or would have no obligation to issue such Letter of Credit by reason of the provisions of clause (ii) of Section 2.03(a)), or (B) it has received notice (which may be by telephone or in writing) on or before the day that is seven Business Days before the Non-Extension Notice Date (1) from the Agent that the Required Lenders have elected not to permit such extension pursuant to Section 6.02 or (2) from the Agent, the Required Lenders or the Borrower that one or more of the applicable conditions specified in Section 3.02 is not then satisfied, and in each such case directing such Issuing Bank not to permit such extension.

(iv)    Promptly after its delivery of any Letter of Credit or any amendment to a Letter of Credit to an advising bank with respect thereto or to the beneficiary thereof, the applicable Issuing Bank will also deliver to the Borrower and the Agent a true and complete copy of such Letter of Credit or amendment.

(c)    Drawings and Reimbursements; Funding of Participations.

(i)    Subject to the provisions below, not later than 2:30 p.m. on the date (the “Honor Date”) that any Issuing Bank makes any payment on a drawing on any Letter of Credit, if the Borrower shall have received notice of such payment prior to 11:30 a.m. on such date, or, if such notice has not been received by the Borrower prior to such time on such date, then not later than 2:30 p.m. on the next Business Day, the Borrower shall reimburse such Issuing Bank through the Agent in an amount equal to the amount of such drawing together with interest thereon. If the Borrower fails to so reimburse such Issuing Bank by such time, unless the Borrower shall have advised the Agent that it does not meet the conditions specified in clause (B) below, the Agent shall promptly notify each Lender of the Honor Date, the amount of the unreimbursed drawing (the “Unreimbursed Amount”), and the amount of such Lender’s Ratable Share thereof. In such event, the Borrower shall be deemed to have requested a Base Rate Advance to be disbursed on the Honor Date in an amount equal to the Unreimbursed Amount, without regard to the minimum and multiples specified in Section 2.01(a) or the delivery of a Notice of Borrowing but subject to (A) the amount of the aggregate Unused Commitments and (B) no Event of Default having occurred and be continuing, or resulting therefrom and, to the extent so financed, the Borrower's obligation to satisfy the reimbursement obligation created by such payment by the Issuing Bank on the Honor Date shall be discharged and replaced by the resulting Base Rate Advance. Any notice given by any Issuing Bank or the Agent pursuant to this Section 2.03(c)(i) may be given by telephone if immediately confirmed in writing; provided that the lack of such

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an immediate confirmation shall not affect the conclusiveness or binding effect of such notice.

(ii)    Each Lender shall upon any notice pursuant to Section 2.03(c)(i) make funds available to the Agent for the account of the applicable Issuing Bank at the Agent’s Office in an amount equal to its Ratable Share of the Unreimbursed Amount not later than 4:00 p.m. on the Business Day specified in such notice by the Agent, whereupon, subject to the provisions of Section 2.03(c)(iii), each Lender that so makes funds available shall be deemed to have made a Base Rate Advance to the Borrower in such amount. The Agent shall remit the funds so received to the applicable Issuing Bank.

(iii)    With respect to any Unreimbursed Amount that is not fully refinanced by a Base Rate Advance because any of the conditions set forth in clauses (A) or (B) of Section 2.03(c)(i) cannot be satisfied or for any other reason, then not later than 2:30 p.m. on the next Business Day after the day notice of the drawing is given to the Borrower, in the case of a failure to meet any such condition, or in any other case, after notice of the event resulting in the outstanding Unreimbursed Amount, the Borrower shall reimburse such Issuing Bank through the Agent in an amount equal to the amount of such outstanding Unreimbursed Amount with interest thereon. If the Borrower fails to so reimburse such Issuing Bank by such time, the Borrower shall be deemed to have incurred from the applicable Issuing Bank an L/C Borrowing in the amount of the Unreimbursed Amount that is not so refinanced, which L/C Borrowing shall be due and payable on demand (together with interest) and shall bear interest at the Base Rate in effect from time to time plus the Applicable Rate for Base Rate Advances in effect from time to time plus 2% per annum. In such event, each Lender’s payment to the Agent for the account of the applicable Issuing Bank pursuant to Section 2.03(c)(ii) shall be deemed payment in respect of its participation in such L/C Borrowing and shall constitute an L/C Advance from such Lender in satisfaction of its participation obligation under this Section 2.03.

(iv)    Until each Lender funds its Base Rate Advance or L/C Advance pursuant to this Section 2.03(c) to reimburse the applicable Issuing Bank for any amount drawn under any Letter of Credit, interest in respect of such Lender’s Ratable Share of such amount shall be solely for the account of the applicable Issuing Bank.

(v)    Each Lender’s obligation to make Base Rate Advances or L/C Advances to reimburse the applicable Issuing Bank for amounts drawn under Letters of Credit, as contemplated by this Section 2.03(c), shall be absolute and unconditional and shall not be affected by any circumstance, including (A) any setoff, counterclaim, recoupment, defense or other right which such Lender may have against such Issuing Bank, the Borrower or any other Person for any reason whatsoever; (B) the occurrence or continuance of a Default, or (C) any other occurrence, event or condition, whether or not similar to any of the foregoing; provided, however, that each Lender’s obligation to make Base Rate Advances pursuant to this Section 2.03(c) is subject to the conditions set forth in Section 2.03(c)(i). No such making of an L/C Advance shall relieve or otherwise impair the obligation of the Borrower

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to reimburse the applicable Issuing Bank for the amount of any payment made by such Issuing Bank under any Letter of Credit, together with interest as provided herein.

(vi)    If any Lender fails to make available to the Agent for the account of the applicable Issuing Bank any amount required to be paid by such Lender pursuant to the foregoing provisions of this Section 2.03(c) by the time specified in Section 2.03(c)(ii), such Issuing Bank shall be entitled to recover from such Lender (acting through the Agent), on demand, such amount with interest thereon for the period from the date such payment is required to the date on which such payment is immediately available to such Issuing Bank at a rate per annum equal to the greater of the Federal Funds Rate and a rate determined by such Issuing Bank in accordance with banking industry rules on interbank compensation, plus any administrative, processing or similar fees customarily charged by such Issuing Bank in connection with the foregoing. If such Lender pays such amount (with interest and fees as aforesaid), the amount so paid shall constitute such Lender’s Base Rate Advance included in the relevant Borrowing or L/C Advance in respect of the relevant L/C Borrowing, as the case may be. A certificate of the applicable Issuing Bank submitted to any Lender (through the Agent) with respect to any amounts owing under this clause (vi) shall be conclusive absent manifest error.

(d)    Repayment of Participations.

(i)    At any time after the applicable Issuing Bank has made a payment under any Letter of Credit and has received from any Lender such Lender’s L/C Advance in respect of such payment in accordance with Section 2.03(c), if the Agent receives for the account of such Issuing Bank any payment in respect of the related Unreimbursed Amount or interest thereon (whether directly from the Borrower or otherwise, including proceeds of Cash Collateral (as defined in Section 2.03(h)) applied thereto by the Agent), the Agent will distribute to such Lender its Ratable Share thereof in the same funds as those received by the Agent.

(ii)    If any payment received by the Agent for the account of the applicable Issuing Bank pursuant to Section 2.03(c)(i) is required to be returned under any of the circumstances described in Section 8.12 (including pursuant to any settlement entered into by such Issuing Bank in its discretion), each Lender shall pay to the Agent for the account of such Issuing Bank its Ratable Share thereof on demand of the Agent, plus interest thereon from the date of such demand to the date such amount is returned by such Lender, at a rate per annum equal to the Federal Funds Rate from time to time in effect. The obligations of the Lenders under this clause shall survive the payment in full of the Obligations and the termination of this Agreement.

(e)    Failure to Make Revolving Advances. The failure of any Lender to make the Revolving Advance to be made by it on the date specified in Section 2.03(c) or any L/C Advance shall not relieve any other Lender of its obligation hereunder to make its Revolving Advance or L/C Advance, as the case may be, to be made by such other Lender on such date.

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(f)    Obligations Absolute. The obligation of the Borrower to reimburse the applicable Issuing Bank for each drawing under each Letter of Credit and to repay each L/C Borrowing shall be absolute, unconditional and irrevocable, and shall be paid strictly in accordance with the terms of this Agreement under all circumstances, including the following:

(i)    any lack of validity or enforceability of such Letter of Credit, this Agreement, or any other Loan Document;

(ii)    the existence of any claim, counterclaim, setoff, defense or other right that the Borrower may have at any time against any beneficiary or any transferee of such Letter of Credit (or any Person for whom any such beneficiary or any such transferee may be acting), any Issuing Bank or any other Person, whether in connection with this Agreement, the transactions contemplated hereby or by such Letter of Credit or any agreement or instrument relating thereto, or any unrelated transaction;

(iii)    any draft, demand, certificate or other document presented under such Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect; or any loss or delay in the transmission or otherwise of any document required in order to make a drawing under such Letter of Credit;

(iv)    any payment by the applicable Issuing Bank under such Letter of Credit against presentation of a draft or certificate that does not strictly comply with the terms of such Letter of Credit; or any payment made by the applicable Issuing Bank under such Letter of Credit to any Person purporting to be a trustee in bankruptcy, debtor-in-possession, assignee for the benefit of creditors, liquidator, receiver or other representative of or successor to any beneficiary or any transferee of such Letter of Credit, including any arising in connection with any proceeding under any Debtor Relief Law; or

(v)    any other circumstance or happening whatsoever, whether or not similar to any of the foregoing, including any other circumstance that might otherwise constitute a defense available to, or a discharge of, the Borrower.

provided, however, that nothing in this Section 2.03(f) shall limit the rights of the Borrower under Section 2.03(g).

The Borrower shall promptly examine a copy of each Letter of Credit and each amendment thereto that is delivered to it and, in the event of any claim of noncompliance with the Borrower’s instructions or other irregularity that is known to the Borrower in connection with any draw under such Letter of Credit of which the Borrower has reasonable notice, the Borrower will immediately notify the applicable Issuing Bank. To the extent allowed by applicable Law, Borrower shall be conclusively deemed to have waived any such claim against the applicable Issuing Bank and its correspondents unless such notice is given as aforesaid. Nothing herein shall require the Borrower to make any determination as to whether the drawing is in accordance with the requirements of the Letter of Credit, provided that the Borrower may waive any discrepancies in the drawing on any such Letter of Credit.

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(g)    Role of Issuing Bank. Each Lender and the Borrower agree that, in paying any drawing under a Letter of Credit, the applicable Issuing Bank shall not have any responsibility to obtain any document (other than any sight draft, certificates and documents expressly required by the Letter of Credit) or to ascertain or inquire as to the validity or accuracy of any such document or the authority of the Person executing or delivering any such document. None of the applicable Issuing Bank, the Agent, any of their respective Related Parties nor any correspondent, participant or assignee of such Issuing Bank shall be liable to any Lender for (i) any action taken or omitted in connection herewith at the request or with the approval of the Lenders or the Required Lenders, as applicable; (ii) any action taken or omitted in the absence of gross negligence or willful misconduct; or (iii) the due execution, effectiveness, validity or enforceability of any document or instrument related to any Letter of Credit or L/C Related Document. The Borrower hereby assumes all risks of the acts or omissions of any beneficiary or transferee with respect to its use of any Letter of Credit; provided, however, that this assumption is not intended to, and shall not, preclude the Borrower’s pursuing such rights and remedies as it may have against the beneficiary or transferee at Law or under any other agreement. None of the applicable Issuing Bank, the Agent, any of their respective Related Parties nor any correspondent, participant or assignee of such Issuing Bank shall be liable or responsible for any of the matters described in clauses (i) through (v) of Section 2.03(f); provided, however, that anything in such clauses to the contrary notwithstanding, the Borrower may have a claim against the applicable Issuing Bank, and such Issuing Bank may be liable to the Borrower, to the extent, but only to the extent, of any direct, as opposed to consequential or exemplary, damages suffered by the Borrower which the Borrower proves were caused by such Issuing Bank’s willful misconduct or gross negligence or such Issuing Bank’s willful failure to pay under any Letter of Credit after the presentation to it by the beneficiary of a sight draft and certificate(s) strictly complying with the terms and conditions of a Letter of Credit. In furtherance and not in limitation of the foregoing, the applicable Issuing Bank may accept documents that appear on its face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary, and such Issuing Bank shall not be responsible for the validity or sufficiency of any instrument transferring or assigning or purporting to transfer or assign a Letter of Credit or the rights or benefits thereunder or proceeds thereof, in whole or in part, which may prove to be invalid or ineffective for any reason.

(h)    Cash Collateral. Upon the request of the Agent or the applicable Issuing Bank, if, as of the Letter of Credit Expiration Date, any L/C Obligation for any reason remains outstanding, the Borrower shall, in each case, immediately Cash Collateralize the then outstanding L/C Obligations. Section 6.02 sets forth certain additional requirements to deliver Cash Collateral hereunder. For purposes of this Section 2.03, Section 2.10(b)(ii), Section 2.19(c) (ii), (iv) and (v) and Section 6.02, “Cash Collateralize” means to pledge and deposit with or deliver to the Agent, for the benefit of the Issuing Banks and the Lenders, as collateral for the L/C Obligations, cash or deposit account balances pursuant to documentation in form and substance satisfactory to the Agent and each Issuing Bank (which documents are hereby consented to by the Lenders) in an amount equal to 100% of the amount of the L/C Obligations as of such date plus any accrued and unpaid interest and fees thereon. Derivatives of such term have corresponding meanings. The Borrower hereby grants to the Agent, for the benefit of the Issuing Banks and the Lenders, a security interest in all such cash, deposit accounts and all balances therein and all proceeds of the foregoing. Cash Collateral shall be maintained in blocked, non-interest bearing deposit accounts with the Agent.

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(i)    Letter of Credit Reports. Each Issuing Bank shall furnish (A) to the Agent on the first Business Day of each month a written report summarizing issuance and expiration dates of Letters of Credit issued by such Issuing Bank during the preceding month and drawings during such month under all such Letters of Credit and (B) to the Agent on the first Business Day of each calendar quarter a written report setting forth the average daily aggregate Available Amount during the preceding calendar quarter of all Letters of Credit issued by such Issuing Bank.

(j)    Interim Interest. Except as provided in Section 2.03(c)(ii) with respect to Unreimbursed Amounts refinanced as Base Rate Advances and Section 2.03(c)(iii) with respect to L/C Borrowings, unless the Borrower shall reimburse each payment by an Issuing Bank pursuant to a Letter of Credit in full on the Honor Date, the Unreimbursed Amount thereof shall bear interest, for each day from and including the Honor Date to but excluding the date that the Borrower reimburses such Issuing Bank for the Unreimbursed Amount in full, at the rate per annum equal to (i) the Base Rate in effect from time to time plus the Applicable Rate for Base Rate Advances in effect from time to time, to but excluding the next Business Day after the Honor Date and (ii) from and including the next Business Day after the Honor Date, the Base Rate in effect from time to time plus the Applicable Rate for Base Rate Advances in effect from time to time plus 2% per annum.

Section 2.03A    Swingline Advances.

(a)    Amount of Swingline Advances. Subject to the terms and conditions set forth herein, the Swingline Lender will make Swingline Advances in Dollars to the Borrower from time to time during the period from the Effective Date until the Termination Date, in an aggregate principal amount at any time outstanding that will not result in (i) the aggregate principal amount of all outstanding Swingline Advances exceeding $0 (or such lesser amount as agreed between the Borrower and the Swingline Lender) or (ii) the Total Outstandings exceeding the aggregate Revolving Credit Commitment. Each Swingline Advance shall be in an aggregate amount of $0 or an integral multiple of $0 in excess thereof or such greater amounts as agreed between the Borrower and the Swingline Lender. Within the foregoing limits and subject to the terms and conditions set forth herein, the Borrower may borrow, prepay and reborrow Swingline Advances. The Swingline Lender shall be under no obligation to make a Swingline Advance if any Lender is at such time an Affected Lender hereunder, unless the Swingline Lender is satisfied that the related exposure will be 100% covered by the Commitments of the non-Affected Lenders or, if not so covered, until the Swingline Lender has entered into arrangements satisfactory to it in its sole discretion with the Borrower or such Affected Lender to eliminate the Swingline Lender’s risk with respect to such Affected Lender, and participating interests in any such newly made Swingline Advance shall be allocated among non-Affected Lenders in a manner consistent with Section 2.19(c)(i) (and Affected Lenders shall not participate therein).

(b)    Borrowing Notice and Making of Swingline Advances. To request a Swingline Advance, the Borrower shall notify the Swingline Lender and the Agent of such request by telephone (confirmed by electronic communications), not later than 2:00 p.m. (or such later time as the Swingline Lender may determine in its sole discretion), on the day of such Swingline Advance. Each such notice shall be irrevocable and shall specify the requested date (which shall be a Business Day) and amount of the requested Swingline Advance. The Swingline Lender shall promptly notify

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the Borrower and the Agent (and the Agent shall promptly notify each Lender) and the Swingline Lender shall make each Swingline Advance available to the Borrower by 2:30 p.m. (or such later time as may be agreed by the Swingline Lender and the Borrower) on the requested date of such Swingline Advance in a manner agreed upon by the Borrower and the Swingline Lender. Each Swingline Advance shall bear interest at the Base Rate, or, at the option of the Borrower and subject to prior agreement between the Borrower and the Swingline Lender, shall be a Swingline Eurodollar Rate Advance or a Money Market Rate Advance.

(c)    Repayment of Swingline Advances. Each Swingline Advance shall be paid in full by the Borrower on the earlier of (x) on or before the fourteenth (14^th) Business Day after the date such Swingline Advance was made by the Swingline Lender or (y) the Termination Date. A Swingline Advance may not be repaid with the proceeds from another Swingline Advance. In addition, the Swingline Lender (i) may at any time in its sole discretion with respect to any outstanding Swingline Advance, or (ii) shall, on the fourteenth (14^th) Business Day after the date any Swingline Advance is made and which has not been otherwise repaid, require each Lender (including the Swingline Lender) to make a Revolving Advance in the amount of such Lender’s Ratable Share of such Swingline Advance (including, without limitation, any interest accrued and unpaid thereon), for the purpose of repaying such Swingline Advance. Not later than 2:00 p.m. on the date of any notice received pursuant to this Section 2.03A(c), each Lender shall make available to the Agent its required Revolving Advance, in immediately available funds in the same manner as provided in Section 2.02(a) with respect to Revolving Advances made by such Lender. Revolving Advances made pursuant to this Section 2.03A(c) shall initially be Base Rate Advances and thereafter may be continued as Base Rate Advances or converted into Eurodollar Rate Advances in the manner provided in Section 2.09 and subject to the other conditions and limitations set forth in this Article II. Each Lender’s obligation to make Revolving Advances pursuant to this Section 2.03A(c) to repay Swingline Advances shall be unconditional, continuing, irrevocable and absolute and shall not be affected by any circumstances, including, without limitation, (a) any set-off, counterclaim, recoupment, defense or other right which such Lender may have against the Agent, the Swingline Lender or any other Person, (b) the occurrence or continuance of a Default or an Event of Default, (c) any adverse change in the condition (financial or otherwise) of the Borrower, or (d) any other circumstance, happening or event whatsoever. In the event that any Lender fails to make payment to the Agent of any amount due under this Section 2.03A(c), the Agent shall be entitled to receive, retain and apply against such obligation the principal and interest otherwise payable to such Lender hereunder until the Agent receives such payment from such Lender or such obligation is otherwise fully satisfied. In addition to the foregoing, if for any reason any Lender fails to make payment to the Agent of any amount due under this Section 2.03A(c), such Lender shall be deemed, at the option of the Agent, to have unconditionally and irrevocably purchased from the Swingline Lender without recourse or warranty, an undivided interest and participation in the applicable Swingline Advance in the amount of such Revolving Advance, and such interest and participation may be recovered from such Lender together with interest thereon at the Federal Funds Rate for each day during the period commencing on the date of demand and ending on the date such amount is received.

(d)    Swingline Advances Reports. The Swingline Lender shall furnish to the Agent on each Business Day a written report summarizing outstanding Swingline Advances made by the

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Swingline Lender and the due date for the repayment of such Swingline Advances; provided that if no Swingline Advances are outstanding, no such report shall be required to be delivered.

(e)    Successor Swingline Lender. Subject to the appointment and acceptance of a successor Swingline Lender as provided in this paragraph, the Borrower may, upon not less than ten (10) Business Days prior notice to the Agent and the Lenders, replace the existing Swingline Lender with the consent of the Agent (which consent shall not unreasonably be withheld). Upon the acceptance of its appointment as Swingline Lender hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the replaced Swingline Lender, and the replaced Swingline Lender shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to a successor Swingline Lender shall be as agreed between the Borrower and such successor. After the Swingline Lender’s replacement hereunder, the provisions of this Article and Section 8.04 shall continue in effect for its benefit in respect of any actions taken or omitted to be taken by it while it was acting as Swingline Lender.

Section 2.04    Fees.

(a)    Commitment Fee. The Borrower agrees to pay to the Agent for the account of each Lender a commitment fee on such Lender’s Unused Commitment (provided that, for the avoidance of doubt, and without duplication, such Lender’s Unused Commitment shall be calculated exclusive of such Lender’s Swingline Exposure and, if such Lender is the Swingline Lender, without giving effect to the Swingline Advances, and in no event shall the aggregate of such commitment fees exceed an amount calculated based on the product of (a) the aggregate Revolving Credit Commitments minus the aggregate principal amount of all Revolving Advances and aggregate L/C Obligations and (b) the Applicable Rate for commitment fees) from the Effective Date in the case of each Initial Lender and from the effective date specified in the Assignment and Assumption pursuant to which it became a Lender in the case of each other Lender until the Termination Date at a rate per annum equal to the Applicable Rate for commitment fees in effect from time to time, payable in arrears quarterly on the last day of each March, June, September and December, commencing September 30, 2016, and on the Termination Date, provided that no commitment fee shall accrue with respect to the Unused Commitment of an Affected Lender so long as such Lender shall be an Affected Lender.

(b)    Letter of Credit Fees.

(i)    The Borrower shall pay to the Agent for the account of each Lender a commission on such Lender’s Ratable Share of the average daily aggregate Available Amount of all Letters of Credit outstanding from time to time at a rate per annum equal to the Applicable Rate for Eurodollar Rate Advances in effect from time to time, during such calendar quarter, payable in arrears quarterly on the last day of each March, June, September and December, commencing with the quarter ended September 30, 2016, and on the Termination Date; provided that the Applicable Rate for Eurodollar Rate Advances shall be 2% above such Applicable Rate in effect upon the occurrence and during the continuation of an Event of Default if the Borrower is required to pay default interest pursuant to Section 2.07(b).

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(ii)    The Borrower shall pay to each Issuing Bank, for its own account, a fronting fee with respect to each Letter of Credit issued by such Issuing Bank, payable in the amounts and at the times specified in the applicable Fee Letter between the Borrower and such Issuing Bank, and such other commissions, issuance fees, transfer fees and other fees and charges in connection with the issuance or administration of each Letter of Credit as the Borrower and such Issuing Bank shall agree promptly following receipt of an invoice therefor.

(c)    Agent’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 2.05    Optional Termination or Reduction of the Commitments.

(a)    The Borrower shall have the right, upon at least three Business Days’ notice to the Agent, to terminate in whole or permanently reduce ratably in part the Unused Commitments or the Unissued Letter of Credit Commitments, provided that each partial reduction shall be in the aggregate amount of $10,000,000 or an integral multiple of $1,000,000 in excess thereof.

(b)    So long as no Default or Event of Default shall be continuing, the Borrower shall have the right, at any time, upon at least ten Business Days’ notice to an Affected Lender (with a copy to the Agent), to terminate in whole such Lender’s Revolving Credit Commitment and, if applicable, its Letter of Credit Commitment, without affecting the Commitments of any other Lender. Such termination shall be effective, (x) with respect to such Lender’s Unused Commitment, on the date set forth in such notice, provided, however, that such date shall be no earlier than ten Business Days after receipt of such notice and (y) with respect to each Revolving Advance outstanding to such Lender, in the case of Base Rate Advances, on the date set forth in such notice and, in the case of Eurodollar Rate Advances, on the last day of the then current Interest Period relating to such Revolving Advance. Upon termination of a Lender’s Commitments under this Section 2.05(b), the Borrower will pay or cause to be paid all principal of, and interest accrued to the date of such payment on, Revolving Advances (and if such Lender is the Swingline Lender, the Swingline Advances) owing to such Lender and, subject to Section 2.19, pay any accrued commitment fees or Letter of Credit fees payable to such Lender pursuant to the provisions of Section 2.04, and all other amounts payable to such Lender hereunder (including, but not limited to, any increased costs or other amounts owing under Section 2.11 and any indemnification for Taxes under Section 2.14); and, if such Lender is an Issuing Bank, shall pay to such Issuing Bank for deposit in an escrow account an amount equal to the Available Amount of all Letters of Credit issued by such Issuing Bank, whereupon all Letters of Credit issued by such Issuing Bank shall be deemed to have been issued outside of this Agreement on a bilateral basis and shall cease for all purposes to constitute a Letter of Credit issued under this Agreement, and upon such payments, except as otherwise provided below, the obligations of such Lender hereunder shall, by the provisions hereof, be released and discharged; provided, however, that (i) such Lender’s rights under Section 2.11, Section 2.14 and Section 8.04, and, in the case of an Issuing Bank, Section 8.04(c), and its obligations under Section 8.04 and 8.08, in each case in accordance with the terms thereof, shall survive such release and discharge as to matters occurring prior to such date and (ii) such escrow agreement shall be in a form reasonably agreed to by the Borrower and such Issuing Bank, but in

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no event shall either the Borrower or such Issuing Bank require any waivers, covenants, events of default or other provisions that are more restrictive than or inconsistent with the provisions of this Agreement. The aggregate amount of the Commitments of the Lenders once reduced pursuant to this Section 2.05(b) may not be reinstated. The termination of the Commitments of an Affected Lender pursuant to this Section 2.05(b) will not be deemed to be a waiver of any right that the Borrower, the Agent, any Issuing Bank, the Swingline Lender or any other Lender may have against the Affected Lender that arose prior to the date of such termination. Upon any such termination, the Ratable Share of each remaining Lender will be revised.

Section 2.06    Repayment of Advances. The Borrower shall repay to the Agent for the ratable account of the Lenders on the Termination Date the aggregate principal amount of the Revolving Advances made by such Lender and then outstanding. The Borrower shall repay Swingline Advances in accordance with Section 2.03A(c).

Section 2.07    Interest on Advances.

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

(i)    Base Rate Advances. During such periods as such Revolving Advance is a Base Rate Advance, 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 Advances 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 Advance shall be Converted or paid in full.

(ii)    Eurodollar Rate Advances. During such periods as such Revolving Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during each Interest Period for such Revolving Advance to the sum of (x) the Eurodollar Rate for such Interest Period for such Revolving Advance plus (y) the Applicable Rate for Eurodollar Rate Advances 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 Advance shall be Converted or paid in full.

(iii)    Swingline Advances. During such period as such Swingline Advance remains outstanding, the Base Rate or, as agreed to by the Swingline Lender and the Borrower, the Money Market Rate or the Eurodollar Rate, payable on the date such Swingline Advance is required to be repaid.

(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 Advance owing to each Lender, payable in arrears on the dates referred to in clause (a)(i), (a)(ii) or (a)(iii) above, at a rate per annum equal at all times to 2% per annum above the rate per annum

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required to be paid on such Advance pursuant to clause (a)(i), (a)(ii) or (a)(iii) above and (ii) to the fullest extent permitted 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 Advances pursuant to clause (a)(i) above, provided, however, that following acceleration of the Advances 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 2.08    Interest 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 2.07(a).

(b)    If the Required Lenders determine that for any reason in connection with any request for a Eurodollar Rate Advance 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 Advance, (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 Advance, or (c) the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Rate Advance does not adequately and fairly reflect the cost to such Lenders of funding such Revolving Advance, the Agent will promptly so notify the Borrower and each Lender, whereupon each Eurodollar Rate Advance will automatically on the last day of the then existing Interest Period therefor Convert into a Base Rate Advance. Thereafter, the obligation of the Lenders to make or maintain Eurodollar Rate Advances 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 Advances or, failing that, will be deemed to have Converted such request into a request for a Base Rate Advance in the amount specified therein.

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(c)    If the Borrower shall fail to select the duration of any Interest Period for any Eurodollar Rate Advances in accordance with the provisions contained in the definition of “Interest Period” in Section 1.01, the Agent will forthwith so notify the Borrower and the Lenders and such Revolving Advances will automatically, on the last day of the then existing Interest Period therefor, Convert into Base Rate Advances.

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

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

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

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

Section 2.09    Optional Conversion of Revolving Advances. The Borrower may on any Business Day, upon notice given to the Agent 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 Section 2.08 and Section 2.12, Convert all Revolving Advances of one Type comprising the same Borrowing into Revolving Advances of the other Type; provided, however, that (a) any Conversion of Eurodollar Rate Advances into Base Rate Advances shall be made only on the last day of an Interest Period for such Eurodollar Rate Advances, (b) any Conversion of Base Rate Advances into Eurodollar Rate Advances shall be in an amount not less than the minimum amount specified in Section 2.02(b), (c) no Conversion of any Revolving Advances shall result in more separate Borrowings than permitted under Section 2.02(b) and (d) no Swingline Advances may be converted. Each such notice of a Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Revolving Advances to be Converted, and (iii) if such Conversion is into Eurodollar Rate Advances, the duration of the initial Interest Period for each such Revolving Advance. Each notice of Conversion shall be irrevocable and binding on the Borrower.

Section 2.10    Prepayments of Advances.

(a)    Optional. At any time and from time to time, the Borrower shall have the right to prepay any Advance, in whole or in part, without premium or penalty (except as provided in clause (y) below), upon notice at least two Business Days’ prior to the date of such prepayment, in the case of Eurodollar Rate Advances, and not later than 11:00 a.m. on the date of such prepayment in the case of Base Rate Advances and Swingline Advances, to the Agent (and, in the case of prepayment a Swingline Advance, the Swingline Lender) specifying the proposed date of such

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prepayment and the aggregate principal amount and Type of the Advance to be prepaid (and, in the case of Eurodollar Rate Advances, 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, and shall be accompanied by accrued interest to the date of prepayment on the principal amount prepaid, and (y) in the event of any such prepayment of a Eurodollar Rate Advance, the Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.04(e).

(b)    Mandatory.

(i)    The Borrower shall prepay the aggregate principal amount of the Advances, 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 or applicable resolutions of the Board of Directors of the Borrower.

(ii)    If for any reason the Total Outstandings at any time exceed the aggregate Revolving Credit Commitments then in effect, the Borrower shall, within one Business Day after notice thereof, prepay Advances and/or Cash Collateralize the L/C Obligations in an aggregate amount equal to such excess; provided, however, that the Borrower shall not be required to Cash Collateralize the L/C Obligations pursuant to this Section 2.10(b) unless, after the prepayment in full of the Advances, the Total Outstandings exceed the aggregate Revolving Credit Commitments then in effect.

Section 2.11    Increased 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 2.11(e)) or any Issuing Bank;

(ii)    impose on any Lender or any Issuing Bank or the London interbank market any other condition, cost or expense affecting this Agreement or Eurodollar Rate Advances made by such Lender or any Letter of Credit or participation therein; 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 Advance (or of maintaining its obligation to make any such Revolving Advance), or to increase the cost to the Agent, such Lender or such Issuing Bank of participating

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in, issuing or maintaining any Letter of Credit (or of maintaining its obligation to participate in or to issue any Letter of Credit), or to reduce the amount of any sum received or receivable by the Agent, such Lender or such Issuing Bank hereunder (whether of principal, interest or any other amount) then, upon request of the Agent, such Lender or such Issuing Bank, the Borrower will pay to the Agent, such Lender or such Issuing Bank, as the case may be, such additional amount or amounts as will compensate the Agent, such Lender or such Issuing Bank, as the case may be, for such additional costs incurred or reduction suffered.

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

(c)    Certificates for Reimbursement. A certificate of a Lender or an Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or such Issuing Bank 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 or such Issuing Bank, as the case may be, 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 or any Issuing Bank to demand compensation pursuant to the foregoing provisions of this Section shall not constitute a waiver of such Lender’s or such Issuing Bank’s right to demand such compensation, provided that the Borrower shall not be required to compensate a Lender or an Issuing Bank 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 or such Issuing Bank, as the case may be, notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s or such Issuing Bank’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 Advances. 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 Advance

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equal to the actual costs of such reserves allocated to such Revolving Advance 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 Eurodollar Rate Advance, 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 2.12    Illegality. 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 Advances, 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 Advances or to Convert Base Rate Advances to Eurodollar Rate Advances 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 Advances of such Lender to Base Rate Advances, either on the last day of the Interest Period therefor, if such Lender may lawfully continue to maintain such Eurodollar Rate Advances to such day, or immediately, if such Lender may not lawfully continue to maintain such Eurodollar Rate Advances. Upon any such prepayment or Conversion, the Borrower shall also pay accrued interest on the amount so prepaid or Converted.

Section 2.13    Payments 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 U.S. 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, fees or commissions ratably (other than amounts payable pursuant to Section 2.05(b), Section 2.11, Section 2.12, Section 2.14, Section 2.20 or Section 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.

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(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 and of fees and Letter of Credit commissions 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, fees or commissions are payable. Interest on Swingline Advances shall be calculated on the basis of a year of 360 days or such other basis agreed to by the Swingline Lender and the Borrower, 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 is 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, fees or commissions, as the case may be; provided, however, that, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances 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.

Section 2.14    Taxes.

(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

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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, Lender or Issuing Bank, 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, each Lender and each Issuing Bank, 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, such Lender or such Issuing Bank, 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 or an Issuing Bank 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 or an Issuing Bank (with a copy to the Agent), or by the Agent on its own behalf or on behalf of a Lender or an Issuing Bank, shall be conclusive absent manifest error.

(ii)    Each Lender and each Issuing Bank shall, within 30 days after demand therefor, severally (A) indemnify the Agent for (x) any Indemnified Taxes and Other Taxes attributable to such Lender or such Issuing Bank (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), (y) any Taxes attributable to such Lender’s or such Issuing Bank’s failure to comply with the provisions of Section 8.07(d) relating to the maintenance of a Participant Register and (z) for any Excluded Taxes attributable to such Lender or such Issuing Bank, 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, and (B) indemnify the Borrower and the Agent against any and all Taxes and any and all related losses, claims, liabilities, penalties, interest and expenses (including the fees, charges and disbursements

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of any counsel for the Borrower orthe Agent) incurred by or asserted against the Borrower or the Agent by any Governmental Authority as a result of the failure by such Lender or such Issuing Bank, as the case may be, to deliver, or as a result of the inaccuracy, inadequacy or deficiency of, any documentation required to be delivered by such Lender or such Issuing Bank, as the case may be, to the Borrower or the Agent pursuant to subsection (e). A certificate as to the amount of such payment or liability delivered to any Lender or any Issuing Bank by the Agent shall be conclusive absent manifest error. Each Lender and each Issuing Bank hereby authorizes the Agent to set off and apply any and all amounts at any time owing to such Lender or such Issuing Bank, as the case may be, under this Agreement or any other Loan Document or otherwise payable by the Agent to the Lender or the Issuing Bank from any other source against any amount due to the Agent under this clause (ii). The agreements in this clause (ii) shall survive the resignation and/or replacement of the Agent, any assignment of rights by, or the replacement of, a Lender or an Issuing Bank, the termination of the Commitments and the repayment, satisfaction or discharge of all other Obligations.

(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 2.14, 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 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,

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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-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.

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(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 an Issuing Bank, or have any obligation to pay to any Lender or any Issuing Bank, any refund of Taxes withheld or deducted from funds paid for the account of such Lender or such Issuing Bank, as the case may be. If the Agent, any Lender or any Issuing Bank 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, such Lender or such Issuing Bank, 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, such Lender or such Issuing Bank, 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, such Lender or such Issuing Bank in the event the Agent, such Lender or such Issuing Bank is required to repay such refund to such Governmental Authority. This subsection shall not be construed to require the Agent, any Lender or any Issuing Bank 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, any Lender or any Issuing Bank to demand compensation pursuant to the foregoing provisions of this Section 2.14 shall not constitute a waiver of the Agent’s, such Lender’s or such Issuing Bank’s right to demand such compensation, provided that the Borrower shall not be required to compensate the Agent, a Lender or an Issuing Bank pursuant to the foregoing provisions of this Section 2.14 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, such Lender or such Issuing Bank, 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)    Each of the Agent, any Issuing Bank or any 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 2.14 if (i) the Borrower has agreed in writing to pay all of the Agent’s or such Issuing Bank’s or such Lender’s reasonable out-of-pocket costs and expenses relating to such claim, (ii) the Agent or such Issuing Bank 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 Issuing Bank 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 such Issuing Bank or the Agent) that the Borrower is likely to receive a refund or credit.

Section 2.15    Sharing 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 Advances or L/C Advances owing to it (other than pursuant to Section 2.05(b), Section 2.11, Section 2.12, Section 2.14, Section 2.20 or Section 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 Advances or participations in Letters of Credit 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 2.15 shall apply) in excess of its Ratable Share of payments on account of the Advances obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders (for cash at face value) such participations in the Advances 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 2.15 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 2.16    Evidence 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 Advance 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 Advances. The Borrower agrees that upon notice by any Lender (including the Swingline 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 Advances owing to, or to be made by, such Lender, the Borrower shall promptly execute and deliver to such Lender a Note

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payable to the order of such Lender in a principal amount up to the Revolving Credit Commitment of such Lender.

(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 Advances 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 2.17    Use of Proceeds. The proceeds of the Advances and issuances of Letters of Credit shall be available (and the Borrower agrees that it shall use such proceeds) solely to directly or indirectly fund or otherwise support 4C Sub or related obligations.

Section 2.18    Reserved.

Section 2.19    Affected 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)    fees shall cease to accrue on the Unused Commitment of such Affected Lender pursuant to Section 2.04(a);

(b)    the Revolving Credit Commitment and Advances 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;

(c)    if (x) there shall be any Available Amount under any outstanding Letter of Credit or (y) any Swingline Exposure shall exist during any time a Lender is an Affected Lender, then:

(i)    so long as no Default or Event of Default has occurred and is continuing, all or any part of the Available Amount of all such Letters of Credit and Swingline Exposure shall be reallocated among the non-Affected Lenders in accordance with their respective

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Ratable Shares (disregarding any Affected Lender’s Revolving Credit Commitment) but only to the extent that with respect to each non-Affected Lender the sum of (A) the aggregate principal amount of all Revolving Advances made by such non-Affected Lender (in its capacity as a Lender) and outstanding at such time plus (B) such non-Affected Lender’s Ratable Share (after giving effect to the reallocation contemplated in this Section 2.19(c)(i)) of the outstanding L/C Obligations plus (C) such non-Affected Lender’s Ratable Share (after giving effect to the reallocation contemplated in this Section 2.19(c)(i)) of the outstanding Swingline Exposure, does not exceed such non-Affected Lender’s Revolving Credit Commitment;

(ii)    if the reallocation described in clause (i) above cannot, or can only partially, be effected, the Borrower shall within one (1) Business Day following notice by the Agent (x) first, prepay such unallocable Swingline Exposure and (y) second, Cash Collateralize for the benefit of the applicable Issuing Bank only the Borrower’s obligations corresponding to such Affected Lender’s Ratable Share of the Available Amount of outstanding Letters of Credit (after giving effect to any partial reallocation pursuant to clause (i) above) (the “Affected Lender Share”) in accordance with the procedures set forth in Section 2.03(h) for so long as such there shall be any Available Amount of outstanding Letters of Credit;

(iii)    if the Ratable Share of the Available Amount of outstanding Letters of Credit and the Swingline Exposure of the non-Affected Lenders is reallocated pursuant to this Section 2.19(c), then the fees payable to the Lenders pursuant to Section 2.04(a) and Section 2.04(b)shall be adjusted in accordance with such non-Affected Lenders’ Ratable Shares;

(iv)    if any Affected Lender Share is not reallocated pursuant to clause (i) above and if the Borrower fails to Cash Collateralize any portion of such Affected Lender Share pursuant to clause (ii) above, then, without prejudice to any rights or remedies of any Issuing Bank or any Lender hereunder, the fee payable under Section 2.04(b) with respect to such Affected Lender Share shall be payable to the Issuing Bank until such Affected Lender Share is reallocated; and

(v)    if the Borrower Cash Collateralizes any portion of any Affected Lender Share pursuant to clause (ii) above, the Borrower shall not be required to pay any fees to such Affected Lender pursuant to Section 2.04(b)(i) or the applicable Issuing Bank pursuant to Section 2.04(b)(ii) (solely with respect to any fronting fee) with respect to such Affected Lender’s Affected Lender Share during the period such Affected Lender’s Affected Lender Share is Cash Collateralized;

(d)    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 Revolving Advance under Section 2.03(c) or Section 2.03A(c) or L/C Advance or any other unfunded payment obligation of such Affected Lender under this Agreement; and

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(e)    subject to Section 8.18, for the avoidance of doubt, the Borrower, each Issuing Bank, the Swingline Lender, 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, the Borrower, the Swingline Lender and the Issuing Banks each agrees that an Affected Lender has adequately remedied all matters that caused such Lender to be an Affected Lender, then the Ratable Shares of the Lenders shall be readjusted to reflect the inclusion of such Lender’s Revolving Credit Commitment and on such date such Lender shall purchase at par such of the Revolving Advances of the other Lenders as the Agent shall determine may be necessary in order for such Lender to hold such Revolving Advances in accordance with its Ratable Share. In addition, at such time as the Affected Lender is replaced by another Lender pursuant to Section 2.20, the Ratable Shares of the Lenders will be readjusted to reflect the inclusion of the replacing Lender’s Commitment in accordance with Section 2.20. In either such case, this Section 2.19 will no longer apply.

Section 2.20    Replacement of Lenders. If any Lender requests compensation under Section 2.11, 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 2.14, 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, if a 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 of its Revolving Advances and L/C Advances, 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 2.11 or payments required to be made pursuant to Section 2.14, 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.

Section 2.21    Reserved

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ARTICLE III

CONDITIONS PRECEDENT

Section 3.01    Conditions 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 and the reasonable accrued fees and expenses of one law firm acting as counsel to the Agent that have been invoiced at least one Business Day prior to the Effective Date.

(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, and

(ii)    No event has occurred and is continuing that constitutes a Default.

(d)    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 2.16.

(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 and governmental approvals, if any, with respect to this Agreement and the Notes.

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(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 its state of organization or formation.

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

(ix)    A favorable opinion of Sidley Austin LLP, counsel for the Agent, in form and substance reasonably acceptable to the Lenders.

(e)    Reserved.

(f)    Reserved.

(g)    Reserved.

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

Section 3.02    Conditions Precedent to Each Credit Extension. The obligation of each Lender to make an Advance (other than an L/C Advance or an Advance made pursuant to Section 2.03(c) or Section 2.03A(c)) on the occasion of each Borrowing and the obligation of each Issuing Bank to issue a Letter of Credit shall be subject to the conditions precedent that the Effective Date shall have occurred and on the date of such Borrowing or such issuance (as the case may be), the following statements shall be true (and each of the giving of the applicable Notice of Borrowing or request for issuance and the acceptance by the Borrower of the proceeds of such Borrowing shall constitute a representation and warranty by the Borrower that on the date of such Borrowing or date of such issuance such statements are true):

(a)    the representations and warranties contained in Section 4.01 (other than Section 4.01(k)), and in the case of a Borrowing or issuance of a Letter of Credit, Section 4.01(e)(ii) and Section 4.01(f)(ii)) are correct on and as of such date, before and after giving effect to such Borrowing or issuance of a Letter of Credit and to the application of the proceeds therefrom, as though made on and as of such date; and

(b)    no event has occurred and is continuing, or would result from such Borrowing or issuance of a Letter of Credit or from the application of the proceeds therefrom, that constitutes a Default.

Each request for Credit Extension (which shall not include a Conversion or a continuation of Eurodollar Rate Advances) submitted by the Borrower shall be deemed to be a representation and warranty that the conditions specified in Section 3.02(a) and (b) have been satisfied on and as of the date of the applicable Credit Extension.

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Section 3.03    Determinations 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 Section 4.01(a), Section 4.01(e) and Section 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 IV

REPRESENTATIONS AND WARRANTIES

Section 4.01    Representations 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 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) APS 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 APS 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, 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)

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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.

(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, 2015, 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 June 30, 2016, 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 furnished to the Agent, fairly present in all material respects, subject, in the case of said balance sheet at June 30, 2016, 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, 2015, 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.

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(g)    No proceeds of any Advance 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 Advance 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 Advance, 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 to Section 4.01(e) or Section 5.01(h)(i) or Section 5.01(h)(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 Material Subsidiaries of the Borrower.

(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

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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, region or territory that is, or whose government is, the subject of Sanctions, including, without limitation, Crimea, 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 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 Credit Extension 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 Credit Extension 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 Credit Extension made by any Lender would be in violation of law; (c) the Borrower will not, directly or indirectly, use the proceeds of the Credit Extension, 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 Credit Extensions, whether as a Lender or otherwise), and (d) neither the Borrower nor any Controlled Affiliate (i) is or will become a “blocked person”

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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 Laws, 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.

ARTICLE V
COVENANTS OF THE BORROWER

Section 5.01    Affirmative Covenants. So long as any Advance shall remain unpaid, any Letter of Credit shall remain outstanding or any Lender shall have any Commitment hereunder, 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 all 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.

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(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 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, in the case of APS, will cause APS to use its commercially reasonable efforts to preserve and maintain such franchises reasonably necessary in the normal conduct of its business, except that (i) APS 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 time communities served by APS 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

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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 50 days after the end of each of the first three fiscal quarters of each fiscal year of the Borrower commencing with the fiscal quarter ending September 30, 2016, (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 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, 2016, 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;

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(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 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 their respective Public Debt Rating;

(vii)    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

(viii)    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 Section 5.01(h)(i), Section 5.01(h)(ii) and Section 5.01(h)(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 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 Section 5.01(h)(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 directly or through its Subsidiaries the same general type of business conducted by the Borrower and its Material Subsidiaries on the date hereof.

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Section 5.02    Negative Covenants. So long as any Advance shall remain unpaid, any Letter of Credit shall remain outstanding or any Lender shall have any Commitment hereunder, the Borrower shall not:

(a)    Liens, Etc. Directly or indirectly create, incur, assume or permit to exist any Lien securing Indebtedness for borrowed money on or with respect to any property or asset (including, without limitation, the capital stock of APS) of the Borrower, whether now owned or held or hereafter acquired (unless it makes, or causes to be made, effective provision whereby the Obligations will be equally and ratably secured with any and all other obligations thereby secured so long as such other Indebtedness shall be so secured, such security to be pursuant to an agreement reasonably satisfactory to the Required Lenders); provided, however, that this Section 5.02(a) shall not apply to Liens securing Indebtedness for borrowed money (other than Indebtedness for borrowed money secured by the capital stock of APS) which do not in the aggregate exceed at any time outstanding the principal amount of $50,000,000.

(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.

(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 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)(i) or Section 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 APS 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 APS’ interests

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in such Units 1, 2 and 3, (vii) any sale of 4C Sub or its assets and (viii) any Lien permitted under Section 5.02(a).

(d)    Ownership of APS. Except to the extent permitted under Section 5.02(b), the Borrower will at all times continue to own directly or indirectly at least 80% of the outstanding capital stock of APS.

Section 5.03    Financial Covenant. So long as any Advance shall remain unpaid, any Letter of Credit shall remain outstanding or any Lender shall have any Commitment hereunder, 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 1.0.

ARTICLE VIEVENTS OF DEFAULT

Section 6.01    Events 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 Advance, (ii) any drawing under any Letter of Credit, or (iii) any interest on any Advance or any other fees or other amounts payable under this Agreement or any other Loan Documents, and (in the case of this clause (iii) 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 2.17, Section 5.01(d) (as to the corporate existence of the Borrower), Section 5.01(h)(iii),Section 5.01(h)(vi), Section 5.02or Section 5.03, or (ii) the Borrower shall fail to perform or observe any other 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,

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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 exceeds any applicable insurance coverage (the insurer of which shall be rated at least “A” by A.M. Best Company) by more than $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 the Borrower entitled to vote for members of the board of directors of the Borrower; or (ii) during any period of 24 consecutive months, a majority of the members of the board of directors of the Borrower 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

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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

(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 obligation of each Lender to make Advances (other than L/C Advances) and of the Issuing Banks to issue Letters of Credit to be terminated, whereupon the same shall forthwith terminate, (ii) declare the Advances, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon the Advances, 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, (A) the obligation of each Lender to make Advances (other than L/C Advances) and of the Issuing Banks to issue Letters of Credit shall automatically be terminated and (B) the Advances, 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 (iii) exercise all rights and remedies available to it under this Agreement, the other Loan Documents and applicable Law.

Section 6.02    Actions in Respect of Letters of Credit upon Default. If any Event of Default shall have occurred and be continuing, the Agent may with the consent, or shall at the request, of the Required Lenders, irrespective of whether it is taking any of the actions described in Section 6.01 or otherwise, (a) make demand upon the Borrower to, and forthwith upon such demand the Borrower will Cash Collateralize the aggregate Available Amount of all Letters of Credit then outstanding (whether or not any beneficiary under any Letter of Credit shall have drawn or be entitled at such time to draw thereunder) or (b) make such other arrangements in respect of the outstanding Letters of Credit as shall be acceptable to the Required Lenders, 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 Borrower will Cash Collateralize the aggregate Available Amount of all Letters of Credit then outstanding, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower. If at any time the Agent determines that any funds held in the L/C Cash Deposit Account are subject to any right or interest of any Person other than the Agent, the Issuing Banks and the Lenders or that the total amount of such funds is less than the aggregate Available Amount of all Letters of Credit, the Borrower will, forthwith upon demand by the Agent, pay to the Agent, as additional funds to be deposited and held in the L/C Cash Deposit Account, an amount equal to the excess of (a) such aggregate Available Amount over (b) the total amount of funds, if any, then held in the L/

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C Cash Deposit Account that are free and clear of any such right and interest. Upon the drawing of any Letter of Credit, to the extent funds are on deposit in the L/C Cash Deposit Account, such funds shall be applied to reimburse the Issuing Banks to the extent permitted by applicable Law, or each Lender to the extent such Lender has funded a Revolving Advance in respect of such Letter of Credit. The Borrower hereby grants to the Agent, for the benefit of the Issuing Banks and the Lenders, a Lien upon and security interest in the L/C Cash Deposit Account and all amounts held therein from time to time as security for the L/C Obligations, and for application to the Borrower’s reimbursement obligations as and when the same shall arise. The Agent shall have exclusive dominion and control, including the exclusive right of withdrawal, over such account. After all such Letters of Credit shall have expired or been fully drawn upon and all other obligations of the Borrower hereunder and under the other Loan Documents shall have been paid in full, the balance, if any, in such L/C Cash Deposit Account shall be promptly returned to the Borrower.

ARTICLE VIITHE AGENT

Section 7.01    Appointment and Authority. Each of the Lenders (for purposes of this Article, references to the Lenders shall also mean the Issuing Banks) hereby irrevocably appoints The Bank of Tokyo-Mitsubishi UFJ, Ltd. 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 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 7.02    Rights 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 7.03    Exculpatory 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

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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 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 7.04    Reliance 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 Advance, or the issuance of a Letter of Credit, that by its terms must be fulfilled to the satisfaction of a Lender or an Issuing Bank, the Agent may presume that such condition is satisfactory to such Lender or such Issuing Bank unless the Agent shall have received notice to the contrary from such Lender or such Issuing Bank prior to the making of such Advance or the issuance of such Letter of Credit. 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 7.05    Delegation 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

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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 7.06    Resignation 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) 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 7.07    Non-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 7.08    No Other Duties, Etc. Anything herein to the contrary notwithstanding, none of the Arrangers, Syndication Agents, Documentation Agents or 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.

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Section 7.09    Issuing Banks. Each Issuing Bank shall act on behalf of the Lenders with respect to any Letters of Credit issued by it and the documents associated therewith, and each Issuing Bank shall have all of the benefits and immunities provided in this Article VII (other than Section 7.02) to the same extent as such provisions apply to the Agent.

ARTICLE VIII
MISCELLANEOUS

Section 8.01    Amendments, 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 Advance or the Borrower’s obligations to reimburse any drawing on a Letter of Credit, 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, the Arrangers, any Issuing Bank or the Swingline Lender, if any, 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 Advance, extend the time of payment of any obligation of the Borrower to reimburse any drawing on any Letter of Credit or any interest thereon, extend the expiry date of any Letter of Credit beyond the Letter of Credit Expiration Date, or extend the time of payment of any fees hereunder (other than fees payable to the Agent, the Arrangers, any Issuing Bank or the Swingline Lender, if any, for their own respective accounts), or (iii) increase any Revolving Credit Commitment of any such Lender over the amount thereof in effect or extend the maturity thereof (it being understood that a waiver of any condition precedent set forth in Section 3.02 or 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);

(b)    unless agreed to by all of the Lenders, (i) reduce the percentage of the aggregate Revolving Credit Commitments or of the aggregate unpaid principal amount of the Advances, 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 such 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 2.15, 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 2.19(b); and

(c)    unless agreed to by the Issuing Banks, the Swingline Lender, if any, or the Agent in addition to the Lenders required as provided hereinabove to take such action, affect the respective

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rights or obligations of the Issuing Banks, the Swingline Lender, if any, or the Agent, as applicable, hereunder or under any of the other Loan Documents.

(d)    Reserved.

(e)    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, each Issuing Bank and the Agent shall agree, as of such date, to purchase for cash the Advances 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 Section 2.11 and Section 2.14, 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 Advances of such Non-Consenting Lender been prepaid on such date rather than sold to the replacement Lender.

Section 8.02    Notices, Etc.

(a)    All notices and other communications provided for hereunder shall be either (x) in writing (including electronic communication) and mailed or delivered or (y) as and to the extent set forth in Section 8.02(b) and (c) and in the proviso to this Section 8.02(a), if to the Borrower, at the address specified on Schedule 8.02; if to any Lender, at its Domestic Lending Office; if to the Agent, at the address specified on Schedule 8.02; if to the Swingline Lender, at the address specified by the Swingline Lender to the Borrower and the Agent, and if to any Issuing Bank, 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, be effective when deposited in the mails, respectively, except that notices and communications to the Agent pursuant to Article II, Article III or Article VIII shall not be effective until received by the Agent. 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, the Agent and the Issuing Banks 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 or the Issuing Banks pursuant

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to Article II if such Lender or the Issuing Banks, as applicable, 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 Section 5.01(h)(i), Section 5.01(h)(ii) and Section 5.01(h)(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 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 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

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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 Borrowing and any notice of Default.

Section 8.03    No Waiver; Cumulative Remedies; Enforcement. No failure by any Lender, any Issuing Bank 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 and the Issuing Banks; 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 Issuing Bank from exercising the rights and remedies that inure to its benefit (solely in its capacity as an Issuing Bank) hereunder and under the other Loan Documents, (c) any Lender from exercising setoff rights in accordance with Section 8.05 (subject to the terms of Section 2.15), or (d) 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; 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), (c) and (d) of the preceding proviso and subject to Section 2.15, 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 8.04    Costs and Expenses; Indemnity; Damage Waiver.

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(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 one law firm acting as 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 of the transactions contemplated herein or the actual or proposed use of the proceeds of any Advance or Letter of Credit (including any refusal by any Issuing Bank to honor a demand for payment under a Letter of Credit if the documents presented in connection with such demand do not strictly comply with the terms of such Letter of Credit), 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 2.14, 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 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.

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(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), any Issuing Bank 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), such Issuing Bank 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) or such Issuing Bank in its capacity as such, or against any Related Party of any of the foregoing acting for the Agent (or any such sub-agent) or such Issuing Bank 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 Advances or the Letters of Credit. 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 Advance 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 Revolving Advance, as a result of a payment or Conversion pursuant to Section 2.08(d) or (e), Section 2.10 or Section 2.12, acceleration of the maturity of the Revolving Advances 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 Revolving Advance 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 2.19, 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 Revolving Advance.

(f)    Without prejudice to the survival of any other agreement of the Borrower hereunder, the agreements and obligations of the Borrower contained in Section 2.02(c), Section 2.11, Section 2.14 and Section 8.04 shall survive the payment in full of principal, interest and all other amounts payable hereunder and under the Notes.

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Section 8.05    Right 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 6.01to authorize the Agent to declare the Advances due and payable pursuant to the provisions of Section 6.01, each Lender, each Issuing Bank and each of their respective 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, such Issuing Bank 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 or Issuing Bank, whether or not such Lender or Issuing Bank 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 or such Issuing Bank different from the branch or office holding such deposit or obligated on such indebtedness. Each Lender and each Issuing Bank 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 and each Issuing Bank 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 8.06    Effectiveness; 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 8.07    Successors 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, the Issuing Banks 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 its Revolving Credit Commitment, Swingline Exposure and the Revolving Advances (including for purposes of this subsection (b), participations in L/C Obligations) at the time owing to it); 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 remaining amount of the assigning Lender’s Revolving Credit Commitment and the Revolving Advances 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 amount of the Revolving Credit Commitment (which for this purpose includes Revolving Advances outstanding thereunder) or, if the Revolving Credit Commitment is not then in effect, the principal outstanding balance of the Revolving Advances 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 Revolving Advances, L/C Obligations, Swingline Exposure or the Revolving Credit Commitment 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 written 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;

(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;

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(C)    the consent of each Issuing Bank (such consent not to be unreasonably withheld or delayed) shall be required for any assignment that increases the obligation of the assignee to participate in exposure under one or more Letters of Credit (whether or not then outstanding); and

(D)    the consent of the Swingline Lender, if any, (such consent not to be unreasonably withheld or delayed) shall be required for any assignment that increases the obligation of the assignee to participate in exposure under Swingline Advances (whether or not then outstanding).

(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.

(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 Section 2.11, Section 2.14 and Section 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 Revolving Credit Commitments of, and principal amounts of the Advances and L/C Obligations 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)

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(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 its Revolving Credit Commitment, Swingline Exposure and/or the Revolving Advances (including such Lender’s participations in L/C Obligations) 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, the Lenders and the Issuing Banks 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.

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 Section 2.11, Section 2.14 and Section 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 2.15 as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary 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 2.11 or Section 2.14 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

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2.14 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 2.14(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)    Resignation as an Issuing Bank after Assignment. Notwithstanding anything to the contrary contained herein, if at any time any Issuing Bank assigns all of its Revolving Credit Commitment and Revolving Advancespursuant to subsection (b) above, such Issuing Bank may, upon 30 days’ notice to the Borrower and the Lenders, resign as an Issuing Bank. If any Issuing Bank resigns, it shall retain all the rights, powers, privileges and duties of an Issuing Bank hereunder with respect to all Letters of Credit outstanding as of the effective date of its resignation as an Issuing Bank and all L/C Obligations with respect thereto (including the right to require the Lenders to make Base Rate Advances or fund risk participations in Unreimbursed Amounts pursuant to Section 2.03(c)).

(h)    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 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 8.08    Confidentiality. 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

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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 8.09    Governing Law. This Agreement and the Notes shall be governed by, and construed in accordance with, the Laws of the State of New York.

Section 8.10    Counterparts; 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 electronic imaging means shall be effective as delivery of an original 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 8.11    Jurisdiction, Etc.

(a)    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 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.

(b)    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 8.12    Payments Set Aside. To the extent that any payment by or on behalf of the Borrower is made to the Agent, any Issuing Bank or any Lender, or the Agent, any Issuing Bank 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

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(including pursuant to any settlement entered into by the Agent, such Issuing Bank 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 and each Issuing Bank 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 and the Issuing Banks under clause (b) of the preceding sentence shall survive the payment in full of the Obligations and the termination of this Agreement.

Section 8.13    Patriot 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 8.14    Waiver 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 OR ANY LENDER IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE OR ENFORCEMENT THEREOF.

Section 8.15    No 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

77

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 8.16    Survival 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 Advance or any other Obligation hereunder shall remain unpaid or unsatisfied or any Letter of Credit shall remain outstanding.

Section 8.17    Severability. 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 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.

Section 8.18    Acknowledgement and Consent to Bail-In of EEA Financial Institutions. Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)    the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an EEA Financial Institution; and

(b)    the effects of any Bail-in Action on any such liability, including, if applicable:

(i)    a reduction in full or in part or cancellation of any such liability;

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(ii)    a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)    the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

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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.

PINNACLE WEST CAPITAL CORPORATION

By    /s/ Lee R. Nickloy            

Name:    Lee R. Nickloy

Title:    Vice President and Treasurer

Signature Page to 364-Day Credit Facility

ADMINISTRATIVE AGENT:	THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as Agent, as an Issuing Bank and as a Lender
	By    /s/ Maria Ferradas
	Name:    Maria Ferradas
	Title:    Director

Signature Page to 364-Day Credit Facility

LENDERS:	JPMORGAN CHASE BANK, N.A., as a Lender
	By    /s/ Nancy R. Barwig
	Name:    Nancy R. Barwig
	Title:    Credit Risk Director

Signature Page to 364-Day Credit Facility

SCHEDULE 1.01

COMMITMENTS AND RATABLE SHARES

Bank	Revolving Credit Commitment	Ratable Share
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$37,500,000	50.0%
JPMorgan Chase Bank, N.A.	$37,500,000	50.0%
TOTAL	$75,000,000.00	100.000000000%

SCHEDULE 4.01(j)

SUBSIDIARIES

Arizona Public Service Company

SCHEDULE 4.01(k)

EXISTING INDEBTEDNESS

None.

SCHEDULE 8.02

CERTAIN ADDRESSES FOR NOTICES

BORROWER:

Pinnacle West Capital Corporation

400 North 5th Street

Mail Station 9040

Phoenix, AZ 85004

Attention: Treasurer

Telephone:    (602) 250-3300

Electronic    lee.nickloy@pinnaclewest.com

AGENT:

Agent’s Office

(for payments and Requests for Credit Extensions):

The Bank of Tokyo-Mitsubishi UFJ, Ltd.

1221 Avenue of the Americas, New York, NY 10020

Attention: Lawrence Blat

Telephone: 1-212-405-6621 / 6628

Email: lblat@us.mufg.jp and to Agencydesk@us.mufg.jp

Agent’s Account/Agency Service Wiring Information

The Bank of Tokyo-Mitsubishi UFJ, Ltd.

Account Number: 9777-0191

Account Name: Loan Operations Department

Ref: Pinnacle West Capital Corporation

Other Notices as Agent:

The Bank of Tokyo-Mitsubishi UFJ, Ltd.

1221 Avenue of the Americas, New York, NY 10020

Attention: Lawrence Blat

Telephone: 1-212-405-6621 / 6628

Email: lblat@us.mufg.jp and to Agencydesk@us.mufg.jp

ISSUING BANKS:

The Bank of Tokyo-Mitsubishi UFJ, Ltd.

1221 Avenue of the Americas, New York, NY 10020

Attention: Lawrence Blat

Telephone: 1-212-405-6621 / 6628

Email: lblat@us.mufg.jp and to Agencydesk@us.mufg.jp

EXHIBIT A — FORM OF

PROMISSORY NOTE

______________, 20__

FOR VALUE RECEIVED, the undersigned, PINNACLE WEST CAPITAL CORPORATION, an Arizona corporation (the “Borrower”), hereby promises to pay to _______ or its registered assigns (the “Lender”), in accordance with the provisions of the Credit Agreement (as hereinafter defined), the principal amount of each Advance from time to time made by the Lender to the Borrower pursuant to the 364-Day Credit Agreement dated as of August 31, 2016 among the Borrower, the Lender and certain other lenders parties thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent for the Lender and such other lenders, and the issuing banks and other agents party thereto (as amended or modified from time to time, the “Credit Agreement”; the terms defined therein being used herein as therein defined) outstanding on such date.

The Borrower promises to pay interest on the unpaid principal amount of each Advance from the date of such Advance until such principal amount is paid in full, at such interest rates, and payable at such times, as are specified in the Credit Agreement.

Both principal and interest are payable in lawful money of the United States of America to the Agent for the account of the Lender in same day funds at the address and account specified on Schedule 8.02. Each Advance owing to the Lender by the Borrower pursuant to the Credit Agreement, and all payments made on account of principal thereof, shall be recorded by the Lender and, prior to any transfer hereof, endorsed on the grid attached hereto which is part of this Promissory Note.

This Promissory Note is one of the Notes referred to in, and is entitled to the benefits of, the Credit Agreement. The Credit Agreement, among other things, (i) provides for the making of Advances by the Lender to the Borrower from time to time in an aggregate amount not to exceed at any time the Lender’s Unused Commitment, the indebtedness of the Borrower resulting from each such Advance being evidenced by this Promissory Note and (ii) contains provisions for acceleration of the maturity hereof upon the happening of certain stated events and also for prepayments on account of principal hereof prior to the maturity hereof upon the terms and conditions therein specified.

THIS PROMISSORY NOTE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

PINNACLE WEST CAPITAL CORPORATION

By    

Name:     

Title:    

ADVANCES AND PAYMENTS OF PRINCIPAL

Date Amount of Advance Amount of Principal Paid or Prepaid Unpaid Principal Balance Notation
Made By

EXHIBIT B — FORM OF NOTICE OF

BORROWING

The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent

for the Lenders parties

to the Credit Agreement

referred to below

Attention: Loan Operations

[Date]

Ladies and Gentlemen:

The undersigned, Pinnacle West Capital Corporation, refers to the 364-Day Credit Agreement, dated as of August 31, 2016 (as amended or modified from time to time, the “Credit Agreement”, the terms defined therein being used herein as therein defined), among the undersigned, certain Lenders parties thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent for said Lenders and the Issuing Banks and other agents party thereto, and hereby gives you notice, irrevocably, pursuant to Section 2.02 of the Credit Agreement that the undersigned hereby requests a Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Borrowing (the “Proposed Borrowing”) as required by Section 2.02(a) of the Credit Agreement:

(i) The Business Day of the Proposed Borrowing is ____________, 20___.

(ii) The Type of Revolving Advances comprising the Proposed Borrowing is [Base Rate Advances] [Eurodollar Rate Advances].

(iii) The aggregate amount of the Proposed Borrowing is $_____________.

[(iv) The initial Interest Period for each Eurodollar Rate Advance made as part of the Proposed Borrowing is ___month[s].]

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing:

(A)    the representations and warranties contained in Section 4.01 (other than Sections 4.01(k), 4.01(e)(ii) and 4.01(f)(ii)) of the Credit Agreement are correct, before and after giving effect to the Proposed Borrowing and to the application of the proceeds therefrom, as though made on and as of such date;

(B)    no event has occurred and is continuing, or would result from such Proposed Borrowing or from the application of the proceeds therefrom, that constitutes a Default; and

(C)    before and after giving effect to the Proposed Borrowing and to the application of

the proceeds therefrom, as though made on and as of such date, the Indebtedness of the Borrower does not exceed that permitted by (i) applicable resolutions of the Board of Directors of the Borrower or (ii) applicable Laws of any Governmental Authority.

Very truly yours,

PINNACLE WEST CAPITAL CORPORATION

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 Credit Agreement identified below (as amended, the “Credit 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 Credit 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 Credit 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 respective facilities identified below (including without limitation any letters of credit, guarantees, and swingline loans included in such facilities) 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 Credit 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”). Each 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 Bank]]

3. Borrower: Pinnacle West Capital Corporation

4. Agent: The Bank of Tokyo-Mitsubishi UFJ, Ltd., as the administrative agent under the Credit Agreement

5. Credit Agreement: The 364-Day Credit Agreement dated as of August 31, 2016, by and among the Borrower, the Lenders party thereto, the Agent and the Issuing Banks and other agents party thereto.

6. Assigned Interest:

Aggregate Amount of Commitment for all Lenders	Amount of Commitment Assigned	Percentage Assigned of Commitment	CUSIP Number
$____________	$____________	___________%

[7. 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] Accepted:

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as Agent

By    

Name:     

Title:    

[Consented to:]

PINNACLE WEST CAPITAL CORPORATION

By    

Name:     

Title:    

ANNEX 1 TO ASSIGNMENT AND ASSUMPTION

STANDARD TERMS AND CONDITIONS FOR

ASSIGNMENT AND ASSUMPTION

1.    Representations and Warranties.

1.1    Assignor. 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 Credit 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.

1.2    Assignee. 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 Credit Agreement, (ii) it meets all the requirements to be an Eligible Assignee under Section 8.07 of the Credit Agreement (subject to such consents, if any, as may be required under Section 8.07 of the Credit Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit 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 Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements referred to in Section 4.01(e) or delivered pursuant to Section 5.01(h), as applicable, thereof, 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, the Assignor 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 (vi) if it is a foreign lender, attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by the Assignee; and (b) 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 electronic imaging means 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.

EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Nine Months Ended September 30,		Twelve Months Ended December 31,
	2016		2015		2014		2013		2012		2011
Earnings:
Income from continuing operations attributable to common shareholders	$	388,788	$	437,257	$	397,595	$	406,074	$	387,380	$	328,110
Income taxes	209,102		237,720		220,705		230,591		237,317		183,604
Fixed charges	161,142		202,465		208,226		206,089		219,437		246,462
Total earnings	$	759,032	$	877,442	$	826,526	$	842,754	$	844,134	$	758,176
Fixed Charges:
Interest expense	$	154,886	$	194,964	$	200,950	$	201,888	$	214,616	$	241,995
Estimated interest portion of annual rents	6,256		7,501		7,276		4,201		4,821		4,467
Total fixed charges	$	161,142	$	202,465	$	208,226	$	206,089	$	219,437	$	246,462
Ratio of Earnings to Fixed Charges (rounded down)	4.71		4.33		3.96		4.08		3.84		3.07

EX-12.2

Exhibit 12.2

ARIZONA PUBLIC SERVICE COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	Nine Months Ended September 30,		Twelve Months Ended December 31,
	2016		2015		2014		2013		2012		2011
Earnings:
Income from continuing operations attributable to common shareholders	$	403,661	$	450,274	$	421,219	$	424,969	$	395,497	$	336,249
Income taxes	215,950		245,841		237,360		245,095		244,396		192,542
Fixed charges	158,861		199,458		204,198		202,457		214,227		238,286
Total earnings	$	778,472	$	895,573	$	862,777	$	872,521	$	854,120	$	767,077
Fixed Charges:
Interest charges	$	149,100	$	187,499	$	193,119	$	194,616	$	205,533	$	229,326
Amortization of debt discount	3,529		4,793		4,168		4,046		4,215		4,616
Estimated interest portion of annual rents	6,232		7,166		6,911		3,795		4,479		4,344
Total fixed charges	$	158,861	$	199,458	$	204,198	$	202,457	$	214,227	$	238,286
Ratio of Earnings to Fixed Charges (rounded down)	4.90		4.49		4.22		4.30		3.98		3.21

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)

	Nine Months Ended September 30,		Twelve Months Ended December 31,
	2016		2015		2014		2013		2012		2011
Earnings:
Income from continuing operations attributable to common shareholders	$	388,788	$	437,257	$	397,595	$	406,074	$	387,380	$	328,110
Income taxes	209,102		237,720		220,705		230,591		237,317		183,604
Fixed charges	161,142		202,465		208,226		206,089		219,437		246,462
Total earnings	$	759,032	$	877,442	$	826,526	$	842,754	$	844,134	$	758,176
Fixed Charges:
Interest expense	$	154,886	$	194,964	$	200,950	$	201,888	$	214,616	$	241,995
Estimated interest portion of annual rents	6,256		7,501		7,276		4,201		4,821		4,467
Total fixed charges	$	161,142	$	202,465	$	208,226	$	206,089	$	219,437	$	246,462
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	597,890	$	674,977	$	618,300	$	636,665	$	624,697	$	511,714
Net income from continuing operations attributable to common shareholders	388,788		437,257		397,595		406,074		387,380		328,110
Ratio of income before income taxes to net income	1.54		1.54		1.56		1.57		1.61		1.56
Preferred stock dividends	—		—		—		—		—		—
Preferred stock dividend requirements — ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	161,142	$	202,465	$	208,226	$	206,089	$	219,437	$	246,462
Preferred stock dividend requirements	—		—		—		—		—		—
Total	$	161,142	$	202,465	$	208,226	$	206,089	$	219,437	$	246,462
Ratio of Earnings to Fixed Charges (rounded down)	4.71		4.33		3.96		4.08		3.84		3.07

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:    November 3, 2016

/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:    November 3, 2016

/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:    November 3, 2016

/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:    November 3, 2016

/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 September 30, 2016 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:      November 3, 2016

/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 September 30, 2016 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:     November 3, 2016

/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 September 30, 2016 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:      November 3, 2016

/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 September 30, 2016 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:      November 3, 2016

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	0000764622
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
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		111,306,107
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
APS
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	0000007286
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
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	2016
Document Fiscal Period Focus	Q3

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
OPERATING REVENUES	$ 1,166,922	$ 1,199,146	$ 2,759,483	$ 2,761,013
OPERATING EXPENSES
Fuel and purchased power	336,120	363,847	832,253	868,561
Operations and maintenance	217,568	220,449	703,042	646,358
Depreciation and amortization	120,428	125,625	362,977	369,313
Taxes other than income taxes	41,284	43,241	125,902	129,489
Other expenses	264	873	2,141	2,524
Total	715,664	754,035	2,026,315	2,016,245
OPERATING INCOME	451,258	445,111	733,168	744,768
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	10,194	7,645	31,079	26,214
Other income (Note 8)	71	139	385	549
Other expense (Note 8)	(5,205)	(5,538)	(12,085)	(12,433)
Total	5,060	2,246	19,379	14,330
INTEREST EXPENSE
Interest charges	51,293	49,342	154,886	146,069
Allowance for borrowed funds used during construction	(4,321)	(3,518)	(14,849)	(12,056)
Total	46,972	45,824	140,037	134,013
INCOME BEFORE INCOME TAXES	409,346	401,533	612,510	625,085
INCOME TAXES	141,446	139,555	209,102	214,873
NET INCOME	267,900	261,978	403,408	410,212
Less: Net income attributable to noncontrolling interests (Note 5)	4,873	4,862	14,620	14,072
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 263,027	$ 257,116	$ 388,788	$ 396,140
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	111,416	111,036	111,363	110,984
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	112,100	111,616	111,987	111,490
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 2.36	$ 2.32	$ 3.49	$ 3.57
Net income attributable to common shareholders - diluted (in dollars per share)	2.35	2.30	3.47	3.55
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 0	$ 0	$ 1.25	$ 1.19
APS
ELECTRIC OPERATING REVENUES	$ 1,166,359	$ 1,198,380	$ 2,752,748	$ 2,758,771
OPERATING EXPENSES
Fuel and purchased power	339,510	363,847	835,643	868,561
Operations and maintenance	209,366	216,011	681,789	633,989
Depreciation and amortization	120,013	125,592	362,492	369,234
Income taxes	148,945	148,543	225,239	232,454
Taxes other than income taxes	40,924	43,149	125,370	129,258
Total	858,758	897,142	2,230,533	2,233,496
OPERATING INCOME	307,601	301,238	522,215	525,275
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	10,194	7,645	31,079	26,214
Income taxes	5,753	5,678	9,289	10,809
Other income (Note 8)	567	650	6,924	1,999
Other expense (Note 8)	(3,776)	(3,965)	(12,956)	(11,768)
Total	12,738	10,008	34,336	27,254
INTEREST EXPENSE
Interest on long-term debt	46,970	44,011	142,692	134,265
Interest on short-term borrowings	2,401	3,460	6,408	6,339
Debt discount, premium and expense	1,195	1,218	3,529	3,455
Allowance for borrowed funds used during construction	(4,320)	(3,492)	(14,359)	(12,019)
Total	46,246	45,197	138,270	132,040
NET INCOME	274,093	266,049	418,281	420,489
Less: Net income attributable to noncontrolling interests (Note 5)	4,873	4,862	14,620	14,072
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 269,220	$ 261,187	$ 403,661	$ 406,417

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
NET INCOME	$ 267,900	$ 261,978	$ 403,408	$ 410,212
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	(29)	(151)	(595)	(926)
Reclassification of net realized loss, net of tax benefit	798	892	2,564	3,742
Pension and other postretirement benefits activity, net of tax benefit (expense)	804	869	633	1,335
Total other comprehensive income	1,573	1,610	2,602	4,151
COMPREHENSIVE INCOME	269,473	263,588	406,010	414,363
Less: Comprehensive income attributable to noncontrolling interests	4,873	4,862	14,620	14,072
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	264,600	258,726	391,390	400,291
APS
NET INCOME	274,093	266,049	418,281	420,489
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense)	(29)	(151)	(595)	(926)
Reclassification of net realized loss, net of tax benefit	798	892	2,564	3,742
Pension and other postretirement benefits activity, net of tax benefit (expense)	799	870	768	1,477
Total other comprehensive income	1,568	1,611	2,737	4,293
COMPREHENSIVE INCOME	275,661	267,660	421,018	424,782
Less: Comprehensive income attributable to noncontrolling interests	4,873	4,862	14,620	14,072
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 270,788	$ 262,798	$ 406,398	$ 410,710

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net unrealized loss, tax benefit (expense)	$ 18	$ 96	$ (608)	$ (392)
Reclassification of net realized loss, tax benefit	500	567	691	1,490
Pension and other postretirement benefits activity, tax expense	504	553	709	1,345
Arizona Public Service Company
Net unrealized loss, tax benefit (expense)	18	96	(608)	(392)
Reclassification of net realized loss, tax benefit	500	567	691	1,490
Pension and other postretirement benefits activity, tax expense	$ 501	$ 553	$ 657	$ 1,275

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 48,267	$ 39,488
Customer and other receivables	325,029	274,691
Accrued unbilled revenues	150,531	96,240
Allowance for doubtful accounts	(3,608)	(3,125)
Materials and supplies (at average cost)	250,789	234,234
Fossil fuel (at average cost)	34,745	45,697
Income tax receivable	0	589
Assets from risk management activities (Note 6)	6,235	15,905
Deferred fuel and purchased power regulatory asset (Note 3)	8,132	0
Other regulatory assets (Note 3)	114,088	149,555
Other current assets	43,284	37,242
Total current assets	977,492	890,516
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 6)	0	12,106
Nuclear decommissioning trust (Note 11)	779,753	735,196
Other assets	68,977	52,518
Total investments and other assets	848,730	799,820
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	16,877,695	16,222,232
Accumulated depreciation and amortization	(5,895,765)	(5,594,094)
Net	10,981,930	10,628,138
Construction work in progress	1,118,666	816,307
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)	114,483	117,385
Intangible assets, net of accumulated amortization	96,789	123,975
Nuclear fuel, net of accumulated amortization	133,731	123,139
Total property, plant and equipment	12,445,599	11,808,944
DEFERRED DEBITS
Regulatory assets (Note 3)	1,212,150	1,214,146
Assets for other postretirement benefits (Note 4)	191,007	185,997
Other	130,748	128,835
Total deferred debits	1,533,905	1,528,978
TOTAL ASSETS	15,805,726	15,028,258
CURRENT LIABILITIES
Accounts payable	248,133	297,480
Accrued taxes	219,432	138,600
Accrued interest	46,124	56,305
Common dividends payable	0	69,363
Short-term borrowings (Note 2)	117,300	0
Current maturities of long-term debt (Note 2)	16,870	357,580
Customer deposits	78,262	73,073
Liabilities from risk management activities (Note 6)	45,175	77,716
Liabilities for asset retirements (Note 14)	11,852	28,573
Deferred fuel and purchased power regulatory liability (Note 3)	0	9,688
Other regulatory liabilities (Note 3)	104,313	136,078
Other current liabilities	222,257	197,861
Total current liabilities	1,109,718	1,442,317
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)	4,145,366	3,462,391
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,941,559	2,723,425
Regulatory liabilities (Note 3)	998,349	994,152
Liabilities for asset retirements (Note 14)	458,628	415,003
Liabilities for pension benefits (Note 4)	401,680	480,998
Liabilities from risk management activities (Note 6)	58,343	89,973
Customer advances	98,779	115,609
Coal mine reclamation	220,269	201,984
Deferred investment tax credit	180,738	187,080
Unrecognized tax benefits	9,904	9,524
Other	190,258	186,345
Total deferred credits and other	5,558,507	5,404,093
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,220,370 and 111,095,402 issued at respective dates	2,552,979	2,541,668
Treasury stock at cost; 1,900 and 115,030 shares at respective dates	(130)	(5,806)
Total common stock	2,552,849	2,535,862
Retained earnings	2,342,643	2,092,803
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(36,960)	(37,593)
Derivative instruments	(5,186)	(7,155)
Total accumulated other comprehensive loss	(42,146)	(44,748)
Total shareholders’ equity	4,853,346	4,583,917
Noncontrolling interests (Note 5)	138,789	135,540
Total equity	4,992,135	4,719,457
TOTAL LIABILITIES AND EQUITY	15,805,726	15,028,258
Arizona Public Service Company
CURRENT ASSETS
Cash and cash equivalents	8,027	22,056
Customer and other receivables	323,036	274,428
Accrued unbilled revenues	150,531	96,240
Allowance for doubtful accounts	(3,608)	(3,125)
Materials and supplies (at average cost)	249,554	234,234
Fossil fuel (at average cost)	34,745	45,697
Assets from risk management activities (Note 6)	6,235	15,905
Deferred fuel and purchased power regulatory asset (Note 3)	8,132	0
Other regulatory assets (Note 3)	114,088	149,555
Other current assets	39,981	35,765
Total current assets	930,721	870,755
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 6)	0	12,106
Nuclear decommissioning trust (Note 11)	779,753	735,196
Other assets	48,471	34,455
Total investments and other assets	828,224	781,757
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	16,764,278	16,218,724
Accumulated depreciation and amortization	(5,808,259)	(5,590,937)
Net	10,956,019	10,627,787
Construction work in progress	1,092,895	812,845
Palo Verde sale leaseback, net of accumulated depreciation (Note 5)	114,483	117,385
Intangible assets, net of accumulated amortization	96,634	123,820
Nuclear fuel, net of accumulated amortization	133,731	123,139
Total property, plant and equipment	12,393,762	11,804,976
DEFERRED DEBITS
Regulatory assets (Note 3)	1,212,150	1,214,146
Assets for other postretirement benefits (Note 4)	187,616	182,625
Other	125,863	127,923
Total deferred debits	1,525,629	1,524,694
TOTAL ASSETS	15,678,336	14,982,182
CURRENT LIABILITIES
Accounts payable	241,495	291,574
Accrued taxes	252,443	144,488
Accrued interest	45,762	56,003
Common dividends payable	0	69,400
Short-term borrowings (Note 2)	83,300	0
Current maturities of long-term debt (Note 2)	16,870	357,580
Customer deposits	78,262	73,073
Liabilities from risk management activities (Note 6)	45,175	77,716
Liabilities for asset retirements (Note 14)	11,505	28,573
Deferred fuel and purchased power regulatory liability (Note 3)	0	9,688
Other regulatory liabilities (Note 3)	104,313	136,078
Other current liabilities	186,402	180,535
Total current liabilities	1,065,527	1,424,708
DEFERRED CREDITS AND OTHER
Deferred income taxes	2,957,021	2,764,489
Regulatory liabilities (Note 3)	998,349	994,152
Liabilities for asset retirements (Note 14)	450,508	415,003
Liabilities for pension benefits (Note 4)	380,640	459,065
Liabilities from risk management activities (Note 6)	58,343	89,973
Customer advances	98,779	115,609
Coal mine reclamation	205,126	201,984
Deferred investment tax credit	180,738	187,080
Unrecognized tax benefits	37,266	35,251
Other	140,233	142,683
Total deferred credits and other	5,507,003	5,405,289
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7)
EQUITY
Total common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	2,413,153	2,148,493
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(19,174)	(19,942)
Derivative instruments	(5,186)	(7,155)
Total shareholders’ equity	4,946,651	4,679,254
Noncontrolling interests (Note 5)	138,789	135,540
Total equity	5,085,440	4,814,794
Long-term debt less current maturities (Note 2)	4,020,366	3,337,391
Total capitalization	9,105,806	8,152,185
TOTAL LIABILITIES AND EQUITY	$ 15,678,336	$ 14,982,182

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
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	111,220,370	111,095,402
Treasury stock at cost, shares	1,900	115,030

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 403,408	$ 410,212
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	422,851	428,121
Deferred fuel and purchased power	(46,185)	(137)
Deferred fuel and purchased power amortization	28,366	19,284
Allowance for equity funds used during construction	(31,079)	(26,214)
Deferred income taxes	194,915	168,071
Deferred investment tax credit	(6,342)	9,542
Change in derivative instruments fair value	(278)	(261)
Changes in current assets and liabilities:
Customer and other receivables	(77,908)	(107,263)
Accrued unbilled revenues	(54,291)	(61,736)
Materials, supplies and fossil fuel	(4,438)	(22,537)
Income tax receivable	589	3,098
Other current assets	(11,665)	1,994
Accounts payable	(57,237)	(53,247)
Accrued taxes	80,925	110,066
Other current liabilities	(12,383)	16,952
Change in margin and collateral accounts — assets	517	(1,291)
Change in margin and collateral accounts — liabilities	18,085	30,678
Change in unrecognized tax benefits	1,628	(9,276)
Change in other long-term assets	(59,589)	17,753
Change in other long-term liabilities	(24,839)	(112,436)
Net cash flow provided by operating activities	765,050	821,373
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,014,910)	(778,700)
Contributions in aid of construction	39,355	33,982
Allowance for borrowed funds used during construction	(14,848)	(12,056)
Proceeds from nuclear decommissioning trust sales	447,419	330,304
Investment in nuclear decommissioning trust	(449,129)	(343,488)
Other	(18,353)	(2,830)
Net cash flow used for investing activities	(1,010,466)	(772,788)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151	600,000
Repayment of long-term debt	(353,560)	(344,847)
Short-term borrowing and payments — net	117,300	(90,400)
Dividends paid on common stock	(203,115)	(192,466)
Common stock equity issuance - net of purchases	11,790	12,543
Distributions to noncontrolling interests	(11,372)	(28,012)
Other	1	0
Net cash flow provided by (used for) financing activities	254,195	(43,182)
NET INCREASE IN CASH AND CASH EQUIVALENTS	8,779	5,403
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	39,488	7,604
CASH AND CASH EQUIVALENTS AT END OF PERIOD	48,267	13,007
Cash paid during the period for:
Income taxes, net of refunds	2,562	2,692
Interest, net of amounts capitalized	146,691	143,116
Significant non-cash investing and financing activities:
Accrued capital expenditures	91,315	36,718
Arizona Public Service Company
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	418,281	420,489
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	422,365	428,042
Deferred fuel and purchased power	(46,185)	(137)
Deferred fuel and purchased power amortization	28,366	19,284
Allowance for equity funds used during construction	(31,079)	(26,214)
Deferred income taxes	171,000	72,737
Deferred investment tax credit	(6,342)	9,542
Change in derivative instruments fair value	(278)	(261)
Changes in current assets and liabilities:
Customer and other receivables	(75,961)	(106,236)
Accrued unbilled revenues	(54,291)	(61,736)
Materials, supplies and fossil fuel	(4,368)	(22,537)
Other current assets	(9,857)	2,676
Accounts payable	(56,349)	(52,919)
Accrued taxes	107,955	215,524
Other current liabilities	(30,973)	7,759
Change in margin and collateral accounts — assets	517	(1,291)
Change in margin and collateral accounts — liabilities	18,085	30,678
Change in unrecognized tax benefits	1,628	(9,276)
Change in other long-term assets	(54,051)	16,955
Change in other long-term liabilities	(32,146)	(111,121)
Net cash flow provided by operating activities	766,317	831,958
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(992,735)	(778,207)
Contributions in aid of construction	39,355	33,982
Allowance for borrowed funds used during construction	(14,359)	(12,019)
Proceeds from nuclear decommissioning trust sales	447,419	330,304
Investment in nuclear decommissioning trust	(449,129)	(343,488)
Other	(14,016)	(840)
Net cash flow used for investing activities	(983,465)	(770,268)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	693,151	600,000
Repayment of long-term debt	(353,560)	(344,847)
Short-term borrowing and payments — net	83,300	(90,400)
Dividends paid on common stock	(208,400)	(197,600)
Distributions to noncontrolling interests	(11,372)	(28,012)
Net cash flow provided by (used for) financing activities	203,119	(60,859)
NET INCREASE IN CASH AND CASH EQUIVALENTS	(14,029)	831
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	22,056	4,515
CASH AND CASH EQUIVALENTS AT END OF PERIOD	8,027	5,346
Cash paid during the period for:
Income taxes, net of refunds	10,533	5,504
Interest, net of amounts capitalized	144,984	141,216
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 90,069	$ 36,718

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN 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, 2014			110,649,762	78,400					71,264,947
Balance at end of period 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		410,212			396,140		14,072	420,489			406,417		14,072
Other comprehensive income		4,151				4,151		4,293				4,293
Dividends on common stock		(131,818)			(131,818)			(131,800)			(131,800)
Other								1			1
Issuance of common stock (in shares)			250,868
Issuance of common stock		16,049	$ 16,049
Purchase of treasury stock (in shares)	[1]			(93,280)
Purchase of treasury stock	[1]	(6,096)		$ (6,096)
Reissuance of treasury stock for stock-based compensation and other (in shares)				118,121
Reissuance of treasury stock for stock-based compensation and other		7,732		$ 7,732
Capital activities by noncontrolling interests		(28,013)					(28,013)	(28,013)					(28,013)
Ending balance (in shares) at Sep. 30, 2015			110,900,630	53,559					71,264,947
Balance at beginning of period at Sep. 30, 2015		4,791,319	$ 2,529,019	$ (1,765)	2,190,387	(63,990)	137,668	4,894,822	$ 178,162	2,379,696	2,243,336	(44,040)	137,668
Increase (Decrease) in Shareholders' Equity
Net income		261,978						266,049
Other comprehensive income		1,610						1,611
Ending balance (in shares) at Sep. 30, 2015			110,900,630	53,559					71,264,947
Balance at beginning of period at Sep. 30, 2015		$ 4,791,319	$ 2,529,019	$ (1,765)	2,190,387	(63,990)	137,668	4,894,822	$ 178,162	2,379,696	2,243,336	(44,040)	137,668
Beginning balance (in shares) at Dec. 31, 2015		111,095,402	111,095,402	115,030					71,264,947
Balance at end of period at Dec. 31, 2015		$ 4,719,457	$ 2,541,668	$ (5,806)	2,092,803	(44,748)	135,540	4,814,794	$ 178,162	2,379,696	2,148,493	(27,097)	135,540
Increase (Decrease) in Shareholders' Equity
Net income		403,408			388,788		14,620	418,281			403,661		14,620
Other comprehensive income		2,602				2,602		2,737				2,737
Dividends on common stock		(138,947)			(138,947)			(139,001)			(139,001)
Issuance of common stock (in shares)			124,968
Issuance of common stock		11,311	$ 11,311
Purchase of treasury stock (in shares)	[1]			(71,962)
Purchase of treasury stock	[1]	(4,880)		$ (4,880)
Reissuance of treasury stock for stock-based compensation and other (in shares)				185,092
Reissuance of treasury stock for stock-based compensation and other		10,555		$ 10,556	(1)
Capital activities by noncontrolling interests		$ (11,371)					(11,371)	(11,371)					(11,371)
Ending balance (in shares) at Sep. 30, 2016		111,220,370	111,220,370	1,900					71,264,947
Balance at beginning of period at Sep. 30, 2016		$ 4,992,135	$ 2,552,979	$ (130)	2,342,643	(42,146)	138,789	5,085,440	$ 178,162	2,379,696	2,413,153	(24,360)	138,789
Increase (Decrease) in Shareholders' Equity
Net income		267,900						274,093
Other comprehensive income		$ 1,573						1,568
Ending balance (in shares) at Sep. 30, 2016		111,220,370	111,220,370	1,900					71,264,947
Balance at beginning of period at Sep. 30, 2016		$ 4,992,135	$ 2,552,979	$ (130)	$ 2,342,643	$ (42,146)	$ 138,789	$ 5,085,440	$ 178,162	$ 2,379,696	$ 2,413,153	$ (24,360)	$ 138,789

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

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Consolidation and Nature of Operations

9 Months Ended

Sep. 30, 2016

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, 4C Acquisition, LLC ("4CA"), 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 5 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.

Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.

Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2015 Form 10-K.

Supplemental Cash Flow Information

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

	Nine Months Ended   September 30,
	2016		2015
Cash paid during the period for:
Income taxes, net of refunds	$	2,562	$	2,692
Interest, net of amounts capitalized	146,691		143,116
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	91,315	$	36,718

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Long-Term Debt and Liquidity Matters

9 Months Ended

Sep. 30, 2016

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, to refinance indebtedness, and for other general corporate purposes.

Pinnacle West

On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $200 million facility that matures in May 2021. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At September 30, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

On August 31, 2016, PNW entered into a $75 million364-day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At September 30, 2016, Pinnacle West had $34 million outstanding under the facility.

APS

During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.

On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. Interest rates are based on APS's senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.

On May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.

On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021.

On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E.

On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A.

On August 1, 2016, APS repaid at maturity APS’s $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016.

On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016.

On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B.

At September 30, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At September 30, 2016, APS had $83 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.

See "Financial Assurances" in Note 7 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 presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

	As of September 30, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125,000	$	125,000	$	125,000	$	125,000
APS	4,037,236		4,609,003		3,694,971		3,981,367
Total	$	4,162,236	$	4,734,003	$	3,819,971	$	4,106,367

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At September 30, 2016, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.2 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.7 billion, assuming APS’s total capitalization remains the same.

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Regulatory Matters

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Regulatory Matters

Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%).

The principal provisions of the application are:

• a test year ended December 31, 2015, adjusted as described below;

• an original cost rate base of $6.8 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2015;

• the following proposed capital structure and costs of capital:

	Capital Structure		Cost of Capital
Long-term debt	44.2	%	5.13	%
Common stock equity	55.8	%	10.50	%
Weighted-average cost of capital			8.13	%

• a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

• a base rate for fuel and purchased power costs of $0.029882 per kilowatt-hour (“kWh”) based on estimated 2017 prices (a decrease from the current base fuel rate of $0.03207 per kWh);

• authorization to defer for potential future recovery its share of the construction costs associated with installing selective catalytic reduction equipment at the Four Corners Power Plant (estimated at approximately $400 million in direct costs). APS proposes that the rates established in this rate case be increased through a step mechanism beginning in 2019 to reflect these deferred costs;

• authorization to defer for potential future recovery in the Company’s next general rate case the construction costs APS incurs for its Ocotillo power plant modernization project, once the project reaches commercial operation. APS estimates the direct construction costs at approximately $500 million and that the new facility will be fully in service by early 2019;

• authorization to defer until the Company’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

• updates and modifications to four of APS’s adjustor mechanisms - the Power Supply Adjustor (“PSA”), the Lost Fixed Cost Recovery Mechanism (“LFCR”), the Transmission Cost Adjustor (“TCA”) and the Environmental Improvement Surcharge (“EIS”);

• a number of proposed rate design changes for residential customers, including:

◦ change the on-peak time of use period from 12 p.m. - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;

◦ reduce the difference in the on- and off-peak energy price and lower all energy charges;

◦ offer four rate plan options, three of which have demand charges and a fourth that is available to non-partial requirements customers using less than 600 kWh on average per month; and

◦ modify the current net metering tariff to provide for a credit at the retail rate for the portion of generation by rooftop solar customers that offsets their own load, and for a credit for excess energy delivered to the grid at an export rate.

• proposed rate design changes for commercial customers, including an aggregation rider that allows certain large customers to qualify for a reduced rate, an extra-high load factor rate schedule for certain customers, and an economic development rate offering for new loads meeting certain criteria.

The Company requested that the increase become effective July 1, 2017.  On July 22, 2016, the administrative law judge set a procedural schedule for the rate proceedings. The ACC staff and interveners will begin filing their direct testimony on December 21, 2016, and the hearing will commence on March 22, 2017. The Commission staff supports completing the case within 12 months. APS cannot predict the outcome of its request.

Prior Rate Case Filing

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 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 an LFCR rate mechanism to support energy efficiency and distributed renewable generation;

• Modifications to the 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");

• 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.

In December of 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected 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 second stage of the program, which includes an additional 2 MW of rooftop solar and energy storage, will place two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and is planned to be in operation by the end of 2016.  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, 2015, APS filed its 2016 RES Implementation Plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules.

In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the United States Environmental Protection Agency ("EPA").  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  APS cannot predict the outcome of this proceeding.

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. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from 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. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

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. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology.

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 rulemaking has not been initiated and there has been no additional action on the draft to date. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others.

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 2016 and 2015 (dollars in thousands):

	Nine Months Ended   September 30,
	2016			2015
Beginning balance	$	(9,688	)	$	6,925
Deferred fuel and purchased power costs — current period	46,185			137
Amounts charged to customers	(28,365		)	(19,284		)
Ending balance	$	8,132		$	(12,222	)

The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh.  On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017.

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 Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

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.

Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million 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, 2016.

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.

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. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two months delay in implementation did not have an adverse effect on APS.

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 electric 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 electric grid.  The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. 

On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, an Administrative Law Judge (the "ALJ") issued a recommendation in the docket concerning the value and cost of distributed generation. The ALJ recommended a change to how customers are compensated for energy that they export from rooftop solar systems. Instead of retail rate net metering, the ALJ recommended that the amount of compensation be established by using both an avoided cost calculation and a grid-scale solar resource proxy calculation that would be updated in subsequent utility rate cases. The ALJ recommended that the change to how APS pays for exported rooftop solar energy apply only to those customers who apply to interconnect their distributed generation systems after a decision in APS’s currently pending rate case. The ALJ found rooftop solar customers to be partial requirements customers, but recommended that whether rooftop solar customers should be placed into a separate customer class for purposes of ratemaking be decided in individual utility rate cases. Exceptions to the ALJ recommendation are due November 15, 2016. On December 13, 2016, the ACC will discuss at an open meeting the ALJ recommendation concerning the value and cost of distributed generation.  APS cannot predict the outcome of this proceeding.

In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company ("TEP") both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015 and February 23, 2016, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS actively participated in the related hearings held in March 2016. On August 18, 2016, the ACC issued a decision which ordered that net metering be considered in a separate, phase 2 of the UNS Electric, Inc. rate case to occur after the ACC decides issues raised in the separate, generic docket concerning the value and cost of distributed generation discussed above. APS has also intervened in the upcoming TEP rate case. On June 24, 2016, APS filed testimony in the TEP rate case in support of the TEP proposed rate design changes. In August 2016, the ACC also bifurcated the TEP rate case into two phases, the first of which will address revenue requirements and other traditional rate case issues while the second will address net metering issues. The outcomes of these proceedings will not directly impact our financial position.

Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB")

In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case.  The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision.  On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.

System Benefits Charge

The 2012 Settlement Agreement  provides that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016.  Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge.  The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through year-to-date 2016. The subpoenas request information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from company personnel having knowledge of the material, including the Chief Executive Officer, on October 6, 2016.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas, or alternatively stay APS’ obligations to comply with the subpoenas and decline to decide APS’ motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. APS and Pinnacle West cannot predict the outcome of this matter.

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 $65 million as of September 30, 2016 and is being amortized in rates over a total of 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 is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter 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. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. 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. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and is seeking recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($117 million as of September 30, 2016), 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 thousands):

	Amortization Through	September 30, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	608,312	$	—	$	619,223
Retired power plant costs	2033	9,913		120,072		9,913		127,518
Income taxes — allowance for funds used during construction ("AFUDC") equity	2046	5,419		151,451		5,495		133,712
Deferred fuel and purchased power — mark-to-market (Note 6)	2019	30,748		53,350		71,852		69,697
Deferred fuel and purchased power (c) (e)	2017	8,132		—		—		—
Four Corners cost deferral	2024	6,689		58,566		6,689		63,582
Income taxes — investment tax credit basis adjustment	2045	1,852		46,699		1,766		48,462
Lost fixed cost recovery (b)	2017	55,297		—		45,507		—
Palo Verde VIEs (Note 5)	2046	—		18,620		—		18,143
Deferred compensation	2036	—		36,071		—		34,751
Deferred property taxes	(c)	—		67,547		—		50,453
Loss on reacquired debt	2034	1,592		16,521		1,515		16,375
Tax expense of Medicare subsidy	2024	1,512		10,774		1,520		12,163
Transmission vegetation management	2016	—		—		4,543		—
Mead-Phoenix transmission line CIAC	2050	332		10,791		332		11,040
Transmission cost adjustor (b)	2018	—		4,687		—		2,942
Coal reclamation	2026	418		5,286		418		6,085
Other	Various	316		3,403		5		—
Total regulatory assets (d)		$	122,220	$	1,212,150	$	149,555	$	1,214,146

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

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

(e) Subject to a carrying charge.

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

	Amortization Through	September 30, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Asset retirement obligations	2057	$	—	$	305,862	$	—	$	277,554
Removal costs	(a)	27,626		237,885		39,746		240,367
Other postretirement benefits	(d)	33,294		146,988		34,100		179,521
Income taxes — deferred investment tax credit	2045	3,774		93,578		3,604		97,175
Income taxes — change in rates	2046	1,771		70,233		1,113		72,454
Spent nuclear fuel	2047	—		71,884		3,051		67,437
Renewable energy standard (b)	2017	28,921		1,091		43,773		4,365
Demand side management (b)	2017	4,261		21,863		6,079		19,115
Sundance maintenance	2030	—		14,885		—		13,678
Deferred fuel and purchased power (b) (c)	2017	—		—		9,688		—
Deferred gains on utility property	2019	2,063		9,335		2,062		6,001
Transmission cost adjustor (b)	2017	2,077		—		—		—
Four Corners coal reclamation	2031	—		17,213		—		8,920
Other	Various	526		7,532		2,550		7,565
Total regulatory liabilities		$	104,313	$	998,349	$	145,766	$	994,152

(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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Retirement Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Retirement Plans and Other Postretirement Benefits

Retirement Plans and Other Postretirement 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 the plan changes, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $140 million of the other postretirement benefit trust assets into a new trust 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 completed amortizing these costs as of June 30, 2015. We amortized approximately $2 million and $4 million for the three and nine months ended September 30, 2015, 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 thousands):

	Pension Benefits												Other Benefits
	Three Months Ended   September 30,						Nine Months Ended   September 30,						Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
Service cost — benefits earned during the period	$	13,448		$	14,907		$	40,344		$	44,721		$	3,748		$	4,207		$	11,245		$	12,620
Interest cost on benefit obligation	32,912			30,996			98,735			92,987			7,430			7,026			22,291			21,077
Expected return on plan assets	(43,477		)	(44,808		)	(130,429		)	(134,424		)	(9,123		)	(9,214		)	(27,371		)	(27,641		)
Amortization of:
Prior service cost	132			148			395			446			(9,471		)	(9,492		)	(28,413		)	(28,476		)
Net actuarial loss	10,179			7,764			30,538			23,292			1,147			1,220			3,442			3,661
Net periodic benefit cost	$	13,194		$	9,007		$	39,583		$	27,022		$	(6,269	)	$	(6,253	)	$	(18,806	)	$	(18,759	)
Portion of cost charged to expense	$	6,476		$	4,433		$	19,427		$	15,653		$	(3,077	)	$	(3,078	)	$	(9,230	)	$	(7,348	)

Contributions

We have made voluntary contributions of $100 million to our pension plan year-to-date in 2016. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period. 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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Palo Verde Sale Leaseback Variable Interest Entities

9 Months Ended

Sep. 30, 2016

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. APS will retain 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 $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 period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms 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.  Predominantly due to the lease terms, 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, resulting in an increase in net income for the three and nine months ended September 30, 2016 of $5 million and $15 million, respectively, and for the three and nine months ended September 30, 2015 of $5 million and $14 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at September 30, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):

	September 30, 2016		December 31, 2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	114,483	$	117,385
Equity — Noncontrolling interests	138,789		135,540

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.

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 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 were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $289 million beginning in 2016, and up to $456 million over the lease terms.

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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Derivative Accounting

9 Months Ended

Sep. 30, 2016

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.

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 10 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 September 30, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	1,630	GWh
Gas	193	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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Financial Statement Location	Three Months Ended   September 30,						Nine Months Ended   September 30,
Commodity Contracts		2016			2015			2016			2015
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	(47	)	$	(247	)	$	13		$	(534	)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(1,298		)	(1,459		)	(3,255		)	(5,232		)

(a) During the three and nine months ended September 30, 2016 and 2015, we had no losses 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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Financial Statement Location	Three Months Ended   September 30,						Nine Months Ended September 30,
Commodity Contracts		2016			2015			2016			2015
Net gain recognized in income	Operating revenues	$	41		$	560		$	524		$	445
Net loss recognized in income	Fuel and purchased power (a)	(35,103		)	(50,909		)	(5,145		)	(85,099		)
Total		$	(35,062	)	$	(50,349	)	$	(4,621	)	$	(84,654	)

(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 September 30, 2016 and December 31, 2015, include gross liabilities of $2 million and $3 million, respectively, of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of September 30, 2016 and December 31, 2015.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance Sheet
Current assets	$	24,894		$	(18,816	)	$	6,078		$	157		$	6,235
Investments and other assets	4,146			(4,146		)	—			—			—
Total assets	29,040			(22,962		)	6,078			157			6,235
Current liabilities	(59,586		)	18,816			(40,770		)	(4,405		)	(45,175		)
Deferred credits and other	(62,489		)	4,146			(58,343		)	—			(58,343		)
Total liabilities	(122,075		)	22,962			(99,113		)	(4,405		)	(103,518		)
Total	$	(93,035	)	$	—		$	(93,035	)	$	(4,248	)	$	(97,283	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $4,405, and cash margin provided to counterparties of $157.

As of December 31, 2015: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	37,396		$	(22,163	)	$	15,233		$	672		$	15,905
Investments and other assets	15,960			(3,854		)	12,106			—			12,106
Total assets	53,356			(26,017		)	27,339			672			28,011
Current liabilities	(113,560		)	40,223			(73,337		)	(4,379		)	(77,716		)
Deferred credits and other	(93,827		)	3,854			(89,973		)	—			(89,973		)
Total liabilities	(207,387		)	44,077			(163,310		)	(4,379		)	(167,689		)
Total	$	(154,031	)	$	18,060		$	(135,971	)	$	(3,707	)	$	(139,678	)

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

(b) Includes cash collateral provided to counterparties of $18,060.

(c) Represents cash collateral and cash 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 $4,379, and cash margin provided to counterparties of $672.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of September 30, 2016 we have no counterparties with positive exposures of greater than 10% of risk management assets. 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 September 30, 2016 (dollars in thousands):

	September 30, 2016
Aggregate fair value of derivative instruments in a net liability position	$	122,075
Cash collateral posted	—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	61,177

(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 $149 million if our debt credit ratings were to fall below investment grade.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

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 second 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 sought 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's 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 the amount of reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016.

APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2016, in the amount $11.3 million (APS’s share is $3.3 million) and payment is expected in the second quarter of 2017.

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 $13 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 $18.9 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 $111.1 million, with a maximum annual retrospective premium assessment of approximately $16.6 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 $2.8 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 $23.8 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 $64 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

There have been no material changes, as of September 30, 2016, outside the normal course of business in contractual obligations from the information provided in our 2015 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations.

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 ("RI/FS").  The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by June 2017. 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.  APS responded to ADEQ on May 4, 2015. 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.  On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016.

Environmental Matters

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

Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners and the Navajo Generating Station ("Navajo Plant"). EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. EPA is currently in the process of considering a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility.

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 Electric Company ("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. 4CA, a wholly-owned subsidiary of Pinnacle West, purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC provided notice of its intent to exercise the option. 4CA is negotiating a definitive purchase agreement with NTEC for the purchase by NTEC of the 7% interest. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

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 original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $100 million(excluding costs related to Cholla Unit 2, which was closed on October 1, 2015), 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 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/or 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 rulemaking 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 October 16, 2015, ADEQ issued the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program.  The proposed rule was published in the Federal Register on July 19, 2016 and the public commenting period for this proposal ended on September 2, 2016. APS and various other parties submitted comments in support of EPA's proposal, while Sierra Club submitted comments in opposition. Once EPA’s action is finalized, there may be judicial petitions for review of EPA’s final action filed in the Ninth Circuit Court of Appeals.  APS cannot predict at this time whether such petitions will be filed or if they will be successful.

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 $8 million for Cholla(excluding costs related to Cholla Unit 2, which was closed on October 1, 2015). 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. Litigation concerning the rules, including supplemental analyses EPA has prepared in support of the MATS regulation, is ongoing. These proceedings do not materially impact APS.  Regardless of the results from further judicial or administrative proceedings concerning the MATS rulemaking, 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. APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is approximately in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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. Additionally, the CCR rule requires on-going groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions. Because the initial monitoring at these plants is not yet complete, at the present time expenditures related to potential corrective actions cannot be reasonably estimated.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for existing, new, modified, and reconstructed electric generating units ("EGUs"). EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO₂ performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal.

With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO₂ emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below.

Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ reports that it is continuing to assess its options while completing outreach and soliciting feedback from stakeholders. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation.

The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such a delay.

With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances.

As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation.

Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material.

Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes.

In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, and additional information or considerations may arise that change our expectations.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and 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.

Federal Agency Environmental Lawsuit Related to Four Corners

On December 21, 2015, several environmental groups filed a notice of intent to sue with Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies under the Endangered Species Act (“ESA”) alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the United States Department of the Interior's ("DOI's") review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners.  This review process also required separate environmental impact evaluations under the National Environmental Policy Act (“NEPA”) and culminated in the issuance of a Record of Decision justifying the agency action extending the life of the plant and the adjacent mine. 

On April 20, 2016, the same environmental groups followed through with their notice of intent to sue by filing a lawsuit against OSM and other DOI federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  Expandingupon the December 2015 ESA notice, the lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. The court's consideration of this motion could affect the schedule for this litigation. We cannot predict the outcome of this matter or its potential effect on Four Corners.

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") 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 in the amount of $0.8 million and immediately filed a refund claim with respect to that partial payment in August 2013.  The NMTRD 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 NMTRD filed an appeal of the decision on August 31, 2015.

On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above is approximately $0.8 million.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of September 30, 2016, standby letters of credit totaled $52 million and will expire in 2016 and 2017. As of September 30, 2016, surety bonds expiring through 2019 totaled $150 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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 September 30, 2016. Effective July 6, 2016, Pinnacle West has issued two parental guarantees for 4CArelating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.

Peabody Bankruptcy

On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri.  Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona.  APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement.  

On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleges that the Buyers have breached the Agreement. Peabody requests substantial, but unspecified, monetary damages from the Buyers.  Peabody and the Buyers have agreed to pursue non-binding mediation, failing which a trial is expected to begin in February 2017.  There is insufficient information at this time to reasonably estimate any possible loss or range of loss to the Company.

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Other Income and Other Expense

9 Months Ended

Sep. 30, 2016

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 Pinnacle West's Consolidated other income and other expense for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Other income:
Interest income	$	65		$	127		$	370		$	422
Investment gains — net	—			—			13			—
Miscellaneous	6			12			2			127
Total other income	$	71		$	139		$	385		$	549
Other expense:
Non-operating costs	$	(2,502	)	$	(2,328	)	$	(6,636	)	$	(6,529	)
Investment losses — net	(450		)	(563		)	(1,508		)	(1,708		)
Miscellaneous	(2,253		)	(2,647		)	(3,941		)	(4,196		)
Total other expense	$	(5,205	)	$	(5,538	)	$	(12,085	)	$	(12,433	)

Arizona Public Service Company

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

Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Other income:
Interest income	$	—		$	32		$	181		$	105
Gain on disposition of property	183			(58		)	5,504			627
Miscellaneous	384			676			1,239			1,267
Total other income	$	567		$	650		$	6,924		$	1,999
Other expense:
Non-operating costs (a)	$	(2,714	)	$	(2,248	)	$	(7,398	)	$	(6,643	)
Loss on disposition of property	36			(327		)	(1,048		)	(934		)
Miscellaneous	(1,098		)	(1,390		)	(4,510		)	(4,191		)
Total other expense	$	(3,776	)	$	(3,965	)	$	(12,956	)	$	(11,768	)

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

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Earnings Per Share

9 Months Ended

Sep. 30, 2016

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 nine months ended September 30, 2016 and 2015 (in thousands, except per share amounts):

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2016		2015		2016		2015
Net income attributable to common shareholders	$	263,027	$	257,116	$	388,788	$	396,140
Weighted average common shares outstanding — basic	111,416		111,036		111,363		110,984
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	684		580		624		506
Weighted average common shares outstanding — diluted	112,100		111,616		111,987		111,490
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	2.36	$	2.32	$	3.49	$	3.57
Net income attributable to common shareholders — diluted	$	2.35	$	2.30	$	3.47	$	3.55

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

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, exchange traded mutual funds, 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.  

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.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires instruments valued using NAV, as a practical expedient, to no longer be classified within the fair value hierarchy. As such, instruments valued using NAV, as a practical expedient, are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments.  See Note 7 in the 2015 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.

Coal Reclamation Trust Investments

The coal reclamation trust holds cash equivalent investments in money market funds that are valued using quoted prices in active markets, and are reported within Level 1.

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 using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds.  We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled 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 funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, 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.

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 11 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at September 30, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at September 30, 2016
Assets
Cash equivalents	$	40,075	$	—		$	—		$	—			$	40,075
Coal reclamation trust - Cash equivalents (b)	14,749		—			—			—				14,749
Risk management activities — derivative instruments:
Commodity contracts	—		14,198			14,835			(22,798		)	(c)	6,235
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			340,436			(d)	340,436
Fixed income securities:
Cash and cash equivalent funds	—		—			—			5,032			(e)	5,032
U.S. Treasury	101,394		—			—			—				101,394
Corporate debt	—		112,923			—			—				112,923
Mortgage-backed securities	—		112,485			—			—				112,485
Municipal bonds	—		82,371			—			—				82,371
Other	—		25,112			—			—				25,112
Subtotal nuclear decommissioning trust	101,394		332,891			—			345,468				779,753
Total	$	156,218	$	347,089		$	14,835		$	322,670			$	840,812
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(67,692	)	$	(54,377	)	$	18,551		(c)	$	(103,518	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets.

(c) Represents counterparty netting, margin and collateral. See Note 6.

(d) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.

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

The following table presents the fair value at December 31, 2015, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	22,992		$	30,364		$	(25,345	)	(b)	$	28,011
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			314,957			(c)	314,957
Fixed income securities:
Cash and cash equivalent funds	12,260		—			—			(335		)	(d)	11,925
U.S. Treasury	117,245		—			—			—				117,245
Corporate debt	—		96,243			—			—				96,243
Mortgage-backed securities	—		99,065			—			—				99,065
Municipal bonds	—		72,206			—			—				72,206
Other	—		23,555			—			—				23,555
Subtotal nuclear decommissioning trust	129,505		291,069			—			314,622				735,196
Total	$	129,505	$	314,061		$	30,364		$	289,277			$	763,207
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(144,044	)	$	(63,343	)	$	39,698		(b)	$	(167,689	)

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

(b) Represents counterparty netting, margin and collateral. See Note 6.

(c) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.

(d) 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 September 30, 2016 and December 31, 2015 for these instruments include electricity 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 September 30, 2016 and December 31, 2015:

	September 30, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	13,726	$	36,438	Discounted cash flows	Electricity forward price (per MWh)	$18.84 - $39.44	$	29.30
Option Contracts (b)	—		1,153		Option model	Electricity forward price (per MWh)	$30.40	$	30.40
						Electricity price volatilities	86%	86		%
						Natural gas price volatilities	42%	42		%
Natural Gas:
Forward Contracts (a)	1,109		16,786		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.43 - $3.22	$	2.73
Total	$	14,835	$	54,377

(a) Includes swaps and physical and financial contracts.

(b) The remaining option contract expired on October 1, 2016; therefore there are no ranges for price and volatilities.

	December 31, 2015 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	24,543	$	54,679	Discounted cash flows	Electricity forward price (per MWh)	$15.92 - $40.73	$	26.86
Option Contracts (b)	—		5,628		Option model	Electricity forward price (per MWh)	$23.87 - $44.13	$	33.91
						Electricity price volatilities	40% - 59%	52		%
						Natural gas price volatilities	32% - 40%	35		%
Natural Gas:
Forward Contracts (a)	5,821		3,036		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.18 - $3.14	$	2.61
Total	$	30,364	$	63,343

(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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
Commodity Contracts	2016			2015			2016			2015
Net derivative balance at beginning of period	$	(32,380	)	$	(42,945	)	$	(32,979	)	$	(41,386	)
Total net gains (losses) realized/unrealized:
Included in OCI	(10		)	(207		)	94			(444		)
Deferred as a regulatory asset or liability	(13,499		)	(5,837		)	(21,103		)	(10,771		)
Settlements	5,424			7,572			11,691			12,424
Transfers into Level 3 from Level 2	1,343			(526		)	1,725			(4,494		)
Transfers from Level 3 into Level 2	(420		)	1,305			1,030			4,033
Net derivative balance at end of period	$	(39,542	)	$	(40,638	)	$	(39,542	)	$	(40,638	)
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.  See Note 2 for our long-term debt fair values.

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Nuclear Decommissioning Trusts

9 Months Ended

Sep. 30, 2016

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 10 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy.  Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities.  The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2016 and December 31, 2015 (dollars in thousands):

	Fair Value		Total Unrealized Gains		Total Unrealized Losses
September 30, 2016
Equity securities	$	340,436	$	176,495	$	(3	)
Fixed income securities	434,285		20,804		(465		)
Net receivables (a)	5,032		—		—
Total	$	779,753	$	197,299	$	(468	)

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2015
Equity securities	$	314,957		$	157,098	$	(115	)
Fixed income securities	420,574			11,955		(2,645		)
Net payables (a)	(335		)	—		—
Total	$	735,196		$	169,053	$	(2,760	)

(a) Net receivables/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 thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Realized gains	$	4,033		$	1,919		$	8,753		$	4,374
Realized losses	(3,345		)	(2,106		)	(6,481		)	(4,156		)
Proceeds from the sale of securities (a)	156,825			104,525			447,419			330,304

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2016 is as follows (dollars in thousands):

	Fair Value
Less than one year	$	8,429
1 year – 5 years	134,200
5 years – 10 years	102,835
Greater than 10 years	188,821
Total	$	434,285

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New Accounting Standards

9 Months Ended

Sep. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

New Accounting Standards

In May 2014, a new revenue recognition accounting standard was issued. This standard 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. Since the issuance of the new revenue standard, additional guidance has been issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. 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. We are currently evaluating the new standard, and related amendments, and the impacts it may have on our financial statements.

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new guidance will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The guidance must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In March 2016, new stock compensation accounting guidance was issued that modifies the accounting for employee share-based payments. The new guidance will require all tax benefits and deficiencies arising from share-based payments to be recognized in net income, modifies the tax withholding threshold for awards to qualify for equity classification, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. The new guidance is effective for us on January 1, 2017, with early application permitted. Certain aspects of the guidance must be adopted using a prospective approach and other aspects will be adopted using a retrospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In June 2016, new accounting guidance was issued that amends the measurement of credit losses on certain financial instruments. The new guidance will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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Changes in Accumulated Other Comprehensive Loss

9 Months Ended

Sep. 30, 2016

Accumulated Other Comprehensive Income (Loss) [Line Items]

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Balance at beginning of period	$	(43,719	)	$	(65,600	)	$	(44,748	)	$	(68,141	)
Derivative Instruments
OCI (loss) before reclassifications	(29		)	(151		)	(595		)	(926		)
Amounts reclassified from accumulated other comprehensive loss (a)	798			892			2,564			3,742
Net current period OCI (loss)	769			741			1,969			2,816
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	—			—			(1,585		)	(969		)
Amounts reclassified from accumulated other comprehensive loss (b)	804			869			2,218			2,304
Net current period OCI (loss)	804			869			633			1,335
Balance at end of period	$	(42,146	)	$	(63,990	)	$	(42,146	)	$	(63,990	)

(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 6.

(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

The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Balance at beginning of period	$	(25,928	)	$	(45,651	)	$	(27,097	)	$	(48,333	)
Derivative Instruments
OCI (loss) before reclassifications	(29		)	(151		)	(595		)	(926		)
Amounts reclassified from accumulated other comprehensive loss (a)	798			892			2,564			3,742
Net current period OCI (loss)	769			741			1,969			2,816
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	—			—			(1,521		)	(927		)
Amounts reclassified from accumulated other comprehensive loss (b)	799			870			2,289			2,404
Net current period OCI (loss)	799			870			768			1,477
Balance at end of period	$	(24,360	)	$	(44,040	)	$	(24,360	)	$	(44,040	)

(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 6.

(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

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

In the second quarter of 2016, APS recognized an asset retirement obligation (“ARO”) for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million.

In the third quarter of 2016, 4CA acquired El Paso Electric’s share of Four Corners Units 4 & 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million.

The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2016 (dollars in thousands): 

Asset retirement obligations at January 1, 2016	$	443,576
Changes attributable to:
Accretion expense	19,868
Settlements	(11,891		)
Newly incurred or acquired liabilities	18,927
Asset retirement obligations at September 30, 2016	$	470,480

Decommissioning activities for Four Corners Units 1-3 began in January 2014. Decommissioning activities for Cholla Ash Ponds began in January 2015. Thus, $12 million of the total asset retirement obligation of $470 million at September 30, 2016, 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

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New Accounting Standards (Policies)

9 Months Ended

Sep. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

In May 2014, a new revenue recognition accounting standard was issued. This standard 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. Since the issuance of the new revenue standard, additional guidance has been issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. 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. We are currently evaluating the new standard, and related amendments, and the impacts it may have on our financial statements.

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new guidance will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The guidance must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In March 2016, new stock compensation accounting guidance was issued that modifies the accounting for employee share-based payments. The new guidance will require all tax benefits and deficiencies arising from share-based payments to be recognized in net income, modifies the tax withholding threshold for awards to qualify for equity classification, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. The new guidance is effective for us on January 1, 2017, with early application permitted. Certain aspects of the guidance must be adopted using a prospective approach and other aspects will be adopted using a retrospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

In June 2016, new accounting guidance was issued that amends the measurement of credit losses on certain financial instruments. The new guidance will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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Consolidation and Nature of Operations (Tables)

9 Months Ended

Sep. 30, 2016

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):

	Nine Months Ended   September 30,
	2016		2015
Cash paid during the period for:
Income taxes, net of refunds	$	2,562	$	2,692
Interest, net of amounts capitalized	146,691		143,116
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	91,315	$	36,718

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Long-Term Debt and Liquidity Matters (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

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

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

	As of September 30, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125,000	$	125,000	$	125,000	$	125,000
APS	4,037,236		4,609,003		3,694,971		3,981,367
Total	$	4,162,236	$	4,734,003	$	3,819,971	$	4,106,367

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Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Proposed capital structure and cost of capital

the following proposed capital structure and costs of capital:

	Capital Structure		Cost of Capital
Long-term debt	44.2	%	5.13	%
Common stock equity	55.8	%	10.50	%
Weighted-average cost of capital			8.13	%

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 2016 and 2015 (dollars in thousands):

	Nine Months Ended   September 30,
	2016			2015
Beginning balance	$	(9,688	)	$	6,925
Deferred fuel and purchased power costs — current period	46,185			137
Amounts charged to customers	(28,365		)	(19,284		)
Ending balance	$	8,132		$	(12,222	)

Schedule of regulatory assets

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

	Amortization Through	September 30, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	608,312	$	—	$	619,223
Retired power plant costs	2033	9,913		120,072		9,913		127,518
Income taxes — allowance for funds used during construction ("AFUDC") equity	2046	5,419		151,451		5,495		133,712
Deferred fuel and purchased power — mark-to-market (Note 6)	2019	30,748		53,350		71,852		69,697
Deferred fuel and purchased power (c) (e)	2017	8,132		—		—		—
Four Corners cost deferral	2024	6,689		58,566		6,689		63,582
Income taxes — investment tax credit basis adjustment	2045	1,852		46,699		1,766		48,462
Lost fixed cost recovery (b)	2017	55,297		—		45,507		—
Palo Verde VIEs (Note 5)	2046	—		18,620		—		18,143
Deferred compensation	2036	—		36,071		—		34,751
Deferred property taxes	(c)	—		67,547		—		50,453
Loss on reacquired debt	2034	1,592		16,521		1,515		16,375
Tax expense of Medicare subsidy	2024	1,512		10,774		1,520		12,163
Transmission vegetation management	2016	—		—		4,543		—
Mead-Phoenix transmission line CIAC	2050	332		10,791		332		11,040
Transmission cost adjustor (b)	2018	—		4,687		—		2,942
Coal reclamation	2026	418		5,286		418		6,085
Other	Various	316		3,403		5		—
Total regulatory assets (d)		$	122,220	$	1,212,150	$	149,555	$	1,214,146

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

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

(e) Subject to a carrying charge.

Schedule of regulatory liabilities

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

	Amortization Through	September 30, 2016				December 31, 2015
		Current		Non-Current		Current		Non-Current
Asset retirement obligations	2057	$	—	$	305,862	$	—	$	277,554
Removal costs	(a)	27,626		237,885		39,746		240,367
Other postretirement benefits	(d)	33,294		146,988		34,100		179,521
Income taxes — deferred investment tax credit	2045	3,774		93,578		3,604		97,175
Income taxes — change in rates	2046	1,771		70,233		1,113		72,454
Spent nuclear fuel	2047	—		71,884		3,051		67,437
Renewable energy standard (b)	2017	28,921		1,091		43,773		4,365
Demand side management (b)	2017	4,261		21,863		6,079		19,115
Sundance maintenance	2030	—		14,885		—		13,678
Deferred fuel and purchased power (b) (c)	2017	—		—		9,688		—
Deferred gains on utility property	2019	2,063		9,335		2,062		6,001
Transmission cost adjustor (b)	2017	2,077		—		—		—
Four Corners coal reclamation	2031	—		17,213		—		8,920
Other	Various	526		7,532		2,550		7,565
Total regulatory liabilities		$	104,313	$	998,349	$	145,766	$	994,152

(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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Retirement Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2016

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 thousands):

	Pension Benefits												Other Benefits
	Three Months Ended   September 30,						Nine Months Ended   September 30,						Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
Service cost — benefits earned during the period	$	13,448		$	14,907		$	40,344		$	44,721		$	3,748		$	4,207		$	11,245		$	12,620
Interest cost on benefit obligation	32,912			30,996			98,735			92,987			7,430			7,026			22,291			21,077
Expected return on plan assets	(43,477		)	(44,808		)	(130,429		)	(134,424		)	(9,123		)	(9,214		)	(27,371		)	(27,641		)
Amortization of:
Prior service cost	132			148			395			446			(9,471		)	(9,492		)	(28,413		)	(28,476		)
Net actuarial loss	10,179			7,764			30,538			23,292			1,147			1,220			3,442			3,661
Net periodic benefit cost	$	13,194		$	9,007		$	39,583		$	27,022		$	(6,269	)	$	(6,253	)	$	(18,806	)	$	(18,759	)
Portion of cost charged to expense	$	6,476		$	4,433		$	19,427		$	15,653		$	(3,077	)	$	(3,078	)	$	(9,230	)	$	(7,348	)

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2016

Variable Interest Entities [Abstract]

Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

Our Condensed Consolidated Balance Sheets at September 30, 2016 and December 31, 2015 include the following amounts relating to the VIEs (in thousands):

	September 30, 2016		December 31, 2015
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	114,483	$	117,385
Equity — Noncontrolling interests	138,789		135,540

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Derivative Accounting (Tables)

9 Months Ended

Sep. 30, 2016

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 September 30, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 

Commodity	Quantity
Power	1,630	GWh
Gas	193	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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Financial Statement Location	Three Months Ended   September 30,						Nine Months Ended   September 30,
Commodity Contracts		2016			2015			2016			2015
Gain (loss) recognized in OCI on derivative instruments (effective portion)	OCI — derivative instruments	$	(47	)	$	(247	)	$	13		$	(534	)
Loss reclassified from accumulated OCI into income (effective portion realized) (a)	Fuel and purchased power (b)	(1,298		)	(1,459		)	(3,255		)	(5,232		)

(a) During the three and nine months ended September 30, 2016 and 2015, we had no losses 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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Financial Statement Location	Three Months Ended   September 30,						Nine Months Ended September 30,
Commodity Contracts		2016			2015			2016			2015
Net gain recognized in income	Operating revenues	$	41		$	560		$	524		$	445
Net loss recognized in income	Fuel and purchased power (a)	(35,103		)	(50,909		)	(5,145		)	(85,099		)
Total		$	(35,062	)	$	(50,349	)	$	(4,621	)	$	(84,654	)

(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 September 30, 2016 and December 31, 2015.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance Sheet
Current assets	$	24,894		$	(18,816	)	$	6,078		$	157		$	6,235
Investments and other assets	4,146			(4,146		)	—			—			—
Total assets	29,040			(22,962		)	6,078			157			6,235
Current liabilities	(59,586		)	18,816			(40,770		)	(4,405		)	(45,175		)
Deferred credits and other	(62,489		)	4,146			(58,343		)	—			(58,343		)
Total liabilities	(122,075		)	22,962			(99,113		)	(4,405		)	(103,518		)
Total	$	(93,035	)	$	—		$	(93,035	)	$	(4,248	)	$	(97,283	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $4,405, and cash margin provided to counterparties of $157.

As of December 31, 2015: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	37,396		$	(22,163	)	$	15,233		$	672		$	15,905
Investments and other assets	15,960			(3,854		)	12,106			—			12,106
Total assets	53,356			(26,017		)	27,339			672			28,011
Current liabilities	(113,560		)	40,223			(73,337		)	(4,379		)	(77,716		)
Deferred credits and other	(93,827		)	3,854			(89,973		)	—			(89,973		)
Total liabilities	(207,387		)	44,077			(163,310		)	(4,379		)	(167,689		)
Total	$	(154,031	)	$	18,060		$	(135,971	)	$	(3,707	)	$	(139,678	)

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

(b) Includes cash collateral provided to counterparties of $18,060.

(c) Represents cash collateral and cash 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 $4,379, and cash margin provided to counterparties of $672.

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 September 30, 2016 and December 31, 2015.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of September 30, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			AmountReported onBalance Sheet
Current assets	$	24,894		$	(18,816	)	$	6,078		$	157		$	6,235
Investments and other assets	4,146			(4,146		)	—			—			—
Total assets	29,040			(22,962		)	6,078			157			6,235
Current liabilities	(59,586		)	18,816			(40,770		)	(4,405		)	(45,175		)
Deferred credits and other	(62,489		)	4,146			(58,343		)	—			(58,343		)
Total liabilities	(122,075		)	22,962			(99,113		)	(4,405		)	(103,518		)
Total	$	(93,035	)	$	—		$	(93,035	)	$	(4,248	)	$	(97,283	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $4,405, and cash margin provided to counterparties of $157.

As of December 31, 2015: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	37,396		$	(22,163	)	$	15,233		$	672		$	15,905
Investments and other assets	15,960			(3,854		)	12,106			—			12,106
Total assets	53,356			(26,017		)	27,339			672			28,011
Current liabilities	(113,560		)	40,223			(73,337		)	(4,379		)	(77,716		)
Deferred credits and other	(93,827		)	3,854			(89,973		)	—			(89,973		)
Total liabilities	(207,387		)	44,077			(163,310		)	(4,379		)	(167,689		)
Total	$	(154,031	)	$	18,060		$	(135,971	)	$	(3,707	)	$	(139,678	)

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

(b) Includes cash collateral provided to counterparties of $18,060.

(c) Represents cash collateral and cash 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 $4,379, and cash margin provided to counterparties of $672.

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 September 30, 2016 (dollars in thousands):

	September 30, 2016
Aggregate fair value of derivative instruments in a net liability position	$	122,075
Cash collateral posted	—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	61,177

(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)

9 Months Ended

Sep. 30, 2016

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

Detail of other income and other expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Other income:
Interest income	$	65		$	127		$	370		$	422
Investment gains — net	—			—			13			—
Miscellaneous	6			12			2			127
Total other income	$	71		$	139		$	385		$	549
Other expense:
Non-operating costs	$	(2,502	)	$	(2,328	)	$	(6,636	)	$	(6,529	)
Investment losses — net	(450		)	(563		)	(1,508		)	(1,708		)
Miscellaneous	(2,253		)	(2,647		)	(3,941		)	(4,196		)
Total other expense	$	(5,205	)	$	(5,538	)	$	(12,085	)	$	(12,433	)

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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Other income:
Interest income	$	—		$	32		$	181		$	105
Gain on disposition of property	183			(58		)	5,504			627
Miscellaneous	384			676			1,239			1,267
Total other income	$	567		$	650		$	6,924		$	1,999
Other expense:
Non-operating costs (a)	$	(2,714	)	$	(2,248	)	$	(7,398	)	$	(6,643	)
Loss on disposition of property	36			(327		)	(1,048		)	(934		)
Miscellaneous	(1,098		)	(1,390		)	(4,510		)	(4,191		)
Total other expense	$	(3,776	)	$	(3,965	)	$	(12,956	)	$	(11,768	)

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

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2016

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 nine months ended September 30, 2016 and 2015 (in thousands, except per share amounts):

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2016		2015		2016		2015
Net income attributable to common shareholders	$	263,027	$	257,116	$	388,788	$	396,140
Weighted average common shares outstanding — basic	111,416		111,036		111,363		110,984
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	684		580		624		506
Weighted average common shares outstanding — diluted	112,100		111,616		111,987		111,490
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	2.36	$	2.32	$	3.49	$	3.57
Net income attributable to common shareholders — diluted	$	2.35	$	2.30	$	3.47	$	3.55

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

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 September 30, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at September 30, 2016
Assets
Cash equivalents	$	40,075	$	—		$	—		$	—			$	40,075
Coal reclamation trust - Cash equivalents (b)	14,749		—			—			—				14,749
Risk management activities — derivative instruments:
Commodity contracts	—		14,198			14,835			(22,798		)	(c)	6,235
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			340,436			(d)	340,436
Fixed income securities:
Cash and cash equivalent funds	—		—			—			5,032			(e)	5,032
U.S. Treasury	101,394		—			—			—				101,394
Corporate debt	—		112,923			—			—				112,923
Mortgage-backed securities	—		112,485			—			—				112,485
Municipal bonds	—		82,371			—			—				82,371
Other	—		25,112			—			—				25,112
Subtotal nuclear decommissioning trust	101,394		332,891			—			345,468				779,753
Total	$	156,218	$	347,089		$	14,835		$	322,670			$	840,812
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(67,692	)	$	(54,377	)	$	18,551		(c)	$	(103,518	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets.

(c) Represents counterparty netting, margin and collateral. See Note 6.

(d) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.

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

The following table presents the fair value at December 31, 2015, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2015
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	22,992		$	30,364		$	(25,345	)	(b)	$	28,011
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			314,957			(c)	314,957
Fixed income securities:
Cash and cash equivalent funds	12,260		—			—			(335		)	(d)	11,925
U.S. Treasury	117,245		—			—			—				117,245
Corporate debt	—		96,243			—			—				96,243
Mortgage-backed securities	—		99,065			—			—				99,065
Municipal bonds	—		72,206			—			—				72,206
Other	—		23,555			—			—				23,555
Subtotal nuclear decommissioning trust	129,505		291,069			—			314,622				735,196
Total	$	129,505	$	314,061		$	30,364		$	289,277			$	763,207
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(144,044	)	$	(63,343	)	$	39,698		(b)	$	(167,689	)

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

(b) Represents counterparty netting, margin and collateral. See Note 6.

(c) Valued using NAV as a practical expedient, and therefore not classified in the fair value hierarchy.

(d) 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 September 30, 2016 and December 31, 2015:

	September 30, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	13,726	$	36,438	Discounted cash flows	Electricity forward price (per MWh)	$18.84 - $39.44	$	29.30
Option Contracts (b)	—		1,153		Option model	Electricity forward price (per MWh)	$30.40	$	30.40
						Electricity price volatilities	86%	86		%
						Natural gas price volatilities	42%	42		%
Natural Gas:
Forward Contracts (a)	1,109		16,786		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.43 - $3.22	$	2.73
Total	$	14,835	$	54,377

(a) Includes swaps and physical and financial contracts.

(b) The remaining option contract expired on October 1, 2016; therefore there are no ranges for price and volatilities.

	December 31, 2015 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input		Weighted-Average
Commodity Contracts	Assets		Liabilities				Range
Electricity:
Forward Contracts (a)	$	24,543	$	54,679	Discounted cash flows	Electricity forward price (per MWh)	$15.92 - $40.73	$	26.86
Option Contracts (b)	—		5,628		Option model	Electricity forward price (per MWh)	$23.87 - $44.13	$	33.91
						Electricity price volatilities	40% - 59%	52		%
						Natural gas price volatilities	32% - 40%	35		%
Natural Gas:
Forward Contracts (a)	5,821		3,036		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.18 - $3.14	$	2.61
Total	$	30,364	$	63,343

(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 nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
Commodity Contracts	2016			2015			2016			2015
Net derivative balance at beginning of period	$	(32,380	)	$	(42,945	)	$	(32,979	)	$	(41,386	)
Total net gains (losses) realized/unrealized:
Included in OCI	(10		)	(207		)	94			(444		)
Deferred as a regulatory asset or liability	(13,499		)	(5,837		)	(21,103		)	(10,771		)
Settlements	5,424			7,572			11,691			12,424
Transfers into Level 3 from Level 2	1,343			(526		)	1,725			(4,494		)
Transfers from Level 3 into Level 2	(420		)	1,305			1,030			4,033
Net derivative balance at end of period	$	(39,542	)	$	(40,638	)	$	(39,542	)	$	(40,638	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	—

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Nuclear Decommissioning Trusts (Tables)

9 Months Ended

Sep. 30, 2016

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 September 30, 2016 and December 31, 2015 (dollars in thousands):

	Fair Value		Total Unrealized Gains		Total Unrealized Losses
September 30, 2016
Equity securities	$	340,436	$	176,495	$	(3	)
Fixed income securities	434,285		20,804		(465		)
Net receivables (a)	5,032		—		—
Total	$	779,753	$	197,299	$	(468	)

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2015
Equity securities	$	314,957		$	157,098	$	(115	)
Fixed income securities	420,574			11,955		(2,645		)
Net payables (a)	(335		)	—		—
Total	$	735,196		$	169,053	$	(2,760	)

(a) Net receivables/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 thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2016			2015			2016			2015
Realized gains	$	4,033		$	1,919		$	8,753		$	4,374
Realized losses	(3,345		)	(2,106		)	(6,481		)	(4,156		)
Proceeds from the sale of securities (a)	156,825			104,525			447,419			330,304

(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 September 30, 2016 is as follows (dollars in thousands):

	Fair Value
Less than one year	$	8,429
1 year – 5 years	134,200
5 years – 10 years	102,835
Greater than 10 years	188,821
Total	$	434,285

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Changes in Accumulated Other Comprehensive Loss (Tables)

9 Months Ended

Sep. 30, 2016

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 table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Balance at beginning of period	$	(43,719	)	$	(65,600	)	$	(44,748	)	$	(68,141	)
Derivative Instruments
OCI (loss) before reclassifications	(29		)	(151		)	(595		)	(926		)
Amounts reclassified from accumulated other comprehensive loss (a)	798			892			2,564			3,742
Net current period OCI (loss)	769			741			1,969			2,816
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	—			—			(1,585		)	(969		)
Amounts reclassified from accumulated other comprehensive loss (b)	804			869			2,218			2,304
Net current period OCI (loss)	804			869			633			1,335
Balance at end of period	$	(42,146	)	$	(63,990	)	$	(42,146	)	$	(63,990	)

(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 6.

(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 table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and nine months ended September 30, 2016 and 2015 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Balance at beginning of period	$	(25,928	)	$	(45,651	)	$	(27,097	)	$	(48,333	)
Derivative Instruments
OCI (loss) before reclassifications	(29		)	(151		)	(595		)	(926		)
Amounts reclassified from accumulated other comprehensive loss (a)	798			892			2,564			3,742
Net current period OCI (loss)	769			741			1,969			2,816
Pension and Other Postretirement Benefits
OCI (loss) before reclassifications	—			—			(1,521		)	(927		)
Amounts reclassified from accumulated other comprehensive loss (b)	799			870			2,289			2,404
Net current period OCI (loss)	799			870			768			1,477
Balance at end of period	$	(24,360	)	$	(44,040	)	$	(24,360	)	$	(44,040	)

(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 6.

(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)

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Change in asset retirement obligations

The following schedule shows the change in our asset retirement obligations for the nine months ended September 30, 2016 (dollars in thousands): 

Asset retirement obligations at January 1, 2016	$	443,576
Changes attributable to:
Accretion expense	19,868
Settlements	(11,891		)
Newly incurred or acquired liabilities	18,927
Asset retirement obligations at September 30, 2016	$	470,480

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Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash paid during the period for:
Income taxes, net of refunds	$ 2,562	$ 2,692
Interest, net of amounts capitalized	146,691	143,116
Significant non-cash investing and financing activities:
Accrued capital expenditures	$ 91,315	$ 36,718

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Long-Term Debt and Liquidity Matters - Narrative (Details)	Aug. 31, 2016 USD ($)	Aug. 01, 2016 USD ($)	Sep. 30, 2016 USD ($) Facility	Sep. 20, 2016 USD ($)	Jun. 01, 2016 USD ($)	May 13, 2016 USD ($)	May 12, 2016 USD ($)	May 06, 2016 USD ($)	Apr. 22, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Long-Term Debt and Liquidity Matters
Shot-term debt			$ 117,300,000								$ 0
Debt Provisions
Total shareholder equity			4,853,346,000								4,583,917,000
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing in May 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility							$ 200,000,000
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing May 2021
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 (up to)			300,000,000
Outstanding borrowings			0
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing in August 2017
Long-Term Debt and Liquidity Matters
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)	$ 75,000,000
Debt instrument, term	364 days
Shot-term debt			34,000,000
Pinnacle West | Letter of Credit | Revolving credit facility maturing May 2021
Long-Term Debt and Liquidity Matters
Outstanding letters of credit			0
Pinnacle West | Commercial paper | Revolving credit facility maturing May 2021
Long-Term Debt and Liquidity Matters
Commercial paper			0
APS
Long-Term Debt and Liquidity Matters
Shot-term debt			83,300,000								0
Debt Provisions
Total shareholder equity			4,946,651,000								4,679,254,000
APS | ACC
Debt Provisions
Total shareholder equity			4,900,000,000
Total capitalization			9,200,000,000
Dividend restrictions, shareholder equity required			$ 3,700,000,000
APS | ACC | Minimum
Debt Provisions
Required common equity ratio ordered by ACC (as a percent) (at least)			40.00%
APS | Arizona pollution control corporation revenue refunding bonds, 2009 series A
Long-Term Debt and Liquidity Matters
Debt Instrument, repurchased face amount					$ 13,000,000
APS | Revolving Credit Facility | Revolving credit facility maturing in May 2019
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility							$ 500,000,000
APS | Revolving Credit Facility | Revolving Credit Facilities Maturing in 2020 and 2021
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility			$ 1,000,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)			1,400,000,000
Outstanding borrowings			$ 0
Number of line of credit facilities | Facility			2
APS | Revolving Credit Facility | Revolving credit facility maturing May 2021
Long-Term Debt and Liquidity Matters
Current borrowing capacity on credit facility			$ 500,000,000			$ 500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)			700,000,000
APS | Revolving Credit Facility | Revolving credit facility maturing September 2020
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 (up to)			700,000,000
APS | Commercial paper
Long-Term Debt and Liquidity Matters
Maximum commercial paper support available under credit facility			500,000,000							$ 500,000,000	$ 250,000,000
APS | Commercial paper | Revolving Credit Facilities Maturing in 2020 and 2021
Long-Term Debt and Liquidity Matters
Commercial paper			$ 83,000,000
APS | Secured debt | Term loan facility maturing April 22, 2019
Long-Term Debt and Liquidity Matters
Debt issued									$ 100,000,000
Senior Notes | APS | Unsecured senior notes 3.75 percent mature on 15 May, 2046
Long-Term Debt and Liquidity Matters
Debt issued								$ 350,000,000
Debt instrument, stated interest rate								3.75%
Senior Notes | APS | Unsecured senior notes 6.25 percent maturing on 01 August, 2016
Long-Term Debt and Liquidity Matters
Debt instrument, stated interest rate		6.25%
Repayments of debt		$ 250,000,000
Senior Notes | APS | Unsecured senior notes 2.55 percent maturing on 15 September, 2026
Long-Term Debt and Liquidity Matters
Debt issued				$ 250,000,000
Debt instrument, stated interest rate				2.55%
Current Maturities of Long-term Debt | APS | Arizona pollution control corporation revenue refunding bonds, 2009 series D and E
Long-Term Debt and Liquidity Matters
Debt Instrument, repurchased face amount					$ 64,000,000
Current Maturities of Long-term Debt | APS | Arizona pollution control corporation revenue refunding bond, 2009 series B
Long-Term Debt and Liquidity Matters
Debt Instrument, repurchased face amount				$ 27,000,000
LIBOR | Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing in August 2017
Long-Term Debt and Liquidity Matters
Debt instrument, basis spread on variable rate	0.80%

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Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 4,162,236	$ 3,819,971
Fair Value	4,734,003	4,106,367
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	125,000	125,000
Fair Value	125,000	125,000
Arizona Public Service Company
Estimated fair value of long-term debt, including current maturities
Carrying Amount	4,037,236	3,694,971
Fair Value	$ 4,609,003	$ 3,981,367

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Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS $ in Millions	Jun. 01, 2016 USD ($) kWh $ / kWh	Dec. 31, 2015 USD ($)	Jun. 01, 2011 USD ($)
Public Utilities, General Disclosures [Line Items]
Net retail rate increase	$ 165.9		$ 95.5
Adjustor account balance transferred into base rates, amount		$ 267.6
Approximate percentage of increase in average customer bill	5.74%
Approximate percentage of increase in average residential customer bill	7.96%
Original cost rate base	$ 6,800.0
Required return on incremental fair value rate base above original cost rate base	1.00%
Base rate for fuel and purchased power costs (in dollars per kWh) | $ / kWh	0.029882
Decrease in base rate for fuel and purchased power costs (in dollars per kWh) | $ / kWh	0.03207
Plan option, non-partial requirements customers, maximum average monthly energy usage (in kWh) | kWh	600
Public utilities, case completion term	12 months
Approximate percentage of increase in the average retail customer bill			6.60%
Proposed Capital Structure and Costs of Capital
Requested debt capital structure (as a percent)	44.20%
Requested debt cost of capital (as a percent)	5.13%
Requested equity capital structure (as a percent)	55.80%
Requested equity cost of capital (as a percent)	10.50%
Requested weighted-average cost of capital (as a percent)	8.13%
Four Corners Power Plant
Public Utilities, General Disclosures [Line Items]
Authorization to defer for potential future recovery of construction costs	$ 400.0
Ocotillo Plant
Public Utilities, General Disclosures [Line Items]
Authorization to defer for potential future recovery of construction costs	$ 500.0

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Regulatory Matters (Details)											1 Months Ended		2 Months Ended	3 Months Ended	9 Months Ended		12 Months Ended
	Jun. 01, 2016 USD ($)	Feb. 01, 2016 $ / kWh	Jan. 15, 2016 USD ($)	Jan. 01, 2016 USD ($)	Jun. 01, 2015 USD ($)	Mar. 02, 2015 USD ($)	Nov. 04, 2014	Mar. 01, 2014 USD ($)	Jan. 01, 2014 USD ($) $ / kWh	Jan. 06, 2012 USD ($) $ / kWh	Sep. 30, 2016 USD ($) phase	Dec. 31, 2014 USD ($) penetration_feeder storage_system MW	Apr. 30, 2014 workshop	Jan. 31, 2016 $ / kWh	Sep. 30, 2016 USD ($) $ / kWh	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($) $ / kWh	Jul. 12, 2016 USD ($)	Jul. 01, 2016 USD ($)	Apr. 01, 2016 USD ($)	Jan. 12, 2016 USD ($)	Nov. 25, 2015 USD ($)	Mar. 20, 2015 project
Change in regulatory asset
Deferred fuel and purchased power costs — current period															$ 46,185,000	$ 137,000
Amounts charged to customers															(28,366,000)	(19,284,000)
APS
Change in regulatory asset
Deferred fuel and purchased power costs — current period															46,185,000	137,000
Amounts charged to customers															$ (28,366,000)	(19,284,000)
RES 2014 | APS | Alternative to AZ Sun Program, Phase 1
Settlement Agreement
Request to build additional utility scale solar, capacity | MW												8
RES 2014 | APS | Alternative to AZ Sun Program Phase 2
Settlement Agreement
Request to build additional utility scale solar, capacity | MW												2
Number of energy storage systems | storage_system												2
Number of high solar penetration feeders | penetration_feeder												2
Lost Fixed Cost Recovery Mechanisms | APS
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
Percentage of retail revenues											1.00%				1.00%
Amount of adjustment representing prorated sales losses approval			$ 46,400,000			$ 38,500,000		$ 25,300,000
Increase in amount of adjustment representing prorated sales losses			$ 7,900,000
ACC | Retail Rate Case Filing with Arizona Corporation Commission | APS
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
Change in regulatory asset
Reduced system benefits charge, amount				$ 14,600,000
ACC | Retail Rate Case Filing with Arizona Corporation Commission | APS | Maximum
Settlement Agreement
Annual cost recovery due to modifications to the Environmental Improvement Surcharge										$ 5,000,000
ACC | RES | APS
Settlement Agreement
Plan term															5 years
ACC | RES 2016 | APS
Settlement Agreement
Amount of approved budget																					$ 148,000,000
ACC | RES 2017 | APS
Settlement Agreement
Amount of proposed budget																			$ 150,000,000
ACC | Modernization and Expansion of the Renewal Energy Standard [Member] | APS
Settlement Agreement
Proposed renewal energy standard, percent of retail sales											30.00%
Current renewal energy standard, percent of retail sales											15.00%
ACC | DSMAC 2015 | APS
Settlement Agreement
Amount of approved budget																				$ 68,900,000		$ 68,900,000
Additional budget approved																		$ 4,000,000
Number of resource savings projects | project																							3
ACC | DSMC 2016 | APS
Settlement Agreement
Amount of approved budget					$ 68,900,000
ACC | Electric energy efficiency standard | APS
Settlement Agreement
Number of workshops | workshop													3
Number of days to convene a workshop							120 days
ACC | Power Supply Adjustor (PSA) | APS
Change in regulatory asset
Beginning balance				$ (9,688,000)											$ (9,688,000)	6,925,000	$ 6,925,000
Deferred fuel and purchased power costs — current period															46,185,000	137,000
Amounts charged to customers															(28,365,000)	(19,284,000)
Ending balance											$ 8,132,000	$ 6,925,000			$ 8,132,000	$ (12,222,000)	$ (9,688,000)
PSA rate (in dollars per kWh) | $ / kWh		0.001678
PSA rate for prior year (in dollars per kWh) | $ / kWh																	0.000887
Forward component of increase in PSA (in dollars per kWh) | $ / kWh		0.001975
Historical component of increase in PSA (in dollars per kWh) | $ / kWh		(0.000297)
Transition component increase in PSA (in dollars per kWh) | $ / kWh														(0.004936)
ACC | Net Metering | APS
Change in regulatory asset
Charge on future customers who install rooftop solar panels (in dollars per kWh) | $ / kWh									0.70						0.70
Rate matter case, umber of filing phases | phase											2
Estimated monthly collection due to charge on future customers who install rooftop solar panels									$ 4.90
United States Federal Energy Regulatory Commission | Open Access Transmission Tariff [Member] | APS
Change in regulatory asset
Decrease in annual wholesale transmission rates					$ 17,600,000
Increase in annual wholesale transmission rates	$ 24,900,000

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Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions			3 Months Ended	9 Months Ended
	Dec. 23, 2014	Dec. 30, 2013	Sep. 30, 2016	Sep. 30, 2016	Dec. 31, 2015
SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Ownership interest acquired		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1
Net receipt due to negotiation of alternate arrangement		$ 40.0
Four Corners cost deferral | SCE | Four Corners Units 4 and 5
Business Acquisition [Line Items]
Regulatory assets, non-current			$ 65.0	$ 65.0
Regulatory noncurrent asset amortization period				10 years
Retired power plant costs
Business Acquisition [Line Items]
Net book value			117.0	$ 117.0
Four Corners | SCE
Business Acquisition [Line Items]
Regulatory assets, non-current					$ 12.0
Regulatory asset, write off amount			$ 12.0

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Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Detail of regulatory assets
Regulatory assets, current	$ 122,220	$ 149,555
Regulatory assets, non-current	1,212,150	1,214,146
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	608,312	619,223
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	9,913	9,913
Regulatory assets, non-current	120,072	127,518
Income taxes — allowance for funds used during construction (AFUDC) equity
Detail of regulatory assets
Regulatory assets, current	5,419	5,495
Regulatory assets, non-current	151,451	133,712
Deferred fuel and purchased power — mark-to-market (Note 6)
Detail of regulatory assets
Regulatory assets, current	30,748	71,852
Regulatory assets, non-current	53,350	69,697
Deferred fuel and purchased power (c) (e)
Detail of regulatory assets
Regulatory assets, current	8,132	0
Regulatory assets, non-current	0	0
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	6,689	6,689
Regulatory assets, non-current	58,566	63,582
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,852	1,766
Regulatory assets, non-current	46,699	48,462
Lost fixed cost recovery (b)
Detail of regulatory assets
Regulatory assets, current	55,297	45,507
Regulatory assets, non-current	0	0
Palo Verde VIEs (Note 5)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	18,620	18,143
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	36,071	34,751
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	67,547	50,453
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,592	1,515
Regulatory assets, non-current	16,521	16,375
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,512	1,520
Regulatory assets, non-current	10,774	12,163
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	0	4,543
Regulatory assets, non-current	0	0
Mead-Phoenix transmission line CIAC
Detail of regulatory assets
Regulatory assets, current	332	332
Regulatory assets, non-current	10,791	11,040
Transmission cost adjustor (b)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	4,687	2,942
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	418	418
Regulatory assets, non-current	5,286	6,085
Other
Detail of regulatory assets
Regulatory assets, current	316	5
Regulatory assets, non-current	$ 3,403	$ 0

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Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Detail of regulatory liabilities
Regulatory liabilities, current	$ 104,313	$ 145,766
Regulatory liabilities, non-current	998,349	994,152
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	305,862	277,554
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	27,626	39,746
Regulatory liabilities, non-current	237,885	240,367
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	33,294	34,100
Regulatory liabilities, non-current	146,988	179,521
Income taxes — deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	3,774	3,604
Regulatory liabilities, non-current	93,578	97,175
Income taxes — change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	1,771	1,113
Regulatory liabilities, non-current	70,233	72,454
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	0	3,051
Regulatory liabilities, non-current	71,884	67,437
Renewable energy standard (b)
Detail of regulatory liabilities
Regulatory liabilities, current	28,921	43,773
Regulatory liabilities, non-current	1,091	4,365
Demand side management (b)
Detail of regulatory liabilities
Regulatory liabilities, current	4,261	6,079
Regulatory liabilities, non-current	21,863	19,115
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	14,885	13,678
Deferred fuel and purchased power (b) (c)
Detail of regulatory liabilities
Regulatory liabilities, current	0	9,688
Regulatory liabilities, non-current	0	0
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,063	2,062
Regulatory liabilities, non-current	9,335	6,001
Transmission cost adjustor (b)
Detail of regulatory liabilities
Regulatory liabilities, current	2,077	0
Regulatory liabilities, non-current	0	0
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	17,213	8,920
Other
Detail of regulatory liabilities
Regulatory liabilities, current	526	2,550
Regulatory liabilities, non-current	$ 7,532	$ 7,565

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Retirement Plans and Other Postretirement Benefits - Narrative (Details) - USD ($)		1 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Jul. 31, 2012	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Regulatory Assets
Regulatory asset amortization period		3 years
Amortization of regulatory asset			$ 2,000,000		$ 4,000,000
Pension Benefits
Contributions
Voluntary employer contributions to pension plan				$ 100,000,000
Minimum employer contributions for the next three years				0
Maximum employer contributions for the next two years (up to)				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	$ 140,000,000
Contributions
2015				1,000,000
2016 (up to)				1,000,000
2017 (up to)				$ 1,000,000

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Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	$ 13,448	$ 14,907	$ 40,344	$ 44,721
Interest cost on benefit obligation	32,912	30,996	98,735	92,987
Expected return on plan assets	(43,477)	(44,808)	(130,429)	(134,424)
Amortization of:
Prior service cost	132	148	395	446
Net actuarial loss	10,179	7,764	30,538	23,292
Net periodic benefit cost	13,194	9,007	39,583	27,022
Portion of cost charged to expense	6,476	4,433	19,427	15,653
Other postretirement benefits
Retirement Plans and Other Benefits
Service cost — benefits earned during the period	3,748	4,207	11,245	12,620
Interest cost on benefit obligation	7,430	7,026	22,291	21,077
Expected return on plan assets	(9,123)	(9,214)	(27,371)	(27,641)
Amortization of:
Prior service cost	(9,471)	(9,492)	(28,413)	(28,476)
Net actuarial loss	1,147	1,220	3,442	3,661
Net periodic benefit cost	(6,269)	(6,253)	(18,806)	(18,759)
Portion of cost charged to expense	$ (3,077)	$ (3,078)	$ (9,230)	$ (7,348)

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Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($) power_plant	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) power_plant Lease	Sep. 30, 2015 USD ($)	Dec. 31, 1986 Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 4,873	$ 4,862	$ 14,620	$ 14,072
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	$ 4,873	4,862	$ 14,620	14,072
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	$ 5,000	15,000	$ 14,000
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period			289,000
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period			$ 456,000
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 | 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 (up to)			2 years

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Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$ 114,483	$ 117,385
Equity — Noncontrolling interests	138,789	135,540
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	114,483	117,385
Equity — Noncontrolling interests	138,789	135,540
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	114,483	117,385
Equity — Noncontrolling interests	$ 138,789	$ 135,540

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Derivative Accounting - Narrative (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Designated as Hedging Instruments
Derivative Accounting
Gross recognized derivatives	$ 2,000	$ 3,000
Commodity Contracts
Derivative Accounting
Gross recognized derivatives	122,075	$ 207,387
Additional collateral to counterparties for energy related non-derivative instrument contracts	149,000
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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Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts MMcf in Thousands	9 Months Ended
	Sep. 30, 2016 GWh MMcf
Outstanding gross notional amount of derivatives
Power | GWh	1,630
Gas | MMcf	193

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Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
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)	(1,298,000)	(1,459,000)	(3,255,000)	(5,232,000)
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net gain (loss) recognized in income	(35,062,000)	(50,349,000)	(4,621,000)	(84,654,000)
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net gain (loss) recognized in income	41,000	560,000	524,000	445,000
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net gain (loss) recognized in income	(35,103,000)	(50,909,000)	(5,145,000)	(85,099,000)
Other comprehensive income | Designated as Hedging Instruments
Gains and losses from derivative instruments
Gain (loss) recognized in OCI on derivative instruments (effective portion)	$ (47,000)	$ (247,000)	$ 13,000	$ (534,000)

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Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - Commodity Contracts - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Assets
Gross Recognized Derivatives	$ 29,040,000	$ 53,356,000
Amounts Offset	(22,962,000)	(26,017,000)
Net Recognized Derivatives	6,078,000	27,339,000
Other	157,000	672,000
Amount Reported on Balance Sheet	6,235,000	28,011,000
Liabilities
Gross Recognized Derivatives	(122,075,000)	(207,387,000)
Amounts Offset	22,962,000	44,077,000
Net Recognized Derivatives	(99,113,000)	(163,310,000)
Other	(4,405,000)	(4,379,000)
Amount Reported on Balance Sheet	(103,518,000)	(167,689,000)
Assets and Liabilities
Gross Recognized Derivatives	(93,035,000)	(154,031,000)
Amounts Offset	0	18,060,000
Net Recognized Derivatives	(93,035,000)	(135,971,000)
Other	(4,248,000)	(3,707,000)
Amount Reported on Balance Sheet	(97,283,000)	(139,678,000)
Current Assets
Assets
Gross Recognized Derivatives	24,894,000	37,396,000
Amounts Offset	(18,816,000)	(22,163,000)
Net Recognized Derivatives	6,078,000	15,233,000
Other	157,000	672,000
Amount Reported on Balance Sheet	6,235,000	15,905,000
Investments and Other Assets
Assets
Gross Recognized Derivatives	4,146,000	15,960,000
Amounts Offset	(4,146,000)	(3,854,000)
Net Recognized Derivatives	0	12,106,000
Other	0	0
Amount Reported on Balance Sheet	0	12,106,000
Current Liabilities
Liabilities
Gross Recognized Derivatives	(59,586,000)	(113,560,000)
Amounts Offset	18,816,000	40,223,000
Net Recognized Derivatives	(40,770,000)	(73,337,000)
Other	(4,405,000)	(4,379,000)
Amount Reported on Balance Sheet	(45,175,000)	(77,716,000)
Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(62,489,000)	(93,827,000)
Amounts Offset	4,146,000	3,854,000
Net Recognized Derivatives	(58,343,000)	(89,973,000)
Other	0	0
Amount Reported on Balance Sheet	$ (58,343,000)	$ (89,973,000)

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Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Sep. 30, 2016 USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	$ 122,075
Cash collateral posted	0
Additional cash collateral in the event credit-risk-related contingent features were fully triggered	$ 61,177

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Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)			9 Months Ended
	Oct. 31, 2016 USD ($)	Aug. 18, 2014 USD ($)	Sep. 30, 2016 USD ($) time_period power_plant claim	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		$ 57,400,000
Proceeds from legal settlements			$ 53,900,000
Arizona Public Service Company
Commitments and Contingencies
Maximum insurance against public liability per occurrence for a nuclear incident (up to)			13,400,000,000
Maximum available nuclear liability insurance (up to)			375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program			13,000,000,000
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			$ 18,900,000
Number of VIE lessor trusts			3	3
Maximum potential retrospective assessment per incident of APS			$ 111,100,000
Annual payment limitation with respect to maximum potential retrospective premium assessment			16,600,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde			2,800,000,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment			23,800,000
Collateral assurance provided based on rating triggers			$ 64,000,000
Period to provide collateral assurance based on rating triggers			20 days
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		$ 16,700,000
Number of claims submitted | claim			2
Number of settlement agreement time periods | time_period			2
Proceeds from legal settlements			$ 15,700,000
Subsequent Event | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
Commitments and Contingencies
Litigation settlement amount	$ 11,300,000
Subsequent Event | 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	$ 3,300,000

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Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - Arizona Public Service Company $ in Millions			9 Months Ended
	Aug. 06, 2013 Defendant	Sep. 08, 2011 kV Customer	Sep. 30, 2016 USD ($)
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
Contaminated groundwater wells
Loss Contingencies [Line Items]
Costs related to investigation and study under Superfund site | $			$ 2
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant	24

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Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions					9 Months Ended
	Jul. 06, 2016 guarantee	Jun. 24, 2016	Mar. 16, 2016 USD ($)	May 23, 2013 USD ($)	Sep. 30, 2016 USD ($)
Environmental Matters
Clean power plan, optional extension period					2 years
Four Corners | New Mexico Tax Matter
Environmental Matters
Coal severance surtax, penalty, and interest				$ 30.0
Litigation settlement awarded (against), amount			$ (1.0)
Arizona Public Service Company | Letter of Credit Expiring in 2016 and 2017
Financial Assurances
Outstanding letters of credit					$ 52.0
Arizona Public Service Company | Letters of Credit Expiring in 2017
Financial Assurances
Surety bonds expiring, amount					$ 150.0
Arizona Public Service Company | Four Corners | New Mexico Tax Matter
Environmental Matters
Share of the assessment				12.0
Partial payment of assessment				$ 0.8
Litigation settlement awarded (against), amount			$ (0.8)
4C Acquisition, LLC | Four Corners Units 4 and 5
Environmental Matters
Percentage of share of cost of control					7.00%
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					$ 400.0
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					$ 45.0
Regional Haze Rules | Arizona Public Service Company | Navajo Plant
Environmental Matters
Expected environmental cost					200.0
Regional Haze Rules | Arizona Public Service Company | Cholla
Environmental Matters
Expected environmental cost					100.0
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Navajo Plant
Environmental Matters
Expected environmental cost					1.0
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Cholla
Environmental Matters
Expected environmental cost					8.0
Coal combustion waste | Arizona Public Service Company | Four Corners
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate					15.0
Coal combustion waste | Arizona Public Service Company | Navajo Plant
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate					1.0
Coal combustion waste | Arizona Public Service Company | Navajo Plant | Boron Inclusion on List of Groundwater Constituents
Environmental Matters
Industry litigation, period to complete rulemaking proceeding		3 years
Payment Guarantee
Financial Assurances
Number of parental guarantees | guarantee	2
Minimum | Coal combustion waste | Arizona Public Service Company | Cholla
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate					5.0
Maximum | Coal combustion waste | Arizona Public Service Company | Cholla
Environmental Matters
Site contingency increase in loss exposure not accrued, best estimate					$ 40.0

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Other Income and Other Expense (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other income:
Interest income	$ 65	$ 127	$ 370	$ 422
Investment gains — net	0	0	13	0
Miscellaneous	6	12	2	127
Total other income	71	139	385	549
Other expense:
Non-operating costs	(2,502)	(2,328)	(6,636)	(6,529)
Investment losses — net	(450)	(563)	(1,508)	(1,708)
Miscellaneous	(2,253)	(2,647)	(3,941)	(4,196)
Total other expense	(5,205)	(5,538)	(12,085)	(12,433)
Arizona Public Service Company
Other income:
Interest income	0	32	181	105
Gain on disposition of property	183	(58)	5,504	627
Miscellaneous	384	676	1,239	1,267
Total other income	567	650	6,924	1,999
Other expense:
Non-operating costs	(2,714)	(2,248)	(7,398)	(6,643)
Loss on disposition of property	36	(327)	(1,048)	(934)
Miscellaneous	(1,098)	(1,390)	(4,510)	(4,191)
Total other expense	$ (3,776)	$ (3,965)	$ (12,956)	$ (11,768)

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 263,027	$ 257,116	$ 388,788	$ 396,140
Weighted average common shares outstanding - basic (in shares)	111,416	111,036	111,363	110,984
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units (in shares)	684	580	624	506
Weighted average common shares outstanding — diluted (in shares)	112,100	111,616	111,987	111,490
Net income attributable to common shareholders - basic (in dollars per share)	$ 2.36	$ 2.32	$ 3.49	$ 3.57
Net income attributable to common shareholders - diluted (in dollars per share)	$ 2.35	$ 2.30	$ 3.47	$ 3.55

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Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Assets
Nuclear decommissioning trust	$ 779,753	$ 735,196
Total assets	14,835	30,364
Recurring
Assets
Cash equivalents	40,075
Coal reclamation trust - Cash equivalents (b)	14,749
Derivative instruments, other	(22,798)	(25,345)
Derivative assets	6,235	28,011
Nuclear decommissioning trust, other	345,468	314,622
Nuclear decommissioning trust	779,753	735,196
Total, other	322,670	289,277
Total assets	840,812	763,207
Liabilities
Total, other	18,551	39,698
Derivative liability	(103,518)	(167,689)
Recurring | US commingled equity funds
Assets
Nuclear decommissioning trust, other	340,436	314,957
Nuclear decommissioning trust	340,436	314,957
Recurring | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust, other	5,032	(335)
Nuclear decommissioning trust	5,032	11,925
Recurring | U.S. Treasury
Assets
Nuclear decommissioning trust	101,394	117,245
Recurring | Corporate debt
Assets
Nuclear decommissioning trust	112,923	96,243
Recurring | Mortgage-backed securities
Assets
Nuclear decommissioning trust	112,485	99,065
Recurring | Municipality bonds
Assets
Nuclear decommissioning trust	82,371	72,206
Recurring | Other
Assets
Nuclear decommissioning trust	25,112	23,555
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash equivalents	40,075
Coal reclamation trust - Cash equivalents (b)	14,749
Decommissioning fund investments, gross fair value	101,394	129,505
Gross assets, fair value disclosure	156,218	129,505
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalent funds
Assets
Decommissioning fund investments, gross fair value	0	12,260
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	101,394	117,245
Recurring | Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	14,198	22,992
Decommissioning fund investments, gross fair value	332,891	291,069
Gross assets, fair value disclosure	347,089	314,061
Liabilities
Gross derivative liability	(67,692)	(144,044)
Recurring | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Decommissioning fund investments, gross fair value	112,923	96,243
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	112,485	99,065
Recurring | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Decommissioning fund investments, gross fair value	82,371	72,206
Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets
Decommissioning fund investments, gross fair value	25,112	23,555
Recurring | Significant Unobservable Inputs (a) (Level 3)
Assets
Gross derivative assets	14,835	30,364
Gross assets, fair value disclosure	14,835	30,364
Liabilities
Gross derivative liability	$ (54,377)	$ (63,343)

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Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016 USD ($) $ / MMBTU $ / MWh	Dec. 31, 2015 USD ($) $ / MMBTU $ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 14,835	$ 30,364
Liabilities	54,377	63,343
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	13,726	24,543
Liabilities	$ 36,438	$ 54,679
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	18.84	15.92
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	39.44	40.73
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	29.30	26.86
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 0	$ 0
Liabilities	$ 1,153	$ 5,628
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	30.40	23.87
Electricity price volatilities (as a percent)	86.00%	40.00%
Natural gas price volatilities (as a percent)	42.00%	32.00%
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	30.40	44.13
Electricity price volatilities (as a percent)	86.00%	59.00%
Natural gas price volatilities (as a percent)	42.00%	40.00%
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	30.40	33.91
Electricity price volatilities (as a percent)	86.00%	52.00%
Natural gas price volatilities (as a percent)	42.00%	35.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 1,109	$ 5,821
Liabilities	$ 16,786	$ 3,036
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	2.43	2.18
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	3.22	3.14
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	2.73	2.61

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Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net derivative balance at beginning of period	$ (32,380)	$ (42,945)	$ (32,979)	$ (41,386)
Included in OCI	(10)	(207)	94	(444)
Deferred as a regulatory asset or liability	(13,499)	(5,837)	(21,103)	(10,771)
Settlements	5,424	7,572	11,691	12,424
Transfers into Level 3 from Level 2	1,343	(526)	1,725	(4,494)
Transfers from Level 3 into Level 2	(420)	1,305	1,030	4,033
Net derivative balance at end of period	(39,542)	(40,638)	(39,542)	(40,638)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0	$ 0	$ 0

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Nuclear Decommissioning Trusts (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Nuclear decommissioning trust fund assets
Fair Value	$ 779,753		$ 779,753		$ 735,196
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities			447,419	$ 330,304
Fair value of fixed income securities, summarized by contractual maturities
Total	779,753		779,753		735,196
Arizona Public Service Company
Nuclear decommissioning trust fund assets
Fair Value	779,753		779,753		735,196
Unrealized Gains	197,299		197,299		169,053
Unrealized Losses	(468)		(468)		(2,760)
Net receivables for securities purchases	5,032		5,032
Net payables for securities purchases					(335)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	4,033	$ 1,919	8,753	4,374
Realized losses	(3,345)	(2,106)	(6,481)	(4,156)
Proceeds from the sale of securities	156,825	$ 104,525	447,419	$ 330,304
Fair value of fixed income securities, summarized by contractual maturities
Total	779,753		779,753		735,196
Arizona Public Service Company | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	340,436		340,436		314,957
Unrealized Gains	176,495		176,495		157,098
Unrealized Losses	(3)		(3)		(115)
Fair value of fixed income securities, summarized by contractual maturities
Total	340,436		340,436		314,957
Arizona Public Service Company | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	434,285		434,285		420,574
Unrealized Gains	20,804		20,804		11,955
Unrealized Losses	(465)		(465)		(2,645)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	8,429		8,429
1 year - 5 years	134,200		134,200
5 years - 10 years	102,835		102,835
Greater than 10 years	188,821		188,821
Total	$ 434,285		$ 434,285		$ 420,574

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Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	$ 4,992,135	$ 4,791,319	$ 4,992,135	$ 4,791,319
Total other comprehensive income	1,573	1,610	2,602	4,151
Balance at end of period			4,719,457	4,519,102
AOCI Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(42,146)	(63,990)	(42,146)	(63,990)
Balance at end of period	(43,719)	(65,600)	(44,748)	(68,141)
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	(29)	(151)	(595)	(926)
Amounts reclassified from accumulated other comprehensive loss	798	892	2,564	3,742
Total other comprehensive income	769	741	1,969	2,816
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	0	0	(1,585)	(969)
Amounts reclassified from accumulated other comprehensive loss	804	869	2,218	2,304
Total other comprehensive income	804	869	633	1,335
Arizona Public Service Company
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	5,085,440	4,894,822	5,085,440	4,894,822
Total other comprehensive income	1,568	1,611	2,737	4,293
Balance at end of period			4,814,794	4,629,852
Arizona Public Service Company | AOCI Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(24,360)	(44,040)	(24,360)	(44,040)
Balance at end of period	(25,928)	(45,651)	(27,097)	(48,333)
Arizona Public Service Company | Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	(29)	(151)	(595)	(926)
Amounts reclassified from accumulated other comprehensive loss	798	892	2,564	3,742
Total other comprehensive income	769	741	1,969	2,816
Arizona Public Service Company | Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
OCI (loss) before reclassifications	0	0	(1,521)	(927)
Amounts reclassified from accumulated other comprehensive loss	799	870	2,289	2,404
Total other comprehensive income	$ 799	$ 870	$ 768	$ 1,477

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Asset Retirement Obligations - Roll-Forward (Details) - Arizona Public Service Company - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Change in asset retirement obligations
Asset retirement obligations at the beginning of year		$ 443,576
Changes attributable to:
Accretion expense		19,868
Settlements		(11,891)
Newly incurred liabilities	$ 9,000	18,927
Asset retirement obligations at the end of year	$ 470,480	$ 470,480

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Asset Retirement Obligations - Narrative (Details) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2016 USD ($) turbine_unit	Dec. 31, 2015 USD ($)
Asset Retirement Obligations
Asset retirement obligation, current	$ 11,852	$ 11,852	$ 28,573
Arizona Public Service Company
Asset Retirement Obligations
Newly incurred liabilities	9,000	18,927
Asset retirement obligation, current	11,505	11,505	28,573
Asset retirement obligation	$ 470,480	$ 470,480	$ 443,576
Arizona Public Service Company | Ocotillo Steam Units
Asset Retirement Obligations
Number of constructed turbine units | turbine_unit		5
Newly incurred liabilities		$ 10,000