Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

332K characters. Original on sec.gov · Markdown

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND

FINANCIAL STATEMENT SCHEDULES



	Page

Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)	83
Report of Independent Registered Public Accounting Firm	84
Pinnacle West Consolidated Statements of Income for 2017, 2016 and 2015	86
Pinnacle West Consolidated Statements of Comprehensive Income for 2017, 2016, and 2015	87
Pinnacle West Consolidated Balance Sheets as of December 31, 2017 and 2016	88
Pinnacle West Consolidated Statements of Cash Flows for 2017, 2016 and 2015	90
Pinnacle West Consolidated Statements of Changes in Equity for 2017, 2016 and 2015	91

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)	92
Report of Independent Registered Public Accounting Firm	93
APS Consolidated Statements of Income for 2017, 2016 and 2015	95
APS Consolidated Statements of Comprehensive Income for 2017, 2016 and 2015	96
APS Consolidated Balance Sheets as of December 31, 2017 and 2016	97
APS Consolidated Statements of Cash Flows for 2017, 2016 and 2015	99
APS Consolidated Statements of Changes in Equity for 2017, 2016 and 2015	100

Combined Notes to Consolidated Financial Statements	101
Note 1. Summary of Significant Accounting Policies	101
Note 2. New Accounting Standards	108
Note 3. Regulatory Matters	112
Note 4. Income Taxes	124
Note 5. Lines of Credit and Short-Term Borrowings	128
Note 6. Long-Term Debt and Liquidity Matters	130
Note 7. Retirement Plans and Other Postretirement Benefits	133
Note 8. Leases	141
Note 9. Jointly-Owned Facilities	143
Note 10. Commitments and Contingencies	144
Note 11. Asset Retirement Obligations	152
Note 12. Selected Quarterly Financial Data (Unaudited)	153
Note 13. Fair Value Measurements	154
Note 14. Earnings Per Share	161
Note 15. Stock-Based Compensation	161
Note 16. Derivative Accounting	164
Note 17. Other Income and Other Expense	169
Note 18. Palo Verde Sale Leaseback Variable Interest Entities	169
Note 19. Investments	171
Note 20. Changes in Accumulated Other Comprehensive Loss	172

See Note 12 for the selected quarterly financial data (unaudited) required to be presented in this Item.

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2017. The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

February 23, 2018

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Pinnacle West Capital Corporation

Phoenix, Arizona

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2017, the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 23, 2018

We have served as the Company's auditor since 1932.

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

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



	Year Ended December 31,
	2017			2016			2015

OPERATING REVENUES	$	3,565,296		$	3,498,682		$	3,495,443
OPERATING EXPENSES
Fuel and purchased power	981,301			1,075,510			1,101,298
Operations and maintenance	924,443			911,319			868,377
Depreciation and amortization	534,118			485,829			494,422
Taxes other than income taxes	184,347			166,499			171,812
Other expenses	6,660			3,541			4,932
Total	2,630,869			2,642,698			2,640,841
OPERATING INCOME	934,427			855,984			854,602
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	47,011			42,140			35,215
Other income (Note 17)	4,006			901			621
Other expense (Note 17)	(21,539		)	(15,337		)	(17,823		)
Total	29,478			27,704			18,013
INTEREST EXPENSE
Interest charges	219,796			205,720			194,964
Allowance for borrowed funds used during construction (Note 1)	(22,112		)	(19,970		)	(16,259		)
Total	197,684			185,750			178,705
INCOME BEFORE INCOME TAXES	766,221			697,938			693,910
INCOME TAXES (Note 4)	258,272			236,411			237,720
NET INCOME	507,949			461,527			456,190
Less: Net income attributable to noncontrolling interests (Note 18)	19,493			19,493			18,933
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	488,456		$	442,034		$	437,257

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	111,839			111,409			111,026
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,367			112,046			111,552

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	4.37		$	3.97		$	3.94
Net income attributable to common shareholders — diluted	$	4.35		$	3.95		$	3.92

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)



	Year Ended December 31,
	2017			2016			2015

NET INCOME	$	507,949		$	461,527		$	456,190

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $24, $(585), and $(342) (Note 16)	(35		)	(538		)	(957		)
Reclassification of net realized loss, net of tax benefit of $1,294, $985, and $1,801 (Note 16)	2,225			2,941			4,187
Pension and other postretirement benefits activity, net of tax benefit (expense) of $693, $633, and $(13,302) (Note 7)	(3,370		)	(1,477		)	20,163
Total other comprehensive income (loss)	(1,180		)	926			23,393

COMPREHENSIVE INCOME	506,769			462,453			479,583
Less: Comprehensive income attributable to noncontrolling interests	19,493			19,493			18,933

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	487,276		$	442,960		$	460,650

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2017			2016
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	13,892		$	8,881
Customer and other receivables	305,147			250,491
Accrued unbilled revenues	112,434			107,949
Allowance for doubtful accounts	(2,513		)	(3,037		)
Materials and supplies (at average cost)	264,012			253,979
Fossil fuel (at average cost)	25,258			28,608
Income tax receivable (Note 4)	—			3,751
Assets from risk management activities (Note 16)	1,931			19,694
Deferred fuel and purchased power regulatory asset (Note 3)	75,637			12,465
Other regulatory assets (Note 3)	172,451			94,410
Other current assets	48,039			45,028
Total current assets	1,016,288			822,219
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	51			1
Nuclear decommissioning trust (Notes 13 and 19)	871,000			779,586
Other assets	84,531			69,063
Total investments and other assets	955,582			848,650
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	17,798,061			17,341,888
Accumulated depreciation and amortization	(6,128,535		)	(5,970,100		)
Net	11,669,526			11,371,788
Construction work in progress	1,291,498			1,019,947
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)	109,645			113,515
Intangible assets, net of accumulated amortization of $582,272 and $603,637	257,189			90,022
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202	117,408			119,004
Total property, plant and equipment	13,445,266			12,714,276
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,202,302			1,313,428
Assets for other postretirement benefits (Note 7)	268,978			166,206
Other	130,666			139,474
Total deferred debits	1,601,946			1,619,108
TOTAL ASSETS	$	17,019,082		$	16,004,253

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2017			2016
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	256,442		$	264,631
Accrued taxes (Note 4)	148,946			138,964
Accrued interest	56,397			52,835
Common dividends payable	77,667			72,926
Short-term borrowings (Note 5)	95,400			177,200
Current maturities of long-term debt (Note 6)	82,000			125,000
Customer deposits	70,388			82,520
Liabilities from risk management activities (Note 16)	59,252			25,836
Liabilities for asset retirements (Note 11)	4,745			9,135
Regulatory liabilities (Note 3)	100,086			99,899
Other current liabilities	246,529			244,000
Total current liabilities	1,197,852			1,292,946
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	4,789,713			4,021,785
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	1,690,805			2,945,232
Regulatory liabilities (Notes 1, 3, 4 and 7)	2,452,536			948,916
Liabilities for asset retirements (Note 11)	674,784			615,340
Liabilities for pension benefits (Note 7)	327,300			509,310
Liabilities from risk management activities (Note 16)	37,170			47,238
Customer advances	113,996			88,672
Coal mine reclamation	231,597			221,910
Deferred investment tax credit	205,575			210,162
Unrecognized tax benefits (Note 4)	13,115			10,046
Other	148,909			156,784
Total deferred credits and other	5,895,787			5,753,610
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,816,170 and 111,392,053 issued at respective dates	2,614,805			2,596,030
Treasury stock at cost; 64,463 shares at end of 2017 and 55,317 shares at end of 2016	(5,624		)	(4,133		)
Total common stock	2,609,181			2,591,897
Retained earnings	2,442,511			2,255,547
Accumulated other comprehensive loss (Note 20)	(45,002		)	(43,822		)
Total shareholders’ equity	5,006,690			4,803,622
Noncontrolling interests (Note 18)	129,040			132,290
Total equity	5,135,730			4,935,912
TOTAL LIABILITIES AND EQUITY	$	17,019,082		$	16,004,253

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)



	Year Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	507,949		$	461,527		$	456,190
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	610,629			565,011			571,664
Deferred fuel and purchased power	(48,405		)	(60,303		)	14,997
Deferred fuel and purchased power amortization	(14,767		)	38,152			1,617
Allowance for equity funds used during construction	(47,011		)	(42,140		)	(35,215		)
Deferred income taxes	248,164			206,870			236,819
Deferred investment tax credit	(4,587		)	23,082			8,473
Change in derivative instruments fair value	(373		)	(403		)	(381		)
Stock compensation	20,502			18,883			18,756
Changes in current assets and liabilities:
Customer and other receivables	(93,797		)	(2,489		)	(22,219		)
Accrued unbilled revenues	(4,485		)	(11,709		)	4,293
Materials, supplies and fossil fuel	(6,683		)	(1,491		)	(23,945		)
Income tax receivable	3,751			(3,162		)	2,509
Other current assets	(10,580		)	(23,324		)	3,145
Accounts payable	(23,769		)	(66,917		)	(34,266		)
Accrued taxes	9,982			447			(2,013		)
Other current liabilities	19,154			29,594			603
Change in margin and collateral accounts — assets	(300		)	673			(324		)
Change in margin and collateral accounts — liabilities	(533		)	17,735			22,776
Change in unrecognized tax benefits	5,891			1,628			(10,328		)
Change in long-term regulatory liabilities	45,764			14,682			(20,535		)
Change in other long-term assets	(68,480		)	(60,163		)	2,426
Change in other long-term liabilities	(29,980		)	(82,793		)	(100,715		)
Net cash flow provided by operating activities	1,118,036			1,023,390			1,094,327
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,408,774		)	(1,275,472		)	(1,076,087		)
Contributions in aid of construction	23,708			64,296			46,546
Allowance for borrowed funds used during construction	(22,112		)	(19,970		)	(16,259		)
Proceeds from nuclear decommissioning trust sales	542,246			633,410			478,813
Investment in nuclear decommissioning trust	(544,527		)	(635,691		)	(496,062		)
Other	(19,078		)	(18,651		)	(3,184		)
Net cash flow used for investing activities	(1,428,537		)	(1,252,078		)	(1,066,233		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	848,239			693,151			842,415
Repayment of long-term debt	(125,000		)	(370,430		)	(415,570		)
Short-term borrowings and (repayments) — net	(107,800		)	137,200			(147,400		)
Short-term debt borrowings under revolving credit facility	58,000			40,000			—
Short-term debt repayments under revolving credit facility	(32,000		)	—			—
Dividends paid on common stock	(289,793		)	(274,229		)	(260,027		)
Common stock equity issuance and purchases - net	(13,390		)	(4,867		)	19,373
Distributions to noncontrolling interests	(22,744		)	(22,744		)	(35,002		)
Other	—			—			1
Net cash flow provided by financing activities	315,512			198,081			3,790
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,011			(30,607		)	31,884
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	8,881			39,488			7,604
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	13,892		$	8,881		$	39,488

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

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands, except per share amounts)



	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
Balance, December 31, 2014	110,649,762	$	2,512,970	(78,400	)	$	(3,401	)	$	1,926,065		$	(68,141	)	$	151,609		$	4,519,102

Net income		—				—			437,257			—			18,933			456,190
Other comprehensive income		—				—			—			23,393			—			23,393
Dividends on common stock ($2.44 per share)		—				—			(270,519		)	—			—			(270,519		)
Issuance of common stock	445,640	28,698				—			—			—			—			28,698
Purchase of treasury stock (a)		—		(154,751	)	(10,136		)	—			—			—			(10,136		)
Reissuance of treasury stock for stock-based compensation and other		—		118,121		7,731			—			—			—			7,731
Net capital activities by noncontrolling interests		—				—			—			—			(35,002		)	(35,002		)
Balance, December 31, 2015	111,095,402	2,541,668		(115,030	)	(5,806		)	2,092,803			(44,748		)	135,540			4,719,457

Net income		—				—			442,034			—			19,493			461,527
Other comprehensive income		—				—			—			926			—			926
Dividends on common stock ($2.56 per share)		—				—			(284,765		)	—			—			(284,765		)
Issuance of common stock	296,651	13,982				—			—			—			—			13,982
Purchase of treasury stock (a)		—		(128,105	)	(9,087		)	—			—			—			(9,087		)
Reissuance of treasury stock for stock-based compensation and other		—		187,818		10,760			—			—			—			10,760
Stock compensation cumulative effect adjustments (See Note 15)		40,380				—			5,475			—			—			45,855
Net capital activities by noncontrolling interests		—				—			—			—			(22,743		)	(22,743		)
Balance, December 31, 2016	111,392,053	2,596,030		(55,317	)	(4,133		)	2,255,547			(43,822		)	132,290			4,935,912

Net income		—				—			488,456			—			19,493			507,949
Other comprehensive loss		—				—			—			(1,180		)	—			(1,180		)
Dividends on common stock ($2.70 per share)		—				—			(301,492		)	—			—			(301,492		)
Issuance of common stock	424,117	18,775				—			—			—			—			18,775
Purchase of treasury stock (a)		—		(216,911	)	(17,755		)	—			—			—			(17,755		)
Reissuance of treasury stock for stock-based compensation and other		—		207,765		16,264			—			—			—			16,264
Net capital activities by noncontrolling interests		—				—			—			—			(22,743		)	(22,743		)
Balance, December 31, 2017	111,816,170	$	2,614,805	(64,463	)	$	(5,624	)	$	2,442,511		$	(45,002	)	$	129,040		$	5,135,730


(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.

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(ARIZONA PUBLIC SERVICE COMPANY)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for APS. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2017. The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.

February 23, 2018

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Arizona Public Service Company

Phoenix, Arizona

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiary (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2017, the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Basis for Opinions

Definition and Limitations of Internal Control over Financial Reporting

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 23, 2018

We have served as the Company's auditor since 1932.

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)



	Year Ended December 31,
	2017			2016			2015

ELECTRIC OPERATING REVENUES	$	3,554,139		$	3,489,754		$	3,492,357

OPERATING EXPENSES
Fuel and purchased power	992,744			1,082,625			1,101,298
Operations and maintenance	891,129			879,108			853,135
Depreciation and amortization	532,423			484,909			494,298
Income taxes (Note 4)	275,295			259,353			260,143
Taxes other than income taxes	182,979			165,779			171,499
Total	2,874,570			2,871,774			2,880,373
OPERATING INCOME	679,569			617,980			611,984

OTHER INCOME (DEDUCTIONS)
Income taxes (Note 4)	6,127			13,511			14,302
Allowance for equity funds used during construction (Note 1)	47,011			42,140			35,215
Other income (Note 17)	6,526			8,607			2,834
Other expense (Note 17)	(23,380		)	(17,514		)	(19,019		)
Total	36,284			46,744			33,332

INTEREST EXPENSE
Interest on long-term debt	200,211			189,828			180,123
Interest on short-term borrowings	9,119			7,983			7,376
Debt discount, premium and expense	4,833			4,760			4,793
Allowance for borrowed funds used during construction (Note 1)	(22,112		)	(19,481		)	(16,183		)
Total	192,051			183,090			176,109

NET INCOME	523,802			481,634			469,207

Less: Net income attributable to noncontrolling interests (Note 18)	19,493			19,493			18,933

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	504,309		$	462,141		$	450,274

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)



	Year Ended December 31,
	2017			2016			2015

NET INCOME	$	523,802		$	481,634		$	469,207

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $24, $(585), and $(342) (Note 16)	(35		)	(538		)	(957		)
Reclassification of net realized loss, net of tax benefit of $1,294, $985, and $1,801 (Note 16)	2,225			2,941			4,187
Pension and other postretirement benefits activity, net of tax benefit (expense) of $977, $293, and $(11,776) (Note 7)	(3,750		)	(729		)	18,006
Total other comprehensive income (loss)	(1,560		)	1,674			21,236

COMPREHENSIVE INCOME	522,242			483,308			490,443
Less: Comprehensive income attributable to noncontrolling interests	19,493			19,493			18,933

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	502,749		$	463,815		$	471,510

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2017			2016
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	$	17,654,078		$	17,228,787
Accumulated depreciation and amortization	(6,041,965		)	(5,881,941		)
Net	11,612,113			11,346,846
Construction work in progress	1,266,636			989,497
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)	109,645			113,515
Intangible assets, net of accumulated amortization of $581,135 and $603,637	257,028			89,868
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202	117,408			119,004
Total property, plant and equipment	13,362,830			12,658,730
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 13 and 19)	871,000			779,586
Assets from risk management activities (Note 16)	51			1
Other assets	67,103			48,320
Total investments and other assets	938,154			827,907
CURRENT ASSETS
Cash and cash equivalents	13,851			8,840
Customer and other receivables	292,791			262,611
Accrued unbilled revenues	112,434			107,949
Allowance for doubtful accounts	(2,513		)	(3,037		)
Materials and supplies (at average cost)	262,630			252,777
Fossil fuel (at average cost)	25,258			28,608
Income tax receivable	—			11,174
Assets from risk management activities (Note 16)	1,931			19,694
Deferred fuel and purchased power regulatory asset (Note 3)	75,637			12,465
Other regulatory assets (Note 3)	172,451			94,410
Other current assets	41,055			41,849
Total current assets	995,525			837,340
DEFERRED DEBITS
Regulatory assets (Notes 1, 3, and 4)	1,202,302			1,313,428
Assets for other postretirement benefits (Note 7)	265,139			162,911
Other	129,801			130,859
Total deferred debits	1,597,242			1,607,198
TOTAL ASSETS	$	16,893,751		$	15,931,175

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2017			2016
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,571,696			2,421,696
Retained earnings	2,533,954			2,331,245
Accumulated other comprehensive loss (Note 20)	(26,983		)	(25,423		)
Total shareholder equity	5,256,829			4,905,680
Noncontrolling interests (Note 18)	129,040			132,290
Total equity	5,385,869			5,037,970
Long-term debt less current maturities (Note 6)	4,491,292			4,021,785
Total capitalization	9,877,161			9,059,755
CURRENT LIABILITIES
Short-term borrowings (Note 5)	—			135,500
Current maturities of long-term debt (Note 6)	82,000			—
Accounts payable	247,852			259,161
Accrued taxes (Note 4)	157,349			130,576
Accrued interest	55,533			52,525
Common dividends payable	77,700			72,900
Customer deposits	70,388			82,520
Liabilities from risk management activities (Note 16)	59,252			25,836
Liabilities for asset retirements (Note 11)	4,192			8,703
Regulatory liabilities (Note 3)	100,086			99,899
Other current liabilities	243,922			226,417
Total current liabilities	1,098,274			1,094,037
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	1,742,485			2,999,295
Regulatory liabilities (Notes 1, 3, and 4)	2,452,536			948,916
Liabilities for asset retirements (Note 11)	666,527			607,234
Liabilities for pension benefits (Note 7)	306,542			488,253
Liabilities from risk management activities (Note 16)	37,170			47,238
Customer advances	113,996			88,672
Coal mine reclamation	215,830			206,645
Deferred investment tax credit	205,575			210,162
Unrecognized tax benefits (Note 4)	43,876			37,408
Other	133,779			143,560
Total deferred credits and other	5,918,316			5,777,383
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	16,893,751		$	15,931,175

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)



	Year Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	523,802		$	481,634		$	469,207
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	608,935			564,091			571,540
Deferred fuel and purchased power	(48,405		)	(60,303		)	14,997
Deferred fuel and purchased power amortization	(14,767		)	38,152			1,617
Allowance for equity funds used during construction	(47,011		)	(42,140		)	(35,215		)
Deferred income taxes	249,465			221,167			223,069
Deferred investment tax credit	(4,587		)	23,082			8,473
Change in derivative instruments fair value	(373		)	(403		)	(381		)
Changes in current assets and liabilities:
Customer and other receivables	(68,040		)	(1,601		)	(21,040		)
Accrued unbilled revenues	(4,485		)	(11,709		)	4,293
Materials, supplies and fossil fuel	(6,503		)	(1,454		)	(23,945		)
Income tax receivable	11,174			(14,567		)	—
Other current assets	(6,775		)	(21,640		)	4,498
Accounts payable	(26,561		)	(67,543		)	(34,891		)
Accrued taxes	26,773			(13,912		)	13,378
Other current liabilities	27,912			5,097			(3,718		)
Change in margin and collateral accounts — assets	(300		)	673			(324		)
Change in margin and collateral accounts — liabilities	(533		)	17,735			22,776
Change in long-term regulatory liabilities	45,764			14,682			(20,535		)
Change in unrecognized tax benefits	5,891			1,628			(10,328		)
Change in other long-term assets	(78,540		)	(45,866		)	(813		)
Change in other long-term liabilities	(31,106		)	(76,855		)	(82,628		)
Net cash flow provided by operating activities	1,161,730			1,009,948			1,100,030
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,381,930		)	(1,248,010		)	(1,072,053		)
Contributions in aid of construction	23,708			64,296			46,546
Allowance for borrowed funds used during construction	(22,112		)	(19,481		)	(16,183		)
Proceeds from nuclear decommissioning trust sales	542,246			633,410			478,813
Investment in nuclear decommissioning trust	(544,527		)	(635,691		)	(496,062		)
Other	(18,538		)	(13,865		)	(1,093		)
Net cash flow used for investing activities	(1,401,153		)	(1,219,341		)	(1,060,032		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	549,478			693,151			842,415
Repayment of long-term debt	—			(370,430		)	(415,570		)
Short-term borrowings and (repayments) — net	(135,500		)	135,500			(147,400		)
Dividends paid on common stock	(296,800		)	(281,300		)	(266,900		)
Equity infusion from Pinnacle West	150,000			42,000			—
Noncontrolling interests	(22,744		)	(22,744		)	(35,002		)
Net cash flow provided by (used for) financing activities	244,434			196,177			(22,457		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,011			(13,216		)	17,541
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	8,840			22,056			4,515
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	13,851		$	8,840		$	22,056
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Income taxes, net of refunds	$	(14,098	)	$	26,864		$	14,831
Interest, net of amounts capitalized	184,210			181,809			167,670
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	130,057		$	114,874		$	83,798
Dividends declared but not paid	77,700			72,900			69,400

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

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)



	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount
Balance, December 31, 2014	71,264,947	$	178,162	$	2,379,696	$	1,968,718		$	(48,333	)	$	151,609		$	4,629,852

Net income		—		—		450,274			—			18,933			469,207
Other comprehensive income		—		—		—			21,236			—			21,236
Dividends on common stock		—		—		(270,500		)	—			—			(270,500		)
Other		—		—		1			—			—			1
Net capital activities by noncontrolling interests		—		—		—			—			(35,002		)	(35,002		)
Balance, December 31, 2015	71,264,947	178,162		2,379,696		2,148,493			(27,097		)	135,540			4,814,794

Equity infusion from Pinnacle West		—		42,000		—			—			—			42,000
Net income		—		—		462,141			—			19,493			481,634
Other comprehensive income		—		—		—			1,674			—			1,674
Dividends on common stock		—		—		(284,800		)	—			—			(284,800		)
Other		—		—		—			—			—			—
Stock compensation cumulative effect adjustments (See Note 15)		—		—		5,411			—			—			5,411
Net capital activities by noncontrolling interests		—		—		—			—			(22,743		)	(22,743		)
Balance, December 31, 2016	71,264,947	178,162		2,421,696		2,331,245			(25,423		)	132,290			5,037,970

Equity infusion from Pinnacle West		—		150,000		—			—			—			150,000
Net income		—		—		504,309			—			19,493			523,802
Other comprehensive loss		—		—		—			(1,560		)	—			(1,560		)
Dividends on common stock		—		—		(301,600		)	—			—			(301,600		)
Net capital activities by noncontrolling interests		—		—		—			—			(22,743		)	(22,743		)
Balance, December 31, 2017	71,264,947	$	178,162	$	2,571,696	$	2,533,954		$	(26,983	)	$	129,040		$	5,385,869

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and 4CA. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated.

We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).

Our 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 line items are presented in a more condensed form on the Consolidated Balance Sheets than in the prior year. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on accumulated other comprehensive loss. The following tables show the impacts of the reclassifications of the prior year (previously reported) amounts (dollars in thousands):



Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(39,070	)	$	39,070		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(43,822		)	43,822			—
Accumulated other comprehensive loss	—			(43,822		)	(43,822		)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(20,671	)	$	20,671		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(25,423		)	25,423			—
Accumulated other comprehensive loss	—			(25,423		)	(25,423		)

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with 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.

Regulatory Accounting

APS is regulated by the ACC and FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

See Note 3 for additional information.

Electric Revenues

We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs.

Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.

Property, Plant and Equipment

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:


•	material and labor;


•	contractor costs;


•	capitalized leases;


•	construction overhead costs (where applicable); and


•	allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, 2017 and 2016 Consolidated Balance Sheets is composed of the following (dollars in thousands):



Property, Plant and Equipment:	2017			2016
Generation	$	7,963,998		$	7,874,898
Transmission	2,836,578			2,746,508
Distribution	6,025,856			5,738,801
General plant	971,629			981,681
Plant in service and held for future use	17,798,061			17,341,888
Accumulated depreciation and amortization	(6,128,535		)	(5,970,100		)
Net	11,669,526			11,371,788
Construction work in progress	1,291,498			1,019,947
Palo Verde sale leaseback, net of accumulated depreciation	109,645			113,515
Intangible assets, net of accumulated amortization	257,189			90,022
Nuclear fuel, net of accumulated amortization	117,408			119,004
Total property, plant and equipment	$	13,445,266		$	12,714,276

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 11.

APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.

We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2017 were as follows:

Fossil plant — 21 years;
Nuclear plant — 26 years;
Other generation — 25 years;
Transmission — 38 years;
Distribution — 33 years; and
General plant — 6 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $453 million in 2017, $422 million in 2016, and $430 million in 2015. For the years 2015 through 2017, the depreciation rates ranged from a low of 0.18% to a high of 16.44%. The weighted-average depreciation rate was 2.80% in 2017, 2.66% in 2016, and 2.74% in 2015.

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 11 for further information on Asset Retirement Obligations.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income. Plant

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

AFUDC was calculated by using a composite rate of 6.68% for 2017, 7.17% for 2016, and 8.02% for 2015. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Materials and Supplies

APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

Fair Value Measurements

We account for derivative instruments, investments held in our nuclear decommissioning trust, coal reclamation escrow accounts, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).

Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.

See Note 13 for additional information about fair value measurements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial 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. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. 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 expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Note 16 for additional information about our derivative instruments.

Loss Contingencies and Environmental Liabilities

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 7 for additional information on pension and other postretirement benefits.

Nuclear Fuel

APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero. In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 10 for information on spent nuclear fuel disposal costs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates. We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).

Cash and Cash Equivalents

We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):



	Year ended December 31,
	2017		2016		2015
Cash paid during the period for:
Income taxes, net of refunds	$	2,186	$	9,956	$	6,550
Interest, net of amounts capitalized	189,288		184,462		170,209
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	130,404	$	114,855	$	83,798
Dividends declared but not paid	77,667		72,926		69,363

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $72 million in 2017, $58 million in 2016, and $58 million in 2015. Estimated amortization expense on existing intangible assets over the next five years is $53 million in 2018, $38 million in 2019, $28 million in 2020, $22 million in 2021, and $17 million in 2022. At December 31, 2017, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

El Dorado holds investments in both debt and equity securities. Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).

Our investments in the nuclear decommissioning trust fund, and coal reclamation escrow, are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 2 for new accounting guidance relating to financial instruments including investments in equity securities, effective for us in 2018.

Business Segments

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.

Preferred Stock

At December 31, 2017, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.

New Accounting Standards

ASU 2014-09, Revenue from Contracts with Customers

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 was 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, became effective for us on January 1, 2018. The standard 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 adopted this standard on January 1, 2018 using the modified retrospective transition approach. The adoption of this standard will not have significant impact on our financial statement results. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment the adoption of this guidance does not generally impact the timing of our revenue recognition relating to these customers. The adoption of the new standard will result in expanded revenue related disclosures.

ASU 2016-01, Financial Instruments: Recognition and Measurement

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 standard became effective for us on January 1, 2018. Certain aspects of the standard require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We adopted this standard on a prospective basis on January 1, 2018. The adoption of this standard will not have a significant impact on our financial statement results, as we did not have significant equity investments impacted by this standard.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2016-02, Leases

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 standard 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. In January 2018, additional lease guidance was issued specifically relating to land easements and how entities may elect to account for these arrangements at transition. The new standard, and related amendments, will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition.

We plan on adopting this standard, and related amendments, on January 1, 2019, and are evaluating the transition practical expedients we may elect. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. We expect the adoption of the new guidance will impact our Consolidated Balance Sheets as we will be required to reflect lease assets and lease liabilities relating to certain operating lease arrangements. We are currently evaluating the significance of the expected balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures.

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. The adoption of this guidance will not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. We do not expect the adoption of this guidance will impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents are generally insignificant.

ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard became effective for us on January 1, 2018 using a prospective approach. We adopted this new standard on January 1, 2018, using a prospective approach with no impacts on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard became effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We adopted this standard on January 1, 2018 using a modified retrospective transition approach. The adoption of this guidance did not have a significant impact on our financial statement results.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance became effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. Beginning in the first quarter of 2018, we will present the non-service cost components of net benefit costs in other income instead of operating income. Prior year non-service cost components will also be reclassified from operating income to other income. Upon adoption, we will no longer capitalize a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income. See note 7 for additional information related to our pension plans and other postretirement benefits.

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as we are currently not applying hedge accounting.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the 2017 Tax Cuts and Jobs Act legislation on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Cuts and Jobs Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Cuts and Jobs Act was recognized. We are currently evaluating this new guidance to determine whether we will elect this reclassification adjustment. The adoption of this guidance will not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Cuts and Jobs Act.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested 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 had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%).

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement is an increase of 3.28% (the average annual bill impact for a typical APS residential customer is 4.54%).

Other key provisions of the agreement include the following:


•	an agreement by APS not to file another general retail rate case application before June 1, 2019;


•	an authorized return on common equity of 10.0%;


•	a capital structure comprised of 44.2% debt and 55.8% common equity;


•	a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;


•	a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at Four Corners;


•	a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;


•	an expansion of the PSA to include certain environmental chemical costs and third-party battery storage costs;


•	a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year, and not more than $15 million per year;


•	an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;


•	rate design changes, including:


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


▪	non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;


▪	a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


•	an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS has filed a motion to intervene. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant is requesting that the ACC hold a hearing on her amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS), and if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. APS cannot predict the outcome of this matter.

Prior Rate Case Filing with the Arizona Corporation Commission

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case 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 5-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

In 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.

In December 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 made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed 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 was in operation by the end of 2016. The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

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. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement. On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million. APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program requiring APS to spend $10-$15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.

In September 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 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. On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy reform policies tied to clean energy sources. The proposal would rename the RES to the Clean Resource Energy Standard and Tariff ("CREST"). 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") annually for review by and approval of the ACC. 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 ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. On July 12, 2016, the ACC Commissioners 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. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.

Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:


•	APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;


•	An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;


•	The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);


•	The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

•

The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and


•	The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):



	Twelve Months Ended December 31,
	2017		2016
Beginning balance	$	12,465	$	(9,688	)
Deferred fuel and purchased power costs — current period	48,405		60,303
Amounts refunded/(charged) to customers	14,767		(38,150		)
Ending balance	$	75,637	$	12,465

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh. On November 30, 2017, APS submitted its calculation for the 2018 PSA year beginning February 1, 2018. The current PSA rate is $.004555 per kWh consisting of a forward component of $.002009 per kWh and a historical component of $.002546 per kWh.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, the 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, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 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.

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 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, 2017.

On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans. A transmission customer intervened and protested certain aspects of APS’s filing. FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed. APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 2017.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were first 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. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. 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. DG sales losses are determined from the metered output from the DG units.

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). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its LFCR Adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease over 2017 levels). Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Tax Expense Adjustor Mechanism and FERC Tax Filing. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps. The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit. APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million annually through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction will be effective March 1, 2018.

The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018.

The TEAM expressly applies to APS's retail rates with the exception noted above. The Company expects to make a filing with FERC in the first quarter of 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG 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, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:


•	Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;


•	Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and


•	Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

System Benefits Charge

The 2012 Settlement Agreement provided 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. This adjustment is subsumed within the 2017 Settlement Agreement and its associated revenue requirement.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested 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 September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's 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.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff. As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter.

In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Renewable Energy Ballot Initiative

On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS intends to oppose this effort. We believe the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. We cannot predict the outcome of this matter.

Clean Resource Energy Standard and Tariff

On January 30, 2018, ACC Commissioner Tobin proposed the CREST, which consists of a series of energy reform policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the Integrated Resource Plan process. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. APS cannot predict the outcome of this matter.

Four Corners

SCE-Related Matters. On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general retail 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 included 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 provided 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 $56 million as of December 31, 2017 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

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,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of 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. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS intends to file the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of 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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($105 million as of December 31, 2017), 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. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026.

Navajo Plant

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($99 million as of December 31, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant 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 this interest, 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):



S		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	576,188	$	—	$	711,059
Retired power plant costs	2033	27,402		188,843		9,913		117,591
Income taxes - AFUDC equity	2047	3,828		142,852		6,305		152,118
Deferred fuel and purchased power — mark-to-market (Note 16)	2020	52,100		34,845		—		42,963
Four Corners cost deferral	2024	8,077		48,305		6,689		56,894
Income taxes — investment tax credit basis adjustment	2046	1,066		26,218		2,120		54,356
Lost fixed cost recovery (b)	2018	59,844		—		61,307		—
Palo Verde VIEs (Note 18)	2046	—		19,395		—		18,775
Deferred compensation	2036	—		36,413		—		35,595
Deferred property taxes	2027	8,569		74,926		—		73,200
Loss on reacquired debt	2038	1,637		15,305		1,637		16,942
AG-1 deferral	2022	2,654		8,472		—		5,868
Demand side management (b)	2017	—		—		3,744		—
Tax expense of Medicare subsidy	2024	1,236		7,415		1,513		10,589
Mead-Phoenix transmission line CIAC	2050	332		10,376		332		10,708
Deferred fuel and purchased power (b) (c)	2018	75,637		—		12,465		—
Coal reclamation	2026	1,068		12,396		418		5,182
Other	Various	4,638		353		432		1,588
Total regulatory assets (d)		$	248,088	$	1,202,302	$	106,875	$	1,313,428


(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 OCI and result in lower future revenues. See Note 7 for further discussion.


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


(c)	Subject to a carrying charge.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(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.”

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



		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - Tax Cuts and Jobs Act	(a)	$	—	$	1,520,274	$	—	$	—
Asset retirement obligations	2057	—		332,171		—		279,976
Removal costs	(b)	18,238		209,191		29,899		223,145
Other post retirement benefits	(d)	37,642		151,985		32,662		123,913
Income taxes - deferred investment tax credit	2046	2,164		52,497		4,368		108,827
Income taxes - change in rates	2046	2,573		70,537		1,771		70,898
Spent nuclear fuel	2027	6,924		62,132		—		71,726
Renewable energy standard (c)	2018	23,155		—		26,809		—
Demand side management (c)	2019	3,066		4,921		—		20,472
Sundance maintenance	2030	—		16,897		—		15,287
Deferred gains on utility property	2022	4,423		10,988		2,063		8,895
Four Corners coal reclamation	2038	1,858		18,921		—		18,248
Other	Various	43		2,022		2,327		7,529
Total regulatory liabilities		$	100,086	$	2,452,536	$	99,899	$	948,916

(a)

See Note 4. While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months.


(b)	In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal (see Note 11).


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


(d)	See Note 7.

Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy. The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 22, 2017, the Tax Cuts and Jobs Act ("Tax Act") was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate to 21% effective January 1, 2018. In accordance with generally accepted accounting principles, the effects of this corporate tax rate reduction were recognized for the year ending December 31, 2017. As a result of this rate reduction, the Company has recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017.

In accordance with accounting for regulated companies, the effect of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a regulatory liability of $1.52 billion and a new $377 million deferred tax asset. The company intends to amortize the regulatory liability in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining regulatory life of the related property, and in a manner to be approved by its federal and state regulatory agencies. See Note 3 for more details.

Additionally, as a result of the corporate tax rate reduction, the Company recorded income tax expense of $9.3 million, for the year ended December 31, 2017, to recognize the effect of certain reductions in deferred tax assets, for which the Company did not believe recovery was probable through its revenue requirement.

Several sections of the Tax Cuts and Jobs Act contain technical ambiguities. These ambiguities include certain transition rules regarding the applicability of bonus depreciation to property acquired, or under construction, prior to September 28, 2017 and the continued deductibility of certain executive compensation arrangements in place prior to November 3, 2017. Management has recognized tax positions which it believes are more likely than not to be sustained upon examination based upon its interpretation of this legislation. Clarifying guidance may be issued through additional legislation, Treasury regulations, or other technical guidance, within the next 12 months which may impact the income tax effects of the Tax Act as recorded by the Company. As of December 31, 2017, the Company does not have a reasonable estimate of what the income tax effects of such clarifying guidance may be, if any.

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18). As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Pinnacle West Consolidated									APS Consolidated
	2017			2016			2015			2017			2016			2015
Total unrecognized tax benefits, January 1	$	36,075		$	34,447		$	44,775		$	36,075		$	34,447		$	44,775
Additions for tax positions of the current year	2,937			2,695			2,175			2,937			2,695			2,175
Additions for tax positions of prior years	4,783			886			—			4,783			886			—
Reductions for tax positions of prior years for:
Changes in judgment	(1,829		)	(1,953		)	(10,244		)	(1,829		)	(1,953		)	(10,244		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	—			—			(2,259		)	—			—			(2,259		)
Total unrecognized tax benefits, December 31	$	41,966		$	36,075		$	34,447		$	41,966		$	36,075		$	34,447

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):



	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Tax positions, that if recognized, would decrease our effective tax rate	$	16,373	$	11,313	$	9,523	$	16,373	$	11,313	$	9,523

As of the balance sheet date, the tax year ended December 31, 2014 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2013.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense. The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):



	Pinnacle West Consolidated							APS Consolidated
	2017		2016		2015			2017		2016		2015
Unrecognized tax benefit interest expense/(benefit) recognized	$	577	$	529	$	(161	)	$	577	$	529	$	(161	)

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):



	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Unrecognized tax benefit interest accrued	$	1,910	$	1,333	$	804	$	1,910	$	1,333	$	804

Additionally, as of December 31, 2017, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of income tax expense are as follows (dollars in thousands):



	Pinnacle West Consolidated							APS Consolidated
	Year Ended December 31,							Year Ended December 31,
	2017		2016		2015			2017		2016		2015
Current:
Federal	$	11,624	$	8,630	$	(12,335	)	$	21,512	$	711	$	6,485
State	3,052		1,259		4,763			2,778		4,276		7,813
Total current	14,676		9,889		(7,572		)	24,290		4,987		14,298
Deferred:
Federal	223,729		201,743		221,505			221,078		215,178		208,326
State	19,867		24,779		23,787			23,800		25,677		23,217
Total deferred	243,596		226,522		245,292			244,878		240,855		231,543
Income tax expense	$	258,272	$	236,411	$	237,720		$	269,168	$	245,842	$	245,841

On the APS Consolidated Statements of Income, federal and state income taxes are allocated between operating income and other income.

The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):



	Pinnacle West Consolidated									APS Consolidated
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016			2015
Federal income tax expense at 35% statutory rate	$	268,177		$	244,278		$	242,869		$	277,540		$	254,617		$	250,267
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	14,897			16,311			18,265			17,276			18,750			20,433
Credits and favorable adjustments related to prior years resolved in current year	—			—			(2,169		)	—			—			(1,892		)
Medicare Subsidy Part-D	853			844			837			853			844			837
Stock compensation	(6,659		)	(2,951		)	—			(3,489		)	(1,937		)	—
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	9,348			—			—			9,431			—			—
Allowance for equity funds used during construction (see Note 1)	(12,937		)	(11,724		)	(9,711		)	(12,937		)	(11,724		)	(9,711		)
Palo Verde VIE noncontrolling interest (see Note 18)	(6,823		)	(6,823		)	(6,626		)	(6,823		)	(6,823		)	(6,626		)
Investment tax credit amortization	(6,715		)	(5,887		)	(5,527		)	(6,715		)	(5,887		)	(5,527		)
Other	(1,869		)	2,363			(218		)	(5,968		)	(1,998		)	(1,940		)
Income tax expense	$	258,272		$	236,411		$	237,720		$	269,168		$	245,842		$	245,841

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net deferred income tax liability were as follows (dollars in thousands):



	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2017			2016			2017			2016
DEFERRED TAX ASSETS
Risk management activities	$	25,103		$	26,614		$	25,103		$	26,614
Regulatory liabilities:
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	376,906			—			376,906			—
Asset retirement obligation and removal costs	135,847			200,140			135,847			200,140
Unamortized investment tax credits	54,661			113,195			54,661			113,195
Other postretirement benefits	47,021			60,375			47,021			60,375
Other	37,489			63,311			37,489			63,311
Pension liabilities	83,126			204,436			77,280			194,981
Renewable energy incentives	33,546			56,379			33,546			56,379
Credit and loss carryforwards	53,946			75,944			1,920			1,645
Other	102,432			158,421			108,223			187,453
Total deferred tax assets	950,077			958,815			897,996			904,093
DEFERRED TAX LIABILITIES
Plant-related	(2,220,886		)	(3,297,989		)	(2,220,886		)	(3,297,989		)
Risk management activities	(491		)	(7,594		)	(491		)	(7,594		)
Other postretirement assets	(66,134		)	(63,477		)	(65,733		)	(62,819		)
Regulatory assets:
Allowance for equity funds used during construction	(36,365		)	(61,088		)	(36,365		)	(61,088		)
Deferred fuel and purchased power — mark-to-market	(40,778		)	(21,396		)	(40,778		)	(21,396		)
Pension benefits	(142,848		)	(274,184		)	(142,848		)	(274,184		)
Retired power plant costs (see Note 3)	(53,611		)	(49,166		)	(53,611		)	(49,166		)
Other	(74,423		)	(123,987		)	(74,423		)	(123,987		)
Other	(5,346		)	(5,166		)	(5,346		)	(5,165		)
Total deferred tax liabilities	(2,640,882		)	(3,904,047		)	(2,640,481		)	(3,903,388		)
Deferred income taxes — net	$	(1,690,805	)	$	(2,945,232	)	$	(1,742,485	)	$	(2,999,295	)

As of December 31, 2017, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $79 million, which first begin to expire in 2034, and other federal and state credit carryforwards of $6 million, which first begin to expire in 2031. The credit and loss carryforwards amount above has been reduced by $31 million of unrecognized tax benefits.

Lines of Credit and Short-Term Borrowings

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2017 and 2016 (dollars in thousands):



	December 31, 2017								December 31, 2016
	Pinnacle West			APS		Total			Pinnacle West			APS			Total
Commitments under Credit Facilities	$	325,000		$	1,000,000	$	1,325,000		$	275,000		$	1,000,000		$	1,275,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(95,400		)	—		(95,400		)	(41,700		)	(135,500		)	(177,200		)
Amount of Credit Facilities Available	$	229,600		$	1,000,000	$	1,229,600		$	233,300		$	864,500		$	1,097,800

Weighted-Average Commitment Fees	0.125%			0.100%					0.125%			0.100%

Pinnacle West

At December 31, 2017, Pinnacle West had a $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 December 31, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $29.4 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018. Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At December 31, 2017, Pinnacle West had $66 million outstanding under the facility.

APS

On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022.

At December 31, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in May 2021 and the above-mentioned $500 million facility. 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 December 31, 2017, APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 10 for a discussion of APS's other outstanding letters of credit.

Debt Provisions

On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of 7% of APS’s capitalization, and $500 million (which is required to be used for costs relating to purchases of natural gas and power). This financing order was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. See Note 6 for additional long-term debt provisions.

Long-Term Debt and Liquidity Matters

All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2017 and 2016 (dollars in thousands):



	Maturity	Interest	December 31,
	Dates (a)	Rates	2017			2016
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975		$	35,975
Fixed	2024-2029	1.75%-4.70%	147,150			147,150
Total pollution control bonds			183,125			183,125
Senior unsecured notes	2019-2046	2.20%-8.75%	4,275,000			3,725,000
Term loans	2018-2019	(c)	150,000			150,000
Unamortized discount			(11,288		)	(11,816		)
Unamortized premium			8,049			4,506
Unamortized debt issuance cost			(31,594		)	(29,030		)
Total APS long-term debt			4,573,292			4,021,785
Less current maturities			82,000			—
Total APS long-term debt less current maturities			4,491,292			4,021,785
Pinnacle West
Term loan	2017	(d)	—			125,000
Senior unsecured notes	2020	2.25%	300,000			—
Unamortized discount			(184		)	—
Unamortized debt issuance cost			(1,395		)	—
Total PNW long-term debt			298,421			125,000
Less current maturities			—			125,000
Total PNW long-term debt less current maturities			298,421			—
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	4,789,713		$	4,021,785


(a)	This schedule does not reflect the timing of redemptions that may occur prior to maturities.


(b)	The weighted-average rate for the variable rate pollution control bonds was 1.77% at December 31, 2017 and 0.81% at December 31, 2016.


(c)	The weighted-average interest rate was 2.236% at December 31, 2017, and 1.427% at December 31, 2016.


(d)	The interest rate was 1.520% at December 31, 2016.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):



Year	Consolidated Pinnacle West		Consolidated APS
2018	$	82,000	$	82,000
2019	600,000		600,000
2020	550,000		250,000
2021	—		—
2022	—		—
Thereafter	3,676,125		3,676,125
Total	$	4,908,125	$	4,608,125

Debt Fair Value

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



	As of December 31, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	298,421	$	298,608	$	125,000	$	125,000
APS	4,573,292		5,006,348		4,021,785		4,300,789
Total	$	4,871,713	$	5,304,956	$	4,146,785	$	4,425,789

Credit Facilities and Debt Issuances

Pinnacle West

On November 30, 2017, Pinnacle West issued $300 million of 2.25% unsecured senior notes that mature on November 30, 2020. The net proceeds from the sale were used to repay our $125 million term loan and for general corporate purposes.

APS

On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% senior unsecured notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures.

On September 11, 2017, APS issued $300 million of 2.95% senior unsecured notes that mature on September 15, 2027. The net proceeds from the sale were used to refinance commercial paper and other indebtedness and to replenish cash used to fund capital expenditures.

On November 30, 2017, PNW contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

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 December 31, 2017, the ratio was approximately 50% 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 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.

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. Its total shareholder equity was approximately $5.3 billion, and total capitalization was approximately $10.0 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.0 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2017.

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. See Note 5 for additional short-term debt provisions.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries. These plans provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

On September 30, 2014, Pinnacle West announced plan design changes to the postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement ("HRA"). The Company is providing a subsidy allowing post-65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The 2014 remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income.

Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account. The Company negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, the Company submitted proof of the transfer to the IRS and expects to execute a final Closing Agreement early in 2018. Per the terms of an order from FERC, the Company must also make an informational filing with FERC. The Company made this FERC filing during February 2018. It is the Company’s understanding that completion of these regulatory requirements will then permit access to the approximately $186 million for the sole purpose of paying active union employee medical benefits.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 13 for further discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory liability. In its 2009 retail rate case settlement, APS received approval to defer a

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over three years beginning in July 2012. We amortized approximately $5 million in 2015, $8 million in 2014, $8 million in 2013 and $4 million in 2012.

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 to the regulatory asset or liability) (dollars in thousands):



	Pension									Other Benefits
	2017			2016			2015			2017			2016			2015
Service cost-benefits earned during the period	$	54,858		$	53,792		$	59,627		$	17,119		$	14,993		$	16,827
Interest cost on benefit obligation	129,756			131,647			123,983			29,959			29,721			28,102
Expected return on plan assets	(174,271		)	(173,906		)	(179,231		)	(53,401		)	(36,495		)	(36,855		)
Amortization of:
Prior service cost (credit)	81			527			594			(37,842		)	(37,883		)	(37,968		)
Net actuarial loss	47,900			40,717			31,056			5,118			4,589			4,881
Net periodic benefit cost	$	58,324		$	52,777		$	36,029		$	(39,047	)	$	(25,075	)	$	(25,013	)
Portion of cost charged to expense	$	27,295		$	26,172		$	20,036		$	(18,274	)	$	(12,435	)	$	(10,391	)

See Note 2 for additional information regarding accounting changes relating to ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2017 and 2016 (dollars in thousands):



	Pension						Other Benefits
	2017			2016			2017			2016
Change in Benefit Obligation
Benefit obligation at January 1	$	3,204,462		$	3,033,803		$	716,445		$	647,020
Service cost	54,858			53,792			17,119			14,993
Interest cost	129,756			131,647			29,959			29,721
Benefit payments	(166,342		)	(142,247		)	(30,144		)	(26,231		)
Actuarial loss	171,452			127,467			20,014			50,942
Benefit obligation at December 31	3,394,186			3,204,462			753,393			716,445
Change in Plan Assets
Fair value of plan assets at January 1	2,675,357			2,542,774			882,651			833,017
Actual return on plan assets	428,374			166,408			139,367			63,463
Employer contributions	100,000			100,000			353			819
Benefit payments	(146,704		)	(133,825		)	—			(14,648		)
Fair value of plan assets at December 31	3,057,027			2,675,357			1,022,371			882,651
Funded Status at December 31	$	(337,159	)	$	(529,105	)	$	268,978		$	166,206

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2017 and 2016 (dollars in thousands):



	2017		2016
Projected benefit obligation	$	3,394,186	$	3,204,462
Accumulated benefit obligation	3,227,233		3,049,406
Fair value of plan assets	3,057,027		2,675,357

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2017 and 2016 (dollars in thousands):



	Pension						Other Benefits
	2017			2016			2017		2016
Noncurrent asset	$	—		$	—		$	268,978	$	166,206
Current liability	(9,859		)	(19,795		)	—		—
Noncurrent liability	(327,300		)	(509,310		)	—		—
Net amount recognized	$	(337,159	)	$	(529,105	)	$	268,978	$	166,206

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2017 and 2016 (dollars in thousands):



	Pension						Other Benefits
	2017			2016			2017			2016
Net actuarial loss	$	643,199		$	773,750		$	75,439		$	146,509
Prior service cost (credit)	—			81			(265,575		)	(303,417		)
APS’s portion recorded as a regulatory (asset) liability	(576,188		)	(711,059		)	189,627			156,575
Income tax expense (benefit)	(24,915		)	(24,202		)	853			833
Accumulated other comprehensive loss	$	42,096		$	38,570		$	344		$	500

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2018 (dollars in thousands):



	Pension		Other Benefits
Net actuarial loss	$	28,334	$	—
Prior service credit	—		(37,842		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018	$	28,334	$	(37,842	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:



	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2017		2016		2017		2016		2015
Discount rate – pension	3.65	%	4.08	%	4.08	%	4.37	%	4.02	%
Discount rate – other benefits	3.71	%	4.17	%	4.17	%	4.52	%	4.14	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets - pension	N/A		N/A		6.55	%	6.90	%	6.90	%
Expected long-term return on plan assets - other benefits	N/A		N/A		6.05	%	4.45	%	4.45	%
Initial healthcare cost trend rate (pre-65 participants)	7.00	%	7.00	%	7.00	%	7.00	%	7.00	%
Initial healthcare cost trend rate (post-65 participants)	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate healthcare cost trend rate	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Number of years to ultimate trend rate (pre-65 participants)	8		4		4		4		4

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2018, we are assuming a 6.05% long-term rate of return for pension assets and 5.55% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects on our December 31, 2017 amounts (dollars in thousands):



	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	8,424	$	(5,616	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	9,145		(7,037		)
Effect on the accumulated other postretirement benefit obligation	128,203		(98,143		)

Plan Assets

The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.

The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis.

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other government

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

agencies, U.S. Treasury Futures Contracts, and fixed income debt securities issued by corporations. Long-term fixed income assets may also include interest rate swaps, and other instruments.

Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments include investments in real estate, private equity and various other strategies. The plan may also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds.

Based on the IPS, and given the pension plan's funded status at year-end 2017, the target and actual allocation for the pension plan at December 31, 2017 are as follows:



	Pension
	Target Allocation		Actual Allocation
Long-term fixed income assets	62	%	58	%
Return-generating assets	38	%	42	%
Total	100	%	100	%

The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the Plan's funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:



Asset Class	Target Allocation
Equities in US and other developed markets	18	%
Equities in emerging markets	6	%
Alternative investments	14	%
Total	38	%

The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade.

As of December 31, 2017, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2017:



	Other Benefits
	Actual Allocation
Long-term fixed income assets	67	%
Return-generating assets	33	%
Total	100	%

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. U.S. Treasury Future Contracts are valued using the quoted active market prices from the exchange on which they trade, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2.

Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (NAV) concept or its equivalent. Mutual funds, which includes exchange traded funds (ETFs), are classified as Level 1 and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). The trust's shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets. As of December 31, 2017, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, 2017, approximately $58 million of these commitments have been funded.

The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2017, by asset category, are as follows (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2017
Pension Plan:
Cash and cash equivalents	$	3,830	$	—	$	—	$	3,830
Fixed income securities:
Corporate	—		1,365,194		—		1,365,194
U.S. Treasury	221,291		—		—		221,291
Other (b)	—		100,599		—		100,599
Common stock equities (c)	228,088		—		—		228,088
Mutual funds (d)	233,732		—		—		233,732
Common and collective trusts:
Equities	—		—		408,763		408,763
Real estate	—		—		171,569		171,569
Fixed Income	—		—		90,869		90,869
Partnerships	—		—		133,379		133,379
Short-term investments and other (e)	—		1,208		98,505		99,713
Total	$	686,941	$	1,467,001	$	903,085	$	3,057,027
Other Benefits:
Cash and cash equivalents	$	143	$	—	$	—	$	143
Fixed income securities:
Corporate	—		306,008		—		306,008
U.S. Treasury	336,963		—		—		336,963
Other (b)	—		32,508		—		32,508
Common stock equities (c)	196,153		—		—		196,153
Mutual funds (d)	39,269		—		—		39,269
Common and collective trusts:
Equities	—		—		75,310		75,310
Real estate	—		—		15,422		15,422
Short-term investments and other (e)	11,268		149		9,178		20,595
Total	$	583,796	$	338,665	$	99,910	$	1,022,371


(a)	These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.


(b)	This category consists primarily of debt securities issued by municipalities.


(c)	This category primarily consists of U.S. common stock equities.


(d)	These funds invest in U.S. and international common stock equities.


(e)	This category includes plan receivables and payables.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016, by asset category, are as follows (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2016
Pension Plan:
Cash and cash equivalents	$	13,995	$	—	$	—	$	13,995
Fixed income securities:
Corporate	—		1,210,453		—		1,210,453
U.S. Treasury	112,583		—		—		112,583
Other (b)	—		102,170		—		102,170
Common stock equities (c)	235,109		—		—		235,109
Mutual funds (d)	251,506		—		—		251,506
Common and collective trusts:
Equities	—		—		266,840		266,840
Real estate	—		—		161,449		161,449
Partnerships	—		—		208,915		208,915
Short-term investments and other (e)	—		—		112,337		112,337
Total	$	613,193	$	1,312,623	$	749,541	$	2,675,357
Other Benefits:
Cash and cash equivalents	$	304	$	—	$	—	$	304
Fixed income securities:
Corporate	—		268,193		—		268,193
U.S. Treasury	145,255		—		—		145,255
Other (b)	—		34,506		—		34,506
Common stock equities (c)	243,741		—		—		243,741
Mutual funds (d)	67,418		—		—		67,418
Common and collective trusts:
Equities	—		—		95,814		95,814
Real estate	—		—		14,509		14,509
Partnerships	—		—		3,060		3,060
Short-term investments and other (e)	—		—		9,851		9,851
Total	$	456,718	$	302,699	$	123,234	$	882,651


(a)	These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.


(b)	This category consists primarily of debt securities issued by municipalities.


(c)	This category primarily consists of U.S. common stock equities.


(d)	These funds invest in U.S. and international common stock equities.


(e)	This category includes plan receivables and payables.

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2017, $100 million in 2016, and $100 million in 2015. 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 $250 million during the 2018-2020 period.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2017, 2016 and 2015. We do not expect to make any contributions over the next three years to our other postretirement benefit plans. APS funds its share of the contributions. APS’s share of the pension plan contribution was approximately $100 million in 2017, $100 million in 2016 and $100 million in 2015. APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2017, 2016 and 2015.

Estimated Future Benefit Payments

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):



Year	Pension		Other Benefits
2018	$	175,383	$	31,891
2019	181,902		34,000
2020	191,586		35,658
2021	196,583		37,090
2022	201,463		37,860
Years 2023-2027	1,068,568		191,207

Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2017, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $10 million for 2017, $10 million for 2016, and $9 million for 2015.

Leases

We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. See Note 2 for a discussion of the new lease accounting standard.

Total lease expense recognized in the Consolidated Statements of Income was $18 million in 2017, $16 million in 2016, and $17 million in 2015. APS’s lease expense was $17 million in 2017, $15 million in 2016, and $14 million in 2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands):



Year	Pinnacle West Consolidated		APS
2018	$	13,412	$	13,110
2019	11,054		10,802
2020	9,641		9,392
2021	7,105		6,858
2022	4,609		4,510
Thereafter	55,940		53,605
Total future lease commitments	$	101,761	$	98,277

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. See Note 18 for a discussion of VIEs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Jointly-Owned Facilities

APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2017 (dollars in thousands):



	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,872,104	$	1,092,049	$	24,257
Palo Verde Unit 2 (a)	16.8	%		619,263		364,516		14,672
Palo Verde Common	28.0	%	(b)	726,223		262,065		46,577
Palo Verde Sale Leaseback			(a)	351,050		241,405		—
Four Corners Generating Station	63.0	%		1,196,683		568,304		240,514
Cholla common facilities (c)	50.5	%		180,907		69,633		1,091
Transmission facilities:
ANPP 500kV System	34.0	%	(b)	130,767		46,400		684
Navajo Southern System	27.5	%	(b)	85,299		28,915		180
Palo Verde — Yuma 500kV System	18.1	%	(b)	14,765		6,614		486
Four Corners Switchyards	63.2	%	(b)	66,386		12,605		327
Phoenix — Mead System	17.1	%	(b)	39,383		17,600		41
Palo Verde — Rudd 500kV System	50.0	%		97,600		23,884		245
Morgan — Pinnacle Peak System	64.6	%	(b)	117,721		14,569		1
Round Valley System	50.0	%		515		141		—
Palo Verde — Morgan System	90.9	%	(b)	137,887		3,948		94,350
Hassayampa — North Gila System	80.0	%		142,541		6,953		—
Cholla 500kV Switchyard	85.7	%		5,243		1,312		190
Saguaro 500kV Switchyard	60.0	%		20,473		12,574		—
Kyrene — Knox System	50.0	%		578		297		—


(a)	See Note 18.


(b)	Weighted-average of interests.


(c)	PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.

APS also has a 14% ownership in the Navajo Plant. In the second quarter of 2017, APS’s remaining net book value of its interest was reclassified from property, plant and equipment to a regulatory asset. See “Navajo Plant” in Note 3 for more details.

4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. At December 31, 2017, 4CA had plant in service of $141 million, accumulated depreciation of $83 million and construction work in progress of $25 million.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Commitments and Contingencies

Palo Verde 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 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, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 retail rate case settlement, this regulatory liability is being refunded to customers (see Note 3). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE in the fourth quarter of 2017 in the amount of $9 million (APS's share is $2.6 million). In February 2018, the DOE approved this claim.

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-wide 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 approximately $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $13.0 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $19 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL"). APS is subject to retrospective premium adjustments 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 $24 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 $64.8 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.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2018 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $715 million in 2018; $578 million in 2019; $548 million in 2020; $548 million in 2021; $554 million in 2022; and $6.5 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions. The current coal contracts with take-or-pay provisions have terms expiring through 2031.

The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):



	Years Ended December 31,
	2018		2019		2020		2021		2022		Thereafter
Coal take-or-pay commitments (a)	$	159,997	$	185,365	$	186,632	$	190,607	$	194,678	$	1,750,739


(a)	Total take-or-pay commitments are approximately $2.7 billion. The total net present value of these commitments is approximately $1.9 billion.

APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):



	Year Ended December 31,
	2017		2016		2015
Total purchases	$	165,220	$	160,066	$	211,327

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $40 million in 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; $40 million in 2022; and $370 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Coal Mine Reclamation Obligations

APS and 4CA must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $216 million at December 31, 2017 and $207 million at December 31, 2016. 4CA recorded an obligation for the coal mine final reclamation of approximately $16 million at December 31, 2017 and $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $31 million in 2018; $32 million in 2019; $21 million in 2020; $20 million in 2021; $22 million in 2022; and $191 million thereafter. 4CA expects to make payments for the final mine reclamation as follows: $1 million in 2018; $1 million in 2019; $2 million in 2020; $2 million in 2021; $2 million in 2022; and $16 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

Superfund-Related Matters

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 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 52nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater RI/FS. Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in the summer or fall of 2018. 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, 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, 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. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. We are unable to

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and 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 pollution control requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. EPA approved 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. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is approximately $400 million. In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC had the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. 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 FIP, could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy. 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.

On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

incorporates APS’s compromise approach for compliance with the Regional Haze program. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

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 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.

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.

On December 16, 2016, President Obama signed the WIIN Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover EGUs, including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017 the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017 a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings. While this filing identified certain provisions of the federal CCR regulations that EPA intends to revise, including allowances for risk-based

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

groundwater protection standards for regulated CCR constituents for which no federal maximum contaminant level has been set, it is not clear at this time which specific provisions of the federal CCR rules will be modified, how they will be modified, or when such modification will occur.

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 2 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 APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

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 $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018. If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. 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. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold.

Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of GHG emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal.

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 April 20, 2016, several environmental groups filed a lawsuit against OSM and other 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 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.

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. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

Four Corners Coal Supply Agreement

Arbitration

On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the 2016 Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant. NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million. APS’s share of this amount is approximately $17 million. On September 20, 2017, NTEC amended its Demand for Arbitration removing its request for a declaratory judgment and at this time is only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year. We cannot predict the timing or

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had 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. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction.

The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% interest in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula at December 31, 2017 is approximately $20 million, which is due to 4CA at December 31, 2018. In future years there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements.

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 commodity contract collateral obligations and other transactions. As of December 31, 2017, standby letters of credit totaled $5 million and will expire in 2018. As of December 31, 2017, surety bonds expiring through 2019 totaled $62 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 December 31, 2017. Since July 6, 2016, Pinnacle West has issued four parental guarantees for 4CA relating 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

In 2017, APS received a new decommissioning study for the Navajo Plant. This resulted in an increase to the ARO in the amount of $22 million, an increase in regulatory asset of $2 million and a reduction of the regulatory liability of $20 million.

In 2016, APS recognized an 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 addition, 4CA acquired El Paso's share of Four Corners Units 4 and 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million. In addition, Four Corners spent $16 million in actual decommissioning costs. Finally, in 2016, APS received a new decommissioning study for the Palo Verde Generating Station. This resulted in an increase to the ARO in the amount of $151 million, an increase in plant in service of $131 million, and a reduction of the regulatory liability of $20 million.

The following table shows the change in our asset retirement obligations for 2017 and 2016 (dollars in thousands):



	2017		2016
Asset retirement obligations at the beginning of year	$	624,475	$	443,576
Changes attributable to:
Accretion expense	33,104		26,656
Settlements	—		(15,732		)
Estimated cash flow revisions	21,950		151,046
Newly incurred or acquired obligations	—		18,929
Asset retirement obligations at the end of year	$	679,529	$	624,475

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2017 and 2016 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.



	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,728	$	944,587	$	1,183,322	$	759,659	$	3,565,296
Operations and maintenance	219,976		214,013		224,305		266,149		924,443
Operating income	73,506		304,229		466,082		90,610		934,427
Income taxes	4,211		88,967		144,319		20,775		258,272
Net income	28,185		172,317		280,945		26,502		507,949
Net income attributable to common shareholders	23,312		167,443		276,072		21,629		488,456

Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.21	$	1.50	$	2.47	$	0.19	$	4.37
Net income attributable to common shareholders — Diluted	0.21		1.49		2.46		0.19		4.35



	2016 Quarter Ended								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,167	$	915,394	$	1,166,922	$	739,199	$	3,498,682
Operations and maintenance	243,195		242,279		217,568		208,277		911,319
Operating income	50,162		231,748		451,258		122,816		855,984
Income taxes	1,914		65,742		141,446		27,309		236,411
Net income	9,326		126,182		267,900		58,119		461,527
Net income attributable to common shareholders	4,453		121,308		263,027		53,246		442,034

Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.04	$	1.09	$	2.36	$	0.48	$	3.97
Net income attributable to common shareholders — Diluted	0.04		1.08		2.35		0.47		3.95

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Selected Quarterly Financial Data (Unaudited) - APS

APS's quarterly financial information for 2017 and 2016 is as follows (dollars in thousands):



	2017 Quarter Ended,								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,869	$	942,615	$	1,178,106	$	756,549	$	3,554,139
Operations and maintenance	212,218		208,286		215,264		255,361		891,129
Operating income	65,468		212,790		322,053		79,258		679,569
Net income attributable to common shareholder	23,162		169,108		284,256		27,783		504,309



	2016 Quarter Ended,								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,632	$	909,757	$	1,166,359	$	737,006	$	3,489,754
Operations and maintenance	238,711		233,712		209,366		197,319		879,108
Operating income	48,930		165,684		307,601		95,765		617,980
Net income attributable to common shareholder	7,253		127,188		269,220		58,480		462,141

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.

Level 2 — Other significant observable inputs, including 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).

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, and investments held in our coal reclamation escrow accounts and nuclear decommissioning trust. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 7 for fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

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

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

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Nuclear Decommissioning Trust and Coal Reclamation Escrow

The nuclear decommissioning trust invests in fixed income securities, equity securities, and may hold cash and cash equivalents. The coal reclamation escrow account invests in fixed income instruments and may also hold cash and cash equivalents. See Note 19 for additional discussion about our investment accounts.

The nuclear decommissioning trust's equity security investments 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.

Fixed income securities issued by the U.S. Treasury 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 fixed income 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.

Cash equivalents reported within Level 1 represent investments held in short-term investment exchange-traded mutual funds. These short-term investment accounts invest in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments.

We price investment securities using information provided by our trustees for our nuclear decommissioning trust assets, and provided by our escrow agent for coal reclamation escrow assets. Our trustee and escrow agent use pricing services that utilize the valuation methodologies described above 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 and escrow agent's internal operating controls and valuation processes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at December 31, 2017 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, 2017
Assets
Cash equivalents	$	10,630	$	—		$	—		$	—			$	10,630
Risk management activities — derivative instruments:
Commodity contracts	—		5,683			1,036			(4,737		)	(b)	1,982
Coal reclamation escrow account (c):	455		31,562			—			525				32,542
Nuclear decommissioning trust:
Cash and cash equivalents	7,224		—			—			109			(d)	7,333
U.S. commingled equity funds	—		—			—			417,390			(e)	417,390
Fixed income securities:
U.S. Treasury	127,662		—			—			—				127,662
Corporate debt	—		114,007			—			—				114,007
Mortgage-backed securities	—		111,874			—			—				111,874
Municipal bonds	—		79,049			—			—				79,049
Other	—		13,685			—			—				13,685
Subtotal nuclear decommissioning trust	134,886		318,615			—			417,499				871,000
Total Assets	$	145,971	$	355,860		$	1,036		$	413,287			$	916,154
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(78,646	)	$	(19,292	)	$	1,516		(b)	$	(96,422	)


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


(b)	Represents counterparty netting, margin, and collateral. See Note 16.


(c)	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 Consolidated Balance Sheets. Primarily consists of fixed income municipal bonds.


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


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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 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 December 31, 2016
Assets
Coal reclamation trust (b):	$	14,521	$	—		$	—		$	—			$	14,521
Risk management activities — derivative instruments:
Commodity contracts	—		43,722			11,076			(35,103		)	(c)	19,695
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			353,261			(d)	353,261
Fixed income securities:
Cash and cash equivalent funds	—		—			—			795			(e)	795
U.S. Treasury	95,441		—			—			—				95,441
Corporate debt	—		111,623			—			—				111,623
Mortgage-backed securities	—		115,337			—			—				115,337
Municipal bonds	—		80,997			—			—				80,997
Other	—		22,132			—			—				22,132
Subtotal nuclear decommissioning trust	95,441		330,089			—			354,056				779,586
Total	$	109,962	$	373,811		$	11,076		$	318,953			$	813,802
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(45,641	)	$	(58,482	)	$	31,049		(c)	$	(73,074	)


(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 Consolidated Balance Sheets. Primarily consists of cash equivalents. Presented as Coal reclamation escrow in 2017.


(c)	Represents counterparty netting, margin and collateral. See Note 16.


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


(e)	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. 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).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 December 31, 2017 and December 31, 2016:



	December 31, 2017 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	21	$	15,485	Discounted cash flows	Electricity forward price (per MWh)	$18.51 - $38.75	$	27.89
Natural Gas:
Forward Contracts (a)	1,015		3,807		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.33 - $3.11	$	2.71
Total	$	1,036	$	19,292


(a)	Includes swaps and physical and financial contracts.



	December 31, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	10,648	$	32,042	Discounted cash flows	Electricity forward price (per MWh)	$16.43 - $41.07	$	29.86
Natural Gas:
Forward Contracts (a)	428		26,440		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.32 - $3.60	$	2.81
Total	$	11,076	$	58,482


(a)	Includes swaps and physical and financial contracts.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 years ended December 31, 2017 and 2016 (dollars in thousands):



	Year Ended December 31,
Commodity Contracts	2017			2016
Net derivative balance at beginning of period	$	(47,406	)	$	(32,979	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—
Included in OCI	3			88
Deferred as a regulatory asset or liability	(13,643		)	(37,543		)
Settlements	5,834			15,146
Transfers into Level 3 from Level 2	(10,026		)	1,900
Transfers from Level 3 into Level 2	46,982			5,982
Net derivative balance at end of period	$	(18,256	)	$	(47,406	)
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 6 for our long-term debt fair values.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share amounts):



	2017		2016		2015
Net income attributable to common shareholders	$	488,456	$	442,034	$	437,257
Weighted average common shares outstanding — basic	111,839		111,409		111,026
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	528		637		526
Weighted average common shares outstanding — diluted	112,367		112,046		111,552
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	4.37	$	3.97	$	3.94
Net Income attributable to common shareholders - diluted	$	4.35	$	3.95	$	3.92

Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan authorizes up to 4.6 million common shares to be available for grant. As of December 31, 2017, 2.2 million common shares were available for issuance under the 2012 Plan. During 2017, 2016, and 2015, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation Expense and Activity

During the fourth quarter of 2016, we adopted new stock-based compensation accounting guidance prescribed by ASU 2016-09. Prior to the adoption of this guidance we had certain awards that were accounted for as liability awards due to the ability of the employee to withhold taxes beyond the minimum statutory tax withholding rate. Under the new standard, the tax withholding terms of our awards no longer trigger liability treatment. Accordingly, effective January 1, 2016 certain awards that were previously classified as liability awards are now accounted for as equity awards. The impacts of this accounting change relating to prior years have been applied using a modified retrospective approach, resulting in a $6 million cumulative-effect adjustment, net of income tax expense of $3 million, to increase Retained Earnings as of January 1, 2016. The impacts of this accounting change relating to 2016 resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. The following amounts related to years ended 2017 and 2016 expense and activity include the effects of adopting this new accounting standard; however, expense and activities relating to 2015 reflect the historical accounting treatment. The new standard also requires excess income tax benefits and deficiencies arising from stock based compensation to now be recognized in the period incurred, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. These other provisions of the standard did not have a material impact on our consolidated financial statements.

Compensation cost included in net income for stock-based compensation plans was $21 million in 2017, $19 million in 2016, and $19 million in 2015. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $15 million in 2017, $10 million in 2016, and $7 million in 2015.

As of December 31, 2017, there were approximately $12 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years.

The total fair value of shares vested was $22 million in 2017, $22 million in 2016 and $21 million in 2015.

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2017, 2016 and 2015.



	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2017		2016		2015		2017		2016		2015
Units granted	161,963		141,811		152,651		147,706		166,666		151,430
Weighted-average grant date fair value	$	72.60	$	67.34	$	64.12	$	78.99	$	66.60	$	64.97


(a)	Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.


(b)	Reflects the target payout level.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table is a summary of the status of non-vested awards as of December 31, 2017 and changes during the year.



	Restricted Stock Units, Stock Grants, and Stock Units					Performance Shares
	Shares			Weighted-Average Grant Date Fair Value		Shares (b)		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2017	335,259			$	62.04	312,724		$	65.32
Granted	161,963			72.60		147,706		78.99
Change in performance factor	—			—		18,266		64.97
Vested	(202,327	)		59.19		(164,396	)	63.87
Forfeited (c)	(3,607	)		69.58		(4,798	)	69.77
Nonvested at December 31, 2017	291,288		(a)	69.78		309,502		72.46
Vested Awards Outstanding at December 31, 2017	89,928					164,396


(a)	Includes 133,373 of awards that will be cash settled.


(b)	The nonvested performance shares are reflected at target payout level. The performance metric component increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests.


(c)	We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $4 million, $3 million and $10 million in 2017, 2016 and 2015, respectively. This includes cash used to settle restricted stock units of $4 million, $3 million and $3 million in 2017, 2016 and 2015, respectively. Restricted stock units that are cash settled are classified as liability awards. Share-based liabilities paid relating to performance shares were $16 million in 2015. In 2017 and 2016, performance shares were classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees. Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date. Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West. This award vested on December 31, 2016, because he remained employed with the Company through that date. The Board did increase the number of awards that vested by 33,745 restricted stock units, payable in stock because certain performance requirements were met. In February 2017, 84,362 restricted stock units were released.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company's closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.

Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, or 50% in cash and 50% in stock. Each stock unit is convertible to one share of stock. The stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment, plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock.

Performance Share Awards

Performance share awards are granted to officers and key employees. The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West's total shareholder return ('TSR') in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that recipients would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates. Risks associated with market volatility are managed 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may 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 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 13 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.

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 December 31, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):



		Quantity
Commodity	Unit of Measure	December 31, 2017	December 31, 2016
Power	GWh	583	1,314
Gas	Billion cubic feet	240	194

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 years ended December 31, 2017, 2016 and 2015 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016			2015
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(59	)	$	47		$	(615	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(3,519		)	(3,926		)	(5,988		)


(a)	During the years ended December 31, 2017, 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 $2 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 years ended December 31, 2017, 2016 and 2015 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016		2015
Net Gain (Loss) Recognized in Income	Operating revenues	$	(1,192	)	$	771	$	574
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(87,991		)	25,711		(108,973		)
Total		$	(89,183	)	$	26,482	$	(108,399	)


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

Derivative Instruments in the 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 Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

As of December 31, 2017, we no longer have derivative instruments that are designated as cash flow hedging instruments. As of December 31, 2016, the Consolidated Balance Sheets included $2 million of gross liabilities related to derivative instruments designated as cash flow 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 December 31, 2017 and 2016. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.



As of December 31, 2017: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982

Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)


(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 $3,521 and cash margin provided to counterparties of $300.



As of December 31, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	48,094		$	(28,400	)	$	19,694		$	—		$	19,694
Investments and other assets	6,704			(6,703		)	1			—			1
Total assets	54,798			(35,103		)	19,695			—			19,695

Current liabilities	(50,182		)	28,400			(21,782		)	(4,054		)	(25,836		)
Deferred credits and other	(53,941		)	6,703			(47,238		)	—			(47,238		)
Total liabilities	(104,123		)	35,103			(69,020		)	(4,054		)	(73,074		)
Total	$	(49,325	)	$	—		$	(49,325	)	$	(4,054	)	$	(53,379	)


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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(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 $4,054.

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 December 31, 2017, Pinnacle West has 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 counterparties 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 December 31, 2017 (dollars in thousands):



	December 31, 2017
Aggregate fair value of derivative instruments in a net liability position	$	97,938
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	91,071


(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 $110 million if our debt credit ratings were to fall below investment grade.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2017, 2016 and 2015 (dollars in thousands):



	2017			2016			2015
Other income:
Interest income	$	3,497		$	884		$	493
Miscellaneous	509			17			128
Total other income	$	4,006		$	901		$	621
Other expense:
Non-operating costs	$	(11,749	)	$	(9,235	)	$	(11,292	)
Investment losses — net	(4,113		)	(1,747		)	(2,080		)
Miscellaneous	(5,677		)	(4,355		)	(4,451		)
Total other expense	$	(21,539	)	$	(15,337	)	$	(17,823	)

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2017, 2016 and 2015 (dollars in thousands):



	2017			2016			2015
Other income:
Interest income	$	2,858		$	261		$	163
Gain on disposition of property	2,048			5,745			716
Miscellaneous	1,620			2,601			1,955
Total other income	$	6,526		$	8,607		$	2,834
Other expense:
Non-operating costs (a)	$	(12,395	)	$	(11,034	)	$	(11,648	)
Loss on disposition of property	(5,424		)	(1,246		)	(2,219		)
Miscellaneous	(5,561		)	(5,234		)	(5,152		)
Total other expense	$	(23,380	)	$	(17,514	)	$	(19,019	)


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

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 2018 through 2023, and about $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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 expense, resulting in an increase in net income of $19 million for 2017, 2016 and 2015. The increase in net income is entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Consolidated Balance Sheets at December 31, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):



	December 31, 2017		December 31, 2016
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	109,645	$	113,515
Equity-Noncontrolling interests	129,040		132,290

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

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the 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 $293 million beginning in 2018, and up to $456 million over the lease extension term.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Investments

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts and Coal Reclamation Escrow Accounts. These investments are classified as available for sale securities, and as a result we record the investments at their fair value on our Consolidated Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning and coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The costs of securities sold are determined on the basis of specific identification.

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. 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 December 31, 2017 and December 31, 2016 (dollars in thousands):



	December 31, 2017							December 31, 2016
	Fair Value		Total Unrealized Gains		Total Unrealized Losses			Fair Value		Total Unrealized Gains		Total Unrealized Losses
Equity securities	$	417,390	$	248,623	$	—		$	353,261	$	188,091	$	—
Fixed income securities	446,277		11,537		(2,996		)	425,530		9,820		(4,962		)
Cash and cash equivalents	7,224		—		—			—		—		—
Net receivables (a)	109		—		—			795		—		—
Total	$	871,000	$	260,160	$	(2,996	)	$	779,586	$	197,911	$	(4,962	)


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

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):



	Nuclear Decommissioning
	Year Ended December 31,
	2017			2016			2015
Realized gains	$	21,813		$	11,213		$	5,189
Realized losses	(13,146		)	(10,106		)	(6,225		)
Proceeds from the sale of securities (a)	542,246			633,410			478,813


(a)	Proceeds are reinvested in the trust/account.

Coal Reclamation Escrow Accounts

APS has investments restricted for coal mine reclamation funding related to Four Corners. As of December 31, 2017, APS’s coal reclamation escrow accounts are invested in fixed income securities with a fair value of $30 million. The realized and unrealized gains and losses relating to these fixed income securities was

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

immaterial for the twelve months ended December 31, 2017 and December 31, 2016. The proceeds from the sale of securities for the twelve months ended December 31, 2017 was $4 million. There were no proceeds from the sale of securities for the twelve months ended December 31, 2016. The proceeds are reinvested in the escrow accounts.

4CA also has investments restricted for coal mine reclamation funding relating to Four Corners invested in fixed income securities. The 4CA fixed income investments have a fair value of $2 million as of December 31, 2017. The realized and unrealized gains and losses relating to these fixed income securities was immaterial for the twelve months ended December 31, 2017 and 2016.

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2017 is as follows (dollars in thousands):



	Nuclear Decommissioning Trusts		Escrow Accounts		Total
Less than one year	$	24,668	$	455	$	25,123
1 year – 5 years	100,289		2,494		102,783
5 years – 10 years	129,239		8,615		137,854
Greater than 10 years	192,081		20,453		212,534
Total	$	446,277	$	32,017	$	478,294

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 years ended December 31, 2017 and 2016 (dollars in thousands):



	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(37,593	)		$	(7,155	)		$	(44,748	)
OCI (loss) before reclassifications	(4,509		)		(538		)		(5,047		)
Amounts reclassified from accumulated other comprehensive loss	3,032			(a)	2,941			(b)	5,973
Balance December 31, 2016	(39,070		)		(4,752		)		(43,822		)
OCI (loss) before reclassifications	(6,438		)		(35		)		(6,473		)
Amounts reclassified from accumulated other comprehensive loss	3,068			(a)	2,225			(b)	5,293
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)


(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.


(b)	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 16.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Changes in Accumulated Other Comprehensive Loss - APS

The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2017 and 2016 (dollars in thousands):



	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(19,942	)		$	(7,155	)		$	(27,097	)
OCI (loss) before reclassifications	(3,821		)		(538		)		(4,359		)
Amounts reclassified from accumulated other comprehensive loss	3,092			(a)	2,941			(b)	6,033
Balance December 31, 2016	(20,671		)		(4,752		)		(25,423		)
OCI (loss) before reclassifications	(6,884		)		(35		)		(6,919		)
Amounts reclassified from accumulated other comprehensive loss	3,134			(a)	2,225			(b)	5,359
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)


(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.


(b)	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 16.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)



	Year Ended December 31,
	2017			2016			2015
Operating revenues	$	119		$	370		$	550
Operating expenses	24,298			26,424			12,733
Operating loss	(24,179		)	(26,054		)	(12,183		)
Other
Equity in earnings of subsidiaries	507,495			462,027			446,508
Other expense	(2,715		)	(1,771		)	(3,302		)
Total	504,780			460,256			443,206
Interest expense	5,633			3,151			2,672
Income before income taxes	474,968			431,051			428,351
Income tax benefit	(13,488		)	(10,983		)	(8,906		)
Net income attributable to common shareholders	488,456			442,034			437,257
Other comprehensive income (loss) — attributable to common shareholders	(1,180		)	926			23,393
Total comprehensive income — attributable to common shareholders	$	487,276		$	442,960		$	460,650

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(dollars in thousands)



	December 31,
	2017			2016
ASSETS
Current assets
Cash and cash equivalents	$	41		$	41
Accounts receivable	93,554			81,751
Income tax receivable	19,124			—
Other current assets	267			340
Total current assets	112,986			82,132
Investments and other assets
Investments in subsidiaries	5,465,137			5,084,035
Deferred income taxes	54,352			53,805
Other assets	44,613			38,500
Total investments and other assets	5,564,102			5,176,340
Total Assets	$	5,677,088		$	5,258,472
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	7,638		$	5,421
Accrued taxes	8,927			12,050
Common dividends payable	77,667			72,926
Short-term borrowings	95,400			41,700
Current maturities of long-term debt	—			125,000
Other current liabilities	17,417			31,182
Total current liabilities	207,049			288,279

Long-term debt less current maturities	298,421			—

Pension liabilities	20,758			21,057
Other	15,130			13,224
Total deferred credits and other	35,888			34,281
Common stock equity
Common stock	2,609,181			2,591,897
Accumulated other comprehensive loss	(45,002		)	(43,822		)
Retained earnings	2,442,511			2,255,547
Total Pinnacle West Shareholders’ equity	5,006,690			4,803,622
Noncontrolling interests	129,040			132,290
Total Equity	5,135,730			4,935,912
Total Liabilities and Equity	$	5,677,088		$	5,258,472

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)



	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities
Net income	$	488,456		$	442,034		$	437,257
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(507,495		)	(462,027		)	(446,508		)
Depreciation and amortization	76			85			92
Deferred income taxes	(264		)	(12,402		)	12,967
Accounts receivable	(2,106		)	15,823			11,336
Accounts payable	(11,162		)	10,402			637
Accrued taxes and income tax receivables — net	(22,247		)	20,041			(12,882		)
Dividends received from subsidiaries	296,800			239,300			266,900
Other	15,092			5,514			(6,995		)
Net cash flow provided by operating activities	257,150			258,770			262,804
Cash flows from investing activities
Construction work in progress	—			(18,457		)	(3,462		)
Investments in subsidiaries	(178,027		)	(19,242		)	(3,491		)
Repayments of loans from subsidiaries	2,987			1,026			157
Advances of loans to subsidiaries	(6,388		)	(2,092		)	(1,010		)
Net cash flow used for investing activities	(181,428		)	(38,765		)	(7,806		)
Cash flows from financing activities
Issuance of long-term debt	298,761			—			—
Short-term debt borrowings under revolving credit facility	58,000			40,000			—
Short-term debt repayments under revolving credit facility	(32,000		)	—			—
Commercial paper - net	27,700			1,700			—
Dividends paid on common stock	(289,793		)	(274,229		)	(260,027		)
Repayment of long-term debt	(125,000		)	—			—
Common stock equity issuance - net of purchases	(13,390		)	(4,867		)	19,373
Net cash flow used for financing activities	(75,722		)	(237,396		)	(240,654		)
Net increase (decrease) in cash and cash equivalents	—			(17,391		)	14,344
Cash and cash equivalents at beginning of year	41			17,432			3,088
Cash and cash equivalents at end of year	$	41		$	41		$	17,432

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

PINNACLE WEST CAPITAL CORPORATION

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)



Column A	Column B		Column C				Column D		Column E
			Additions
Description	Balance at beginning of period		Charged to cost and expenses		Charged to other accounts		Deductions		Balance at end of period
Reserve for uncollectibles:
2017	$	3,037	$	6,836	$	—	$	7,360	$	2,513
2016	3,125		4,025		—		4,113		3,037
2015	3,094		4,073		—		4,042		3,125

ARIZONA PUBLIC SERVICE COMPANY

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)



Column A	Column B		Column C				Column D		Column E
			Additions
Description	Balance at beginning of period		Charged to cost and expenses		Charged to other accounts		Deductions		Balance at end of period
Reserve for uncollectibles:
2017	$	3,037	$	6,836	$	—	$	7,360	$	2,513
2016	3,125		4,025		—		4,113		3,037
2015	3,094		4,073		—		4,042		3,125

Previous: Item 7A. QUANTITATIVE AND QUALITATIVE · Next: Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS