Pinnacle West Capital (PNW) 10-K 21 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 14, 2020
Entity Information [Line Items]
Entity Interactive Data Current	Yes
Entity File Number	1-8962
Entity Registrant Name	PINNACLE WEST CAPITAL CORPORATION
Entity Central Index Key	0000764622
Document Type	10-K
Document Quarterly Report	true
Document Period End Date	Dec. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float	$ 10,536,165,750
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		112,439,441
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Tax Identification Number	86-0512431
Entity Address, Address Line One	400 North Fifth Street, P.O. Box 53999
Entity Address, City or Town	Phoenix
Entity Address, State or Province	AZ
Entity Address, Postal Zip Code	85072-3999
City Area Code	(602)
Local Phone Number	250-1000
Trading Symbol	PNW
Security Exchange Name	NYSE
Document Transition Report	false
Entity Incorporation, State or Country Code	AZ
ARIZONA PUBLIC SERVICE COMPANY
Entity Information [Line Items]
Entity Interactive Data Current	Yes
Entity File Number	1-4473
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	0000007286
Document Type	10-K
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float	$ 0
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		71,264,947
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Tax Identification Number	86-0011170
Entity Address, Address Line One	400 North Fifth Street, P.O. Box 53999
Entity Address, City or Town	Phoenix
Entity Address, State or Province	AZ
Entity Address, Postal Zip Code	85072-3999
City Area Code	(602)
Local Phone Number	250-1000
Title of 12(g) Security	Common Stock
Entity Incorporation, State or Country Code	AZ

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
OPERATING REVENUES (NOTE 2)	$ 3,471,209	$ 3,691,247	$ 3,565,296
OPERATING EXPENSES
Fuel and purchased power	1,042,237	1,076,116	981,301
Operations and maintenance	941,616	1,036,744	949,107
Depreciation and amortization	590,929	582,354	534,118
Taxes other than income taxes	218,579	212,849	184,347
Other expenses	5,888	9,497	6,660
Total	2,799,249	2,917,560	2,655,533
Operating loss	671,960	773,687	909,763
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	31,431	52,319	47,011
Pension and other postretirement non-service credits - net (Note 8)	22,989	49,791	24,664
Other income (Note 18)	50,263	24,896	4,006
Other expense (Note 18)	(17,880)	(17,966)	(21,539)
Total	86,803	109,040	54,142
INTEREST EXPENSE
Interest charges	235,251	243,465	219,796
Allowance for borrowed funds used during construction (Note 1)	(18,528)	(25,180)	(22,112)
Total	216,723	218,285	197,684
INCOME BEFORE INCOME TAXES	542,040	664,442	766,221
Income tax benefit	(15,773)	133,902	258,272
NET INCOME	557,813	530,540	507,949
Less: Net income attributable to noncontrolling interests (Note 19)	19,493	19,493	19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 538,320	$ 511,047	$ 488,456
Net effect of dilutive securities:
Weighted Average common shares outstanding — basic (in shares)	112,443	112,129	111,839
Weighted Average common shares outstanding — diluted (in shares)	112,758	112,550	112,367
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 4.79	$ 4.56	$ 4.37
Net income attributable to common shareholders — diluted (in dollars per share)	$ 4.77	$ 4.54	$ 4.35
ARIZONA PUBLIC SERVICE COMPANY
OPERATING REVENUES (NOTE 2)	$ 3,471,209	$ 3,688,342	$ 3,557,652
OPERATING EXPENSES
Fuel and purchased power	1,042,237	1,094,020	992,744
Operations and maintenance	926,716	969,227	917,983
Depreciation and amortization	590,844	580,694	532,423
Taxes other than income taxes	218,540	212,136	183,254
Other expenses	5,888	2,497	6,709
Total	2,784,225	2,858,574	2,633,113
Operating loss	686,984	829,768	924,539
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	31,431	52,319	47,011
Pension and other postretirement non-service credits - net (Note 8)	24,529	51,242	24,371
Other income (Note 18)	46,884	22,746	3,013
Other expense (Note 18)	(12,990)	(15,292)	(13,913)
Total	89,854	111,015	60,482
INTEREST EXPENSE
Interest charges	220,174	231,391	214,163
Allowance for borrowed funds used during construction (Note 1)	(18,528)	(25,180)	(22,112)
Total	201,646	206,211	192,051
INCOME BEFORE INCOME TAXES	575,192	734,572	792,970
Income tax benefit	(9,572)	144,814	269,168
NET INCOME	584,764	589,758	523,802
Less: Net income attributable to noncontrolling interests (Note 19)	19,493	19,493	19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 565,271	$ 570,265	$ 504,309

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
NET INCOME	$ 557,813	$ 530,540	$ 507,949
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	0
Net unrealized loss, net of tax benefit (expense)		(78)	(35)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax	(1,137)
Reclassification of net realized loss, net of tax benefit		1,527	2,225
Pension and other postretirement benefits activity, net of tax (expense) benefit	(10,525)	4,397	(3,370)
Total other comprehensive income (loss)	(9,388)	5,846	(1,180)
COMPREHENSIVE INCOME	548,425	536,386	506,769
Less: Comprehensive income attributable to noncontrolling interests	19,493	19,493	19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	528,932	516,893	487,276
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	584,764	589,758	523,802
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	0
Net unrealized loss, net of tax benefit (expense)		(78)	(35)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax	(1,137)
Reclassification of net realized loss, net of tax benefit		1,527	2,225
Pension and other postretirement benefits activity, net of tax (expense) benefit	(9,552)	3,465	(3,750)
Total other comprehensive income (loss)	(8,415)	4,914	(1,560)
COMPREHENSIVE INCOME	576,349	594,672	522,242
Less: Comprehensive income attributable to noncontrolling interests	19,493	19,493	19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 556,856	$ 575,179	$ 502,749

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net unrealized loss, tax benefit (expense)	$ 0
Net unrealized loss, tax benefit (expense)		$ (78)	$ 24
Reclassification of net realized loss, tax benefit	375
Reclassification of net realized loss, tax benefit		473	1,294
Pension and other postretirement benefits activity, tax benefit (expense)	3,452	(1,585)	693
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized loss, tax benefit (expense)	0
Net unrealized loss, tax benefit (expense)		(78)	24
Reclassification of net realized loss, tax benefit	375
Reclassification of net realized loss, tax benefit		473	1,294
Pension and other postretirement benefits activity, tax benefit (expense)	$ 3,136	$ (1,159)	$ 977

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 10,283	$ 5,766
Customer and other receivables	266,426	267,887
Accrued unbilled revenues	128,165	137,170
Allowance for doubtful accounts	(8,171)	(4,069)
Materials and supplies (at average cost)	331,091	269,065
Fossil fuel (at average cost)	14,829	25,029
Income tax receivable (Note 5)	21,727	0
Assets from risk management activities (Note 17)	515	1,113
Deferred fuel and purchased power regulatory asset (Note 4)	70,137	37,164
Other regulatory assets (Note 4)	133,070	129,738
Other current assets	61,958	56,128
Total current assets	1,030,030	924,991
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 14 and 20)	1,010,775	851,134
Other special use funds (Notes 14 and 20)	245,095	236,101
Other assets	96,953	103,247
Total investments and other assets	1,352,823	1,190,482
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
Plant in service and held for future use	19,836,292	18,736,628
Accumulated depreciation and amortization	(6,637,857)	(6,366,014)
Net	13,198,435	12,370,614
Construction work in progress	808,133	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation of $249,144 and $245,275 (Note 19)	101,906	105,775
Intangible assets, net of accumulated amortization of $652,902 and $591,202	290,564	262,902
Nuclear fuel, net of accumulated amortization of $137,330 and $137,850	123,500	120,217
Total property, plant and equipment	14,522,538	14,029,570
DEFERRED DEBITS
Regulatory assets (Notes 1, 4 and 5)	1,304,073	1,342,941
Operating Lease, Right-of-Use Asset	145,813	0
Assets for other postretirement benefits (Note 8)	90,570	46,906
Other	33,400	129,312
Total deferred debits	1,573,856	1,519,159
Total Assets	18,479,247	17,664,202
CURRENT LIABILITIES
Accounts payable	346,448	277,336
Accrued taxes	144,899	154,819
Accrued interest	53,534	61,107
Common dividends payable	87,982	82,675
Short-term borrowings (Note 6)	114,675	76,400
Current maturities of long-term debt (Note 7)	800,000	500,000
Customer deposits	64,908	91,174
Liabilities from risk management activities (Note 17)	38,946	35,506
Liabilities for asset retirements (Note 12)	11,025	19,842
Operating lease liabilities (Note 9)	12,713	0
Regulatory liabilities (Note 4)	234,912	165,876
Other current liabilities	168,323	184,229
Total current liabilities	2,078,365	1,648,964
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7)	4,832,558	4,638,232
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 5)	1,992,339	1,807,421
Regulatory liabilities (Notes 1, 4, 5 and 8)	2,267,835	2,325,976
Liabilities for asset retirements (Note 12)	646,193	706,703
Liabilities for pension benefits (Note 8)	280,185	443,170
Liabilities from risk management activities (Note 17)	33,186	24,531
Customer advances	215,330	137,153
Coal mine reclamation	165,695	212,785
Deferred investment tax credit	196,468	200,405
Unrecognized tax benefits (Note 5)	6,189	22,517
Operating lease liabilities (Note 9)	51,872	0
Other	159,844	147,640
Total deferred credits and other	6,015,136	6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,540,126 and 112,159,896 issued at respective dates	2,659,561	2,634,265
Treasury stock at cost; 103,546 shares at end of 2019 and 58,135 shares at end of 2018	(9,427)	(4,825)
Total common stock	2,650,134	2,629,440
Retained earnings	2,837,610	2,641,183
Accumulated other comprehensive loss	(57,096)	(47,708)
Total shareholders’ equity	5,430,648	5,222,915
Noncontrolling interests (Note 19)	122,540	125,790
Total equity	5,553,188	5,348,705
Total Liabilities and Equity	18,479,247	17,664,202
ARIZONA PUBLIC SERVICE COMPANY
CURRENT ASSETS
Cash and cash equivalents	10,169	5,707
Customer and other receivables	255,479	257,654
Accrued unbilled revenues	128,165	137,170
Allowance for doubtful accounts	(8,171)	(4,069)
Materials and supplies (at average cost)	331,091	269,065
Fossil fuel (at average cost)	14,829	25,029
Income tax receivable (Note 5)	7,313	0
Assets from risk management activities (Note 17)	515	1,113
Deferred fuel and purchased power regulatory asset (Note 4)	70,137	37,164
Other regulatory assets (Note 4)	133,070	129,738
Other current assets	38,895	35,111
Total current assets	981,492	893,682
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 14 and 20)	1,010,775	851,134
Other special use funds (Notes 14 and 20)	245,095	236,101
Other assets	43,781	40,817
Total investments and other assets	1,299,651	1,128,052
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
Plant in service and held for future use	19,832,805	18,733,142
Accumulated depreciation and amortization	(6,634,597)	(6,362,771)
Net	13,198,208	12,370,371
Construction work in progress	808,133	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation of $249,144 and $245,275 (Note 19)	101,906	105,775
Intangible assets, net of accumulated amortization of $652,902 and $591,202	290,409	262,746
Nuclear fuel, net of accumulated amortization of $137,330 and $137,850	123,500	120,217
Total property, plant and equipment	14,522,156	14,029,171
DEFERRED DEBITS
Regulatory assets (Notes 1, 4 and 5)	1,304,073	1,342,941
Operating Lease, Right-of-Use Asset	144,024	0
Assets for other postretirement benefits (Note 8)	86,736	43,212
Other	32,591	128,265
Total deferred debits	1,567,424	1,514,418
Total Assets	18,370,723	17,565,323
CURRENT LIABILITIES
Accounts payable	338,006	266,277
Accrued taxes	136,328	176,357
Accrued interest	52,619	60,228
Common dividends payable	88,000	82,700
Current maturities of long-term debt (Note 7)	350,000	500,000
Customer deposits	64,908	91,174
Liabilities from risk management activities (Note 17)	38,946	35,506
Liabilities for asset retirements (Note 12)	11,025	19,842
Operating lease liabilities (Note 9)	12,549	0
Regulatory liabilities (Note 4)	234,912	165,876
Other current liabilities	164,736	178,137
Total current liabilities	1,492,029	1,576,097
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7)	4,833,133	4,189,436
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 5)	2,033,096	1,812,664
Regulatory liabilities (Notes 1, 4, 5 and 8)	2,267,835	2,325,976
Liabilities for asset retirements (Note 12)	646,193	706,703
Liabilities for pension benefits (Note 8)	262,243	425,404
Liabilities from risk management activities (Note 17)	33,186	24,531
Customer advances	215,330	137,153
Coal mine reclamation	165,695	212,785
Deferred investment tax credit	196,468	200,405
Unrecognized tax benefits (Note 5)	40,188	41,861
Operating lease liabilities (Note 9)	50,092	0
Other	136,432	125,511
Total deferred credits and other	6,046,758	6,012,993
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Total common stock	178,162	178,162
Additional paid-in capital	2,721,696	2,721,696
Retained earnings	3,011,927	2,788,256
Accumulated other comprehensive loss	(35,522)	(27,107)
Total shareholders’ equity	5,876,263	5,661,007
Noncontrolling interests (Note 19)	122,540	125,790
Total equity	5,998,803	5,786,797
Total capitalization	10,831,936	9,976,233
Total Liabilities and Equity	$ 18,370,723	$ 17,565,323

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
PROPERTY, PLANT AND EQUIPMENT
Accumulated depreciation of Palo Verde sale leaseback	$ 249,144	$ 245,275
Accumulated amortization on intangible assets	647,276	591,202
Accumulated amortization on nuclear fuel	$ 137,330	$ 137,850
EQUITY
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, authorized shares (in shares)	150,000,000	150,000,000
Common stock, issued shares (in shares)	112,540,126	112,159,896
Treasury stock at cost, shares (in shares)	103,546	58,135
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT
Accumulated depreciation of Palo Verde sale leaseback	$ 249,144	$ 245,275
Accumulated amortization on intangible assets	646,142	590,069
Accumulated amortization on nuclear fuel	$ 137,330	$ 137,850

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 557,813	$ 530,540	$ 507,949
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	664,140	650,955	610,629
Deferred fuel and purchased power	(82,481)	(78,277)	(48,405)
Deferred fuel and purchased power amortization	49,508	116,750	(14,767)
Allowance for equity funds used during construction	(31,431)	(52,319)	(47,011)
Deferred income taxes	(1,479)	117,355	248,164
Deferred investment tax credit	(3,938)	(5,170)	(4,587)
Change in derivative instruments fair value	0	0	(373)
Stock compensation	18,376	19,547	20,502
Changes in current assets and liabilities:
Customer and other receivables	(12,789)	37,530	(93,797)
Accrued unbilled revenues	9,005	(24,736)	(4,485)
Materials, supplies and fossil fuel	(51,826)	(6,103)	(6,683)
Income tax receivable	(21,727)	0	3,751
Other current assets	(3,507)	33,844	(10,580)
Accounts payable	50,641	(14,602)	(23,769)
Accrued taxes	(9,920)	6,597	9,982
Other current liabilities	(84,651)	28,174	19,154
Change in margin and collateral accounts — assets	(247)	143	(300)
Change in margin and collateral accounts — liabilities	(125)	(2,211)	(533)
Change in unrecognized tax benefits	2,704	(1,235)	5,891
Change in long-term regulatory liabilities	124,221	(109,284)	45,764
Change in other long-term assets	(82,895)	78,604	(68,480)
Change in other long-term liabilities	(132,666)	(48,958)	(29,980)
Net cash flow provided by operating activities	956,726	1,277,144	1,118,036
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,191,447)	(1,178,169)	(1,408,774)
Contributions in aid of construction	70,693	27,716	23,708
Allowance for borrowed funds used during construction	(18,528)	(25,180)	(22,112)
Proceeds from nuclear decommissioning trust sales and other special use funds	719,034	653,033	542,246
Investment in nuclear decommissioning trust and other special use funds	(722,181)	(672,165)	(544,527)
Other	11,452	1,941	(19,078)
Net cash flow used for investing activities	(1,130,977)	(1,192,824)	(1,428,537)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	1,092,188	445,245	848,239
Repayment of long-term debt	(600,000)	(182,000)	(125,000)
Short-term borrowings and (repayments) — net	54,275	(7,000)	(107,800)
Short-term debt borrowings under revolving credit facility	49,000	45,000	58,000
Short-term debt repayments under revolving credit facility	(65,000)	(57,000)	(32,000)
Dividends paid on common stock	(329,643)	(308,892)	(289,793)
Common stock equity issuance and purchases - net	692	(5,055)	(13,390)
Distributions to noncontrolling interests	(22,744)	(22,744)	(22,744)
Net cash flow provided by (used for) financing activities	178,768	(92,446)	315,512
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,517	(8,126)	5,011
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	5,766	13,892	8,881
CASH AND CASH EQUIVALENTS AT END OF YEAR	10,283	5,766	13,892
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	584,764	589,758	523,802
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	664,055	649,295	608,935
Deferred fuel and purchased power	(82,481)	(78,277)	(48,405)
Deferred fuel and purchased power amortization	49,508	116,750	(14,767)
Allowance for equity funds used during construction	(31,431)	(52,319)	(47,011)
Deferred income taxes	48,367	59,927	249,465
Deferred investment tax credit	(3,938)	(5,170)	(4,587)
Change in derivative instruments fair value	0	0	(373)
Changes in current assets and liabilities:
Customer and other receivables	(12,075)	35,406	(68,040)
Accrued unbilled revenues	9,005	(24,736)	(4,485)
Materials, supplies and fossil fuel	(51,826)	(6,206)	(6,503)
Income tax receivable	(7,313)	0	11,174
Other current assets	(1,461)	31,707	(6,775)
Accounts payable	53,258	(15,608)	(26,561)
Accrued taxes	(40,029)	19,008	26,773
Other current liabilities	(82,138)	25,070	27,912
Change in margin and collateral accounts — assets	(247)	143	(300)
Change in margin and collateral accounts — liabilities	(125)	(2,211)	(533)
Change in unrecognized tax benefits	2,704	(1,235)	5,891
Change in long-term regulatory liabilities	124,221	(109,284)	45,764
Change in other long-term assets	(85,725)	77,952	(78,540)
Change in other long-term liabilities	(129,682)	(55,169)	(31,106)
Net cash flow provided by operating activities	1,007,411	1,254,801	1,161,730
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,191,447)	(1,169,061)	(1,381,930)
Contributions in aid of construction	70,693	27,716	23,708
Allowance for borrowed funds used during construction	(18,528)	(25,180)	(22,112)
Proceeds from nuclear decommissioning trust sales and other special use funds	719,034	653,033	542,246
Investment in nuclear decommissioning trust and other special use funds	(722,181)	(672,165)	(544,527)
Other	6,336	(1,789)	(18,538)
Net cash flow used for investing activities	(1,136,093)	(1,187,446)	(1,401,153)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	1,092,188	295,245	549,478
Repayment of long-term debt	(600,000)	(182,000)	0
Short-term borrowings and (repayments) — net	0	0	(135,500)
Short-term debt borrowings under revolving credit facility	0	25,000	0
Short-term debt repayments under revolving credit facility	0	(25,000)	0
Dividends paid on common stock	(336,300)	(316,000)	(296,800)
Equity infusion from Pinnacle West	0	150,000	150,000
Distributions to noncontrolling interests	(22,744)	(22,744)	(22,744)
Net cash flow provided by (used for) financing activities	133,144	(75,499)	244,434
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,462	(8,144)	5,011
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	5,707	13,851	8,840
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 10,169	$ 5,707	$ 13,851

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands		Total	Common Stock	Treasury Stock	Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANYCommon Stock	ARIZONA PUBLIC SERVICE COMPANYAdditional Paid-In Capital	ARIZONA PUBLIC SERVICE COMPANYRetained Earnings		ARIZONA PUBLIC SERVICE COMPANYAccumulated Other Comprehensive Income (Loss)		ARIZONA PUBLIC SERVICE COMPANYNoncontrolling Interests
Beginning balance at Dec. 31, 2016		$ 4,935,912	$ 2,596,030	$ (4,133)	$ 2,255,547		$ (43,822)		$ 132,290	$ 5,037,970	$ 178,162	$ 2,421,696	$ 2,331,245		$ (25,423)		$ 132,290
Beginning Balance (in shares) at Dec. 31, 2016			111,392,053	55,317							71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		507,949			488,456				19,493	523,802			504,309				19,493
Other comprehensive income (loss)		(1,180)					(1,180)			(1,560)					(1,560)
Dividends on common stock		(301,492)			(301,492)					(301,600)			(301,600)
Issuance of common stock		18,775	$ 18,775
Issuance of common stock (in shares)			424,117
Purchase of treasury stock	[1]	(17,755)		$ (17,755)
Purchase of treasury stock (in shares)	[1]			(216,911)
Reissuance of treasury stock for stock-based compensation and other		16,264		$ 16,264
Reissuance of treasury stock for stock-based compensation and other (in shares)				207,765
Equity infusion from Pinnacle West										150,000		150,000
Capital activities by noncontrolling interests		(22,743)							(22,743)	(22,743)							(22,743)
Ending balance at Dec. 31, 2017		5,135,730	$ 2,614,805	$ (5,624)	2,442,511		(45,002)		129,040	5,385,869	$ 178,162	2,571,696	2,533,954		(26,983)		129,040
Ending Balance (in shares) at Dec. 31, 2017			111,816,170	64,463							71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		530,540			511,047				19,493	589,758			570,265				19,493
Other comprehensive income (loss)		5,846					5,846			4,914					4,914
Dividends on common stock		(320,927)			(320,927)					(321,001)			(321,001)
Issuance of common stock		19,460	$ 19,460
Issuance of common stock (in shares)			343,726
Purchase of treasury stock	[1]	(10,338)		$ (10,338)
Purchase of treasury stock (in shares)	[1]			(129,903)
Reissuance of treasury stock for stock-based compensation and other		11,137		$ 11,137
Reissuance of treasury stock for stock-based compensation and other (in shares)				136,231
Equity infusion from Pinnacle West										150,000		150,000
Capital activities by noncontrolling interests		(22,743)							(22,743)	(22,743)							(22,743)
Reclassification of income tax effects related to new tax reform					8,552	[2]	(8,552)	[2]					5,038	[3]	(5,038)	[3]
Ending balance at Dec. 31, 2018		$ 5,348,705	$ 2,634,265	$ (4,825)	2,641,183		(47,708)		125,790	5,786,797	$ 178,162	2,721,696	2,788,256		(27,107)		125,790
Ending Balance (in shares) at Dec. 31, 2018		112,159,896	112,159,896	58,135							71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		$ 557,813			538,320				19,493	584,764			565,271				19,493
Other comprehensive income (loss)		(9,388)					(9,388)			(8,415)					(8,415)
Dividends on common stock		(341,893)			(341,893)					(341,600)			(341,600)
Issuance of common stock		25,296	$ 25,296
Issuance of common stock (in shares)			380,230
Purchase of treasury stock	[1]	(11,202)		$ (11,202)
Purchase of treasury stock (in shares)	[1]			(121,493)
Reissuance of treasury stock for stock-based compensation and other		6,600		$ 6,600
Reissuance of treasury stock for stock-based compensation and other (in shares)				76,082
Capital activities by noncontrolling interests		(22,743)							(22,743)	(22,743)							(22,743)
Ending balance at Dec. 31, 2019		$ 5,553,188	$ 2,659,561	$ (9,427)	$ 2,837,610		$ (57,096)		$ 122,540	$ 5,998,803	$ 178,162	$ 2,721,696	$ 3,011,927		$ (35,522)		$ 122,540
Ending Balance (in shares) at Dec. 31, 2019		112,540,126	112,540,126	103,546							71,264,947
[1]	Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[2]	In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the "Tax Act") on items within accumulated other comprehensive income to retained earnings.
[3]	In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.

CONSOLIDATED STATEMENTS OF CH_2

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
DIVIDENDS DECLARED PER SHARE (in dollars per share)	$ 3.04	$ 2.87	$ 2.70

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. See Note 11 for more information on 4CA matters. 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 19 for additional information. 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. Accounting Records and Use of Estimates Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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 judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to 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. Management judgments also include assessing the impact of potential Commission-ordered refunds to customers on regulatory liabilities. See Note 4 for additional information. Electric Revenues On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers; accordingly our 2019 and 2018 electric revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed. We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. 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 regulated retail 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 electricity are netted against other contracts to sell electricity. This is called a "book-out" and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale 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. See Notes 2 and 4 for additional information. 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 an estimated write-off factor to 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, 2019 and 2018 Consolidated Balance Sheets is composed of the following (dollars in thousands): Property, Plant and Equipment: 2019 2018 Generation $ 8,916,872 $ 8,285,514 Transmission 3,095,907 3,033,579 Distribution 6,690,697 6,378,345 General plant 1,132,816 1,039,190 Plant in service and held for future use 19,836,292 18,736,628 Accumulated depreciation and amortization (6,637,857 ) (6,366,014 ) Net 13,198,435 12,370,614 Construction work in progress 808,133 1,170,062 Palo Verde sale leaseback, net of accumulated depreciation 101,906 105,775 Intangible assets, net of accumulated amortization 290,564 262,902 Nuclear fuel, net of accumulated amortization 123,500 120,217 Total property, plant and equipment $ 14,522,538 $ 14,029,570 Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West. 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 12 for additional information. APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it is probable it will 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, 2019 were as follows: • Fossil plant — 17 years ; • Nuclear plant — 22 years ; • Other generation — 21 years ; • Transmission — 40 years ; • Distribution — 34 years ; and • General plant — 8 years . Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $522 million in 2019 , $486 million in 2018 , and $453 million in 2017 . For the years 2017 through 2019 , the depreciation rates ranged from a low of 0.18% to a high of 24.49% . The weighted-average depreciation rate was 2.81% in 2019 , 2.81% in 2018 , and 2.80% in 2017 . 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 12 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 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 6.98% for 2019 , 7.03% for 2018 , and 6.68% for 2017 . 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 apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of 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 7 for additional information. 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 14 for additional information about fair value measurements. 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 17 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 another 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 8 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 now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 11 for information on spent nuclear fuel disposal costs. 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 5 for additional discussion. Cash and Cash Equivalents We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition. The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands): Year ended December 31, 2019 2018 2017 Cash paid during the period for: Income taxes, net of refunds $ 12,535 $ 21,173 $ 2,186 Interest, net of amounts capitalized 218,664 208,479 189,288 Significant non-cash investing and financing activities: Accrued capital expenditures $ 141,297 $ 132,620 $ 130,404 Dividends declared but not paid 87,982 82,675 77,667 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 11,262 — — Sale of 4CA 7% interest in Four Corners — 68,907 — The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands): Year ended December 31, 2019 2018 2017 Cash paid (received) during the period for: Income taxes, net of refunds $ (15,042 ) $ 77,942 $ (14,098 ) Interest, net of amounts capitalized 204,261 196,419 184,210 Significant non-cash investing and financing activities: Accrued capital expenditures $ 141,297 $ 132,620 $ 130,057 Dividends declared but not paid 88,000 82,700 77,700 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 11,262 — — 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 $66 million in 2019 , $68 million in 2018 , and $72 million in 2017 . Estimated amortization expense on existing intangible assets over the next five years is $68 million in 2020, $52 million in 2021, $41 million in 2022, $32 million in 2023, and $22 million in 2024. At December 31, 2019 , the weighted-average remaining amortization period for intangible assets was 8 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 measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence). Bright Canyon holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence). Our investments in the nuclear decommissioning trusts, coal reclamation escrow account and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 14 and 20 for more information on these investments. 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, 2019 , 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.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue	Revenue Sources of Revenue The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands): Year Ended December 31, Year Ended December 31, 2019 2018 Retail Electric Service Residential $ 1,761,122 $ 1,867,370 Non-Residential 1,509,514 1,628,891 Wholesale Energy Sales 121,805 109,198 Transmission Services for Others 62,460 60,261 Other Sources 16,308 25,527 Total Operating Revenues $ 3,471,209 $ 3,691,247 Retail Electric Revenue. Pinnacle West's retail electric revenue is generated by our wholly owned regulated subsidiary APS's sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell generation into the wholesale markets that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC. Revenue Activities Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the year ended December 31, 2019 and 2018 were $3,415 million and $3,644 million , respectively. We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the year ended December 31, 2019 and 2018 , our revenues that do not qualify as revenue from contracts with customers were $56 million and $47 million , respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms. Contract Assets and Liabilities from Contracts with Customers There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Consolidated Balance Sheets as of December 31, 2019 and 2018

New Accounting Standards

New Accounting Standards	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	New Accounting Standards Standards Adopted in 2019 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 requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially 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. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 9 for additional information. ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract In August 2018, a new accounting standard was issued that clarifies how customers in a cloud computing service arrangement should account for implementation costs associated with the arrangement. To determine which implementation costs should be capitalized, the new guidance aligns the accounting with existing guidance pertaining to internal-use software. As a result of this new standard, certain cloud computing service arrangement implementation costs will now be subject to capitalization and amortized on a straight-line basis over the cloud computing service arrangement term. The new standard was effective for us on January 1, 2020, with early application permitted, and may have been applied using either a retrospective or prospective transition approach. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements. Standard Adopted in 2020 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 requires 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. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were 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 adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses, these changes did not have a material impact on our financial statements.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Regulatory Matters	Regulatory Matters 2019 Retail Rate Case Filing with the Arizona Corporation Commission On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates of $69 million . This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ("SCR") project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total revenue increase in APS's application is $184 million . The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4% ). The principal provisions of APS's application are: • a test year comprised of twelve months ended June 30, 2019, adjusted as described below; • an original cost rate base of $8.87 billion , which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits; • the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 45.3 % 4.10 % Common stock equity 54.7 % 10.15 % Weighted-average cost of capital 7.41 % • a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law; • authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated; • a number of proposed rate and program changes for residential customers, including: ▪ a super off-peak period during the winter months for APS’s time-of-use with demand rates; ▪ additional $1.25 million in funding for APS's limited-income crisis bill program; and ▪ a flat bill/subscription rate pilot program; • proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers; • recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and • continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see "Navajo Plant" below). APS requested that the increase become effective December 1, 2020. The hearing for this rate case is currently scheduled to begin in July 2020. APS cannot predict the outcome of its request. 2016 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. 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 was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 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 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 energy 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 in capital costs, and not more than $15 million per year in capital costs; • 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 • 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 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 requested that the ACC hold a hearing on the 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. The ACC held a hearing on this matter beginning in September 2018 and the hearing was concluded on October 1, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC reconsidered the matter and adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint. On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision. Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year and file a report by May 3, 2019. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision. On April 23, 2019, the ACC Staff indicated that they would need additional time beyond May 3, 2019 to file the requested report. On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following: • APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year; • until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month; • APS customers can switch rate plans during an open enrollment period of six months; • APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans; • APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates; • APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and • APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage. APS cannot predict the outcome or impact of the rate case filed on October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they will have a material impact on its financial position, results of operations or cash flows. 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 five -year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES. 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 was 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. 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 authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, 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. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan including a waiver of the distributed energy requirements for the 2018 implementation year. On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million . APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year. On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million . APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. The ACC has not yet ruled on the 2020 RES Implementation Plan. On July 2, 2019, ACC Staff issued draft rules, which propose a RES goal of 45% of retail energy served be renewables by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035. The draft rules would also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. See "Energy Modernization Plan" below for more information. On January 8, 2020, an ACC commissioner proposed replacing the current RES standard with a new standard ("KREST II"). KREST II sets a RES goal of 50% of retail energy to be served by renewables by 2028, 100% zero carbon resources by 2045, and a 35% energy efficiency resource standard by 2030 with a 10% demand response carve out. APS cannot predict the outcome of this matter. Demand Side Management Adjustor Charge . The ACC EES requires APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. Verified energy savings from APS's resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism (see below for discussion of the LFCR). 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 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 . The ACC has not yet ruled on the APS 2018 amended DSM Plan. On December 31, 2018, APS filed its 2019 DSM Plan, which requests a budget of $34.1 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan. On December 31, 2019, APS filed its 2020 DSM Plan, which requests a budget of $51.9 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addresses all components of the 2018 and 2019 DSM plans, which enables the ACC to review the 2020 DSM Plan only. The ACC has not yet ruled on the APS 2020 DSM Plan. Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily 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 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 for 2019 and 2018 (dollars in thousands): Twelve Months Ended 2019 2018 Beginning balance $ 37,164 $ 75,637 Deferred fuel and purchased power costs — current period 82,481 78,277 Amounts charged to customers (49,508 ) (116,750 ) Ending balance $ 70,137 $ 37,164 The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a Forward Component of $0.002009 per kWh and a Historical Component of $0.002546 per kWh. This represented a $0.004 per kWh increase over the August 19, 2017 PSA, the maximum permitted under the Plan of Administration for the PSA. This left $16.4 million of 2017 fuel and purchased power costs above this annual cap. These costs rolled over into the following year and were reflected in the 2019 reset of the PSA. The PSA rate for the PSA year beginning February 1, 2019 is $0.001658 per kWh, consisting of a Forward Component of $0.000536 per kWh and a Historical Component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018. On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $( 0.000456 ) per kWh and consisted of a Forward Component of $( 0.002086 ) per kWh and a Historical Component of $ 0.001630 per kWh. The 2020 PSA rate is a $ 0.002115 per kWh decrease compared to the 2019 PSA year. These rates went into effect as filed on February 1, 2020. On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA. This application is pending with the ACC. APS cannot predict the outcome of this matter. Environmental Improvement Surcharge ("EIS"). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. A filing is made on or before February 1st for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC. There is an overall cap of $0.0005 per kWh (approximately $13 - 14 million per year). APS’s February 1, 2020 application requested an increase in the charge to $8.75 million , or $2.0 million over the charge in effect for the 2019-2020 rate effective year. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters . In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow 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 settlement agreement entered into in 2012 regarding APS's rate case ("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. On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Act beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. Effective June 1, 2018, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 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, 2018. Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $4.9 million for the twelve-month period beginning June 1, 2019 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, 2019. 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 kWhs 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. On February 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million . On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. On February 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $26.6 million (a $9.6 million decrease from previous levels). APS cannot predict the outcome or timing of the ACC’s consideration of this filing. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the delay in implementation does not have an adverse effect on APS. Tax Expense Adjustor Mechanism. 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. The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the 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 that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit ("TEAM Phase I"). On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018. The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company. On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("TEAM Phase II"). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the final billing cycle of March 2020. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern. On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period consistent with IRS normalization rules (“TEAM Phase III”). On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which will provide an additional benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits related to the amortization of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case filing. 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 decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC . 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 most recent five-year rolling average price that APS pays for utility-scale solar projects, 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 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 September 1, 2017, 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 ye

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	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 Consolidated 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. The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company 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 was substantially offset by a net regulatory liability. Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company's proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. As of December 31, 2019, the Company has recorded $57 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5 -year period with amortization to retroactively begin as of January 1, 2018. As a result, in the fourth quarter of 2019, the Company has recorded $62 million of income tax benefit related to amortization of these depreciation related liabilities. See Note 4 for more details. In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018. However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018. Along with the September 2019 final regulations, U.S. Treasury also issued new proposed regulations which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The proposed regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 would continue to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. During the third quarter of 2019, as a result of the clarification provided by these proposed regulations, the Company recorded additional deferred tax liabilities of approximately $56 million related to bonus depreciation benefits claimed on the Company’s 2018 tax return. 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. 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. See Note 19 for additional details related to the Palo Verde sale leaseback VIEs. 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): Pinnacle West Consolidated APS Consolidated 2019 2018 2017 2019 2018 2017 Total unrecognized tax benefits, January 1 $ 40,731 $ 41,966 $ 36,075 $ 40,731 $ 41,966 $ 36,075 Additions for tax positions of the current year 3,373 3,436 2,937 3,373 3,436 2,937 Additions for tax positions of prior years 1,843 2,696 4,783 1,843 2,696 4,783 Reductions for tax positions of prior years for: Changes in judgment (2,078 ) (1,764 ) (1,829 ) (2,078 ) (1,764 ) (1,829 ) Settlements with taxing authorities — — — — — — Lapses of applicable statute of limitations (434 ) (5,603 ) — (434 ) (5,603 ) — Total unrecognized tax benefits, December 31 $ 43,435 $ 40,731 $ 41,966 $ 43,435 $ 40,731 $ 41,966 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 2019 2018 2017 2019 2018 2017 Tax positions, that if recognized, would decrease our effective tax rate $ 22,813 $ 19,504 $ 16,373 $ 22,813 $ 19,504 $ 16,373 As of the balance sheet date, the tax year ended December 31, 2016 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 2015. 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 2019 2018 2017 2019 2018 2017 Unrecognized tax benefit interest expense/(benefit) recognized $ 459 $ (780 ) $ 577 $ 459 $ (780 ) $ 577 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 2019 2018 2017 2019 2018 2017 Unrecognized tax benefit interest accrued $ 1,589 $ 1,130 $ 1,910 $ 1,589 $ 1,130 $ 1,910 Additionally, as of December 31, 2019 , 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. 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, 2019 2018 2017 2019 2018 2017 Current: Federal $ (13,551 ) $ 18,375 $ 11,624 $ (54,697 ) $ 88,180 $ 21,512 State 3,195 3,342 3,052 695 1,877 2,778 Total current (10,356 ) 21,717 14,676 (54,002 ) 90,057 24,290 Deferred: Federal (14,982 ) 94,721 223,729 29,321 32,436 221,078 State 9,565 17,464 19,867 15,109 22,321 23,800 Total deferred (5,417 ) 112,185 243,596 44,430 54,757 244,878 Income tax expense/(benefit) $ (15,773 ) $ 133,902 $ 258,272 $ (9,572 ) $ 144,814 $ 269,168 The following chart compares pretax income at the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to income tax expense (dollars in thousands): Pinnacle West Consolidated APS Consolidated Year Ended December 31, Year Ended December 31, 2019 2018 2017 2019 2018 2017 Federal income tax expense at statutory rate $ 113,828 $ 139,533 $ 268,177 $ 120,790 $ 154,260 $ 277,540 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 18,599 23,115 21,380 19,267 24,531 22,329 State income tax credits net of federal income tax benefit (8,519 ) (6,704 ) (6,483 ) (6,781 ) (5,440 ) (5,053 ) Nondeductible expenditures associated with ballot initiative — 7,879 — — — — Stock compensation (2,252 ) (1,804 ) (6,659 ) (1,054 ) (780 ) (3,489 ) Excess deferred income taxes - Tax Cuts and Jobs Act (124,082 ) (6,725 ) 9,348 (124,082 ) (4,715 ) 9,431 Allowance for equity funds used during construction (see Note 1) (2,476 ) (7,231 ) (12,937 ) (2,476 ) (7,231 ) (12,937 ) Palo Verde VIE noncontrolling interest (see Note 19) (4,094 ) (4,094 ) (6,823 ) (4,094 ) (4,094 ) (6,823 ) Investment tax credit amortization (6,851 ) (6,742 ) (6,715 ) (6,851 ) (6,742 ) (6,715 ) Other 74 (3,325 ) (1,016 ) (4,291 ) (4,975 ) (5,115 ) Income tax expense/(benefit) $ (15,773 ) $ 133,902 $ 258,272 $ (9,572 ) $ 144,814 $ 269,168 The components of the net deferred income tax liability were as follows (dollars in thousands): Pinnacle West Consolidated APS Consolidated December 31, December 31, 2019 2018 2019 2018 DEFERRED TAX ASSETS Risk management activities $ 17,552 $ 15,785 $ 17,552 $ 15,785 Regulatory liabilities: Excess deferred income taxes - Tax Cuts and Jobs Act 335,877 376,869 335,877 376,869 Asset retirement obligation and removal costs 143,011 117,201 143,011 117,201 Unamortized investment tax credits 52,236 53,284 52,236 53,284 Other postretirement benefits 43,841 40,532 43,841 40,532 Other 52,382 40,380 52,382 40,380 Pension liabilities 73,210 112,019 67,976 107,009 Coal reclamation liabilities 40,837 47,508 40,837 47,508 Renewable energy incentives 28,066 30,779 28,066 30,779 Credit and loss carryforwards 54,795 1,755 10,992 — Other 63,102 58,820 70,948 59,919 Total deferred tax assets 904,909 894,932 863,718 889,266 DEFERRED TAX LIABILITIES Plant-related (2,448,458 ) (2,277,724 ) (2,448,458 ) (2,277,724 ) Risk management activities (27 ) (237 ) (27 ) (237 ) Other postretirement assets and other special use funds (66,399 ) (57,697 ) (65,965 ) (57,274 ) Regulatory assets: Allowance for equity funds used during construction (40,023 ) (39,086 ) (40,023 ) (39,086 ) Deferred fuel and purchased power (35,162 ) (23,086 ) (35,162 ) (23,086 ) Pension benefits (163,339 ) (181,504 ) (163,339 ) (181,504 ) Retired power plant costs (see Note 4) (42,228 ) (48,348 ) (42,228 ) (48,348 ) Other (82,722 ) (72,096 ) (82,722 ) (72,096 ) Other (18,890 ) (2,575 ) (18,890 ) (2,575 ) Total deferred tax liabilities (2,897,248 ) (2,702,353 ) (2,896,814 ) (2,701,930 ) Deferred income taxes — net $ (1,992,339 ) $ (1,807,421 ) $ (2,033,096 ) $ (1,812,664 ) As of December 31, 2019 , the deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $62 million , which first begin to expire in 2036, state credit carryforwards net of federal benefit of $23 million , which first begin to expire in 2023, and other federal carryforwards of $9 million . The credit and loss carryforwards amount above has been reduced by $39 million of unrecognized tax benefits.

Lines of Credit and Short-Term

Lines of Credit and Short-Term Borrowings	12 Months Ended
	Dec. 31, 2019
Lines of Credit and Short-Term Borrowings
Lines of Credit and Short-Term Borrowings	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 . The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2019 and 2018 (dollars in thousands): December 31, 2019 December 31, 2018 Pinnacle West APS Total Pinnacle West APS Total Commitments under Credit Facilities $ 200,000 $ 1,000,000 $ 1,200,000 $ 350,000 $ 1,000,000 $ 1,350,000 Outstanding Commercial Paper and Revolving Credit Facility Borrowings (76,675 ) — (76,675 ) (76,400 ) — (76,400 ) Amount of Credit Facilities Available $ 123,325 $ 1,000,000 $ 1,123,325 $ 273,600 $ 1,000,000 $ 1,273,600 Weighted-Average Commitment Fees 0.125% 0.100% 0.125% 0.100% Pinnacle West On May 9, 2019, Pinnacle West entered into a $50 million term loan agreement that matures May 7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR") plus 0.55% per annum. At December 31, 2019 , Pinnacle West had $38 million in outstanding borrowings under the agreement. At December 31, 2019 , Pinnacle West had a $200 million revolving credit facility that matures in July 2023. 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. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, 2019 , Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $77 million of commercial paper borrowings. APS At December 31, 2019 , APS had two revolving credit facilities totaling $1 billion , including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. 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, 2019 , APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 11 for a discussion of APS's other outstanding letters of credit. Debt Provisions On November 27, 2018, 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 (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power). See Note 7 for additional long-term debt provisions.

Long-Term Debt and Liquidity Ma

Long-Term Debt and Liquidity Matters	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt and Liquidity Matters	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, 2019 and 2018 (dollars in thousands): Maturity Interest December 31, Dates (a) Rates 2019 2018 APS Pollution control bonds: Variable 2029 (b) $ 35,975 $ 35,975 Fixed 2024 4.70% 115,150 115,150 Total pollution control bonds 151,125 151,125 Senior unsecured notes 2020-2049 2.20%-6.88% 4,875,000 4,575,000 Term loans (c) 200,000 — Unamortized discount (12,434 ) (12,638 ) Unamortized premium 7,423 7,736 Unamortized debt issuance cost (37,981 ) (31,787 ) Total APS long-term debt 5,183,133 4,689,436 Less current maturities 350,000 500,000 Total APS long-term debt less current maturities 4,833,133 4,189,436 Pinnacle West Senior unsecured notes 2020 2.25% 300,000 300,000 Term loan 2020 (d) 150,000 150,000 Unamortized discount (57 ) (121 ) Unamortized debt issuance cost (518 ) (1,083 ) Total Pinnacle West long-term debt 449,425 448,796 Less current maturities 450,000 — Total Pinnacle West long-term debt less current maturities (575 ) 448,796 TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES $ 4,832,558 $ 4,638,232 (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 1.54% at December 31, 2019 and 1.76% at December 31, 2018 . (c) The weighted-average interest rate was 2.12% at December 31, 2019 . (d) The weighted-average interest rate was 2.20% at December 31, 2019 and 3.02% at December 31, 2018 . 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 2020 $ 800,000 $ 350,000 2021 — — 2022 — — 2023 — — 2024 365,150 365,150 Thereafter 4,510,975 4,510,975 Total $ 5,676,125 $ 5,226,125 Debt Fair Value Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of As of Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 449,425 $ 450,822 $ 448,796 $ 443,955 APS 5,183,133 5,743,570 4,689,436 4,789,608 Total $ 5,632,558 $ 6,194,392 $ 5,138,232 $ 5,233,563 Credit Facilities and Debt Issuances APS On February 26, 2019, APS entered into a $200 million term loan agreement that matures August 26, 2020. APS used the proceeds to repay existing indebtedness. Borrowings under the agreement bear interest at LIBOR plus 0.50% per annum. On February 28, 2019, APS issued $300 million of 4.25% unsecured senior notes that mature on March 1, 2049. The net proceeds from the sale, together with funds made available from the term loan described above, were used to repay existing indebtedness. On March 1, 2019, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes. On August 19, 2019, APS issued $300 million of 2.6% unsecured senior notes that mature on August 15, 2029. The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, and to replenish cash used to fund capital expenditures. On November 20, 2019, APS issued $300 million of 3.5% unsecured senior notes that mature on December 1, 2049. The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, to replenish cash used to fund capital expenditures, and to redeem, on December 30, 2019, $100 million of the $250 million aggregate principal amount of our 2.2% Notes due January 15, 2020. On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% senior notes mentioned above. See “Lines of Credit and Short-Term Borrowings” in Note 6 and “Financial Assurances” in Note 11 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, 2019 , the ratio was approximately 52% 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. 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 November 27, 2018, 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 $5.1 billion to $5.9 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. See Note 6 for additional short-term debt provisions.

Retirement Plans and Other Bene

Retirement Plans and Other Benefits	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Retirement Plans and Other Benefits	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. 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 14 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. 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 or billed to electric plant participants) (dollars in thousands): Pension Other Benefits 2019 2018 2017 2019 2018 2017 Service cost-benefits earned during the period $ 49,902 $ 56,669 $ 54,858 $ 18,369 $ 21,100 $ 17,119 Interest cost on benefit obligation 136,843 124,689 129,756 29,894 28,147 29,959 Expected return on plan assets (171,884 ) (182,853 ) (174,271 ) (38,412 ) (42,082 ) (53,401 ) Amortization of: Prior service cost (credit) — — 81 (37,821 ) (37,842 ) (37,842 ) Net actuarial loss 42,584 32,082 47,900 — — 5,118 Net periodic benefit cost (benefit) $ 57,445 $ 30,587 $ 58,324 $ (27,970 ) $ (30,677 ) $ (39,047 ) Portion of cost charged to expense $ 30,312 $ 10,120 $ 27,295 $ (19,859 ) $ (21,426 ) $ (18,274 ) The following table shows the plans’ changes in the benefit obligations and funded status for the years 2019 and 2018 (dollars in thousands): Pension Other Benefits 2019 2018 2019 2018 Change in Benefit Obligation Benefit obligation at January 1 $ 3,190,626 $ 3,394,186 $ 676,771 $ 753,393 Service cost 49,902 56,669 18,369 21,100 Interest cost 136,843 124,689 29,894 28,147 Benefit payments (177,882 ) (184,161 ) (32,486 ) (31,540 ) Actuarial (gain) loss 413,625 (200,757 ) 54,376 (94,329 ) Benefit obligation at December 31 3,613,114 3,190,626 746,924 676,771 Change in Plan Assets Fair value of plan assets at January 1 2,733,476 3,057,027 723,677 1,022,371 Actual return on plan assets 602,030 (201,078 ) 144,095 (40,354 ) Employer contributions 150,000 50,000 — — Benefit payments (167,155 ) (172,473 ) (30,278 ) (72,453 ) Transfer to active union medical account — — — (185,887 ) Fair value of plan assets at December 31 3,318,351 2,733,476 837,494 723,677 Funded Status at December 31 $ (294,763 ) $ (457,150 ) $ 90,570 $ 46,906 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, 2019 and 2018 (dollars in thousands): 2019 2018 Projected benefit obligation $ 177,775 $ 3,190,626 Accumulated benefit obligation 169,091 3,038,774 Fair value of plan assets — 2,733,476 The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefits obligation basis at December 31, 2019 , therefore the only pension plan with an accumulated benefits obligation in excess of plan assets in 2019 is a non-qualified supplemental excess benefit retirement plan. The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2019 and 2018 (dollars in thousands): Pension Other Benefits 2019 2018 2019 2018 Noncurrent asset $ — $ — $ 90,570 $ 46,906 Current liability (14,578 ) (13,980 ) — — Noncurrent liability (280,185 ) (443,170 ) — — Net amount recognized $ (294,763 ) $ (457,150 ) $ 90,570 $ 46,906 The following table shows the details related to accumulated other comprehensive loss as of December 31, 2019 and 2018 (dollars in thousands): Pension Other Benefits 2019 2018 2019 2018 Net actuarial loss $ 735,186 $ 794,292 $ 12,238 $ 63,544 Prior service credit — — (189,912 ) (227,733 ) APS’s portion recorded as a regulatory (asset) liability (660,223 ) (733,351 ) 177,209 163,767 Income tax expense (benefit) (18,546 ) (15,083 ) 570 561 Accumulated other comprehensive loss $ 56,417 $ 45,858 $ 105 $ 139 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 2020 (dollars in thousands): Pension Other Benefits Net actuarial loss $ 33,642 $ — Prior service credit — (37,575 ) Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2020 $ 33,642 $ (37,575 ) 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, 2019 2018 2019 2018 2017 Discount rate – pension 3.30 % 4.34 % 4.34 % 3.65 % 4.08 % Discount rate – other benefits 3.42 % 4.39 % 4.39 % 3.71 % 4.17 % 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 6.25 % 6.05 % 6.55 % Expected long-term return on plan assets - other benefits N/A N/A 5.40 % 5.40 % 6.05 % 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 % 4.75 % 4.75 % 4.75 % 5.00 % Ultimate healthcare cost trend rate 4.75 % 4.75 % 4.75 % 4.75 % 5.00 % Number of years to ultimate trend rate (pre-65 participants) 6 7 7 8 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 2020, we are assuming a 5.75% long-term rate of return for pension assets and 5.00% (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, 2019 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 $ 9,299 $ (3,827 ) Effect on service and interest cost components of net periodic other postretirement benefit costs 9,434 (7,257 ) Effect on the accumulated other postretirement benefit obligation 124,073 (97,710 ) 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 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 2019, the target and actual allocation for the pension plan at December 31, 2019 are as follows: Pension Target Allocation Actual Allocation Long-term fixed income assets 62 % 63 % Return-generating assets 38 % 37 % 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, 2019 , 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, 2019 : Other Benefits Actual Allocation Long-term fixed income assets 68 % Return-generating assets 32 % Total 100 % See Note 14 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 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 Futures 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, 2019 , 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 $50 million to these partnerships; as of December 31, 2019 , approximately $38 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. The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2019 , by asset category, are as follows (dollars in thousands): Level 1 Level 2 Other (a) Total Pension Plan: Cash and cash equivalents $ 9,370 $ — $ — $ 9,370 Fixed income securities: Corporate — 1,541,729 — 1,541,729 U.S. Treasury 406,112 — — 406,112 Other (b) — 92,240 — 92,240 Common stock equities (c) 250,829 — — 250,829 Mutual funds (d) 185,928 — — 185,928 Common and collective trusts: Equities — — 392,403 392,403 Real estate — — 171,645 171,645 Fixed Income — — 98,065 98,065 Partnerships — — 103,796 103,796 Short-term investments and other (e) — — 66,234 66,234 Total $ 852,239 $ 1,633,969 $ 832,143 $ 3,318,351 Other Benefits: Cash and cash equivalents $ 2,184 $ — $ — $ 2,184 Fixed income securities: Corporate — 202,640 — 202,640 U.S. Treasury 353,650 — — 353,650 Other (b) — 7,999 — 7,999 Common stock equities (c) 146,316 — — 146,316 Mutual funds (d) 14,351 — — 14,351 Common and collective trusts: Equities — — 83,648 83,648 Real estate — — 19,806 19,806 Short-term investments and other (e) 2,881 — 4,019 6,900 Total $ 519,382 $ 210,639 $ 107,473 $ 837,494 (a) These investments primarily represent assets valued using NAV 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 international common stock equities. (e) This category includes plan receivables and payables. The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2018 , by asset category, are as follows (dollars in thousands): Level 1 Level 2 Other (a) Total Pension Plan: Cash and cash equivalents $ 451 $ — $ — $ 451 Fixed income securities: Corporate — 1,237,744 — 1,237,744 U.S. Treasury 372,649 — — 372,649 Other (b) — 78,902 — 78,902 Common stock equities (c) 196,661 — — 196,661 Mutual funds (d) 120,976 — — 120,976 Common and collective trusts: Equities — — 272,926 272,926 Real estate — — 165,123 165,123 Fixed Income — — 86,483 86,483 Partnerships — — 125,217 125,217 Short-term investments and other (e) — — 76,344 76,344 Total $ 690,737 $ 1,316,646 $ 726,093 $ 2,733,476 Other Benefits: Cash and cash equivalents $ 93 $ — $ — $ 93 Fixed income securities: Corporate — 163,286 — 163,286 U.S. Treasury 318,017 — — 318,017 Other (b) — 7,531 — 7,531 Common stock equities (c) 129,199 — — 129,199 Mutual funds (d) 10,963 — — 10,963 Common and collective trusts: Equities — — 65,720 65,720 Real estate — — 19,054 19,054 Short-term investments and other (e) 3,633 — 6,181 9,814 Total $ 461,905 $ 170,817 $ 90,955 $ 723,677 (a) These investments primarily represent assets valued using NAV 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 $150 million in 2019 , $50 million in 2018 , and $100 million in 2017 . The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million per year during the 2020-2022 period. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2019 and 2018 . We made a contribution of approximately $1 million in 2017 . We do not expect to make any contributions over the next three years to our other postretirement benefit plans. The Company was reimbursed $30 million in 2019 and $72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets. The Company was not reimbursed in 2017 . 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 2020 $ 199,395 $ 31,531 2021 201,597 32,777 2022 206,618 33,566 2023 213,208 34,415 2024 218,150 34,468 Years 2025-2029 1,111,171 174,607 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 2019, 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 $11 million for 2019 , $11 million for 2018 , and $10 million for 2017 .

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Leases We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2020 through 2050. Substantially all of our leasing activities relate to APS. 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 19 for a discussion of VIEs. On January 1, 2019 we adopted new lease accounting guidance (see Note 3). We elected the transition method that allows us to apply the new lease guidance on the date of adoption, January 1, 2019, and will not retrospectively adjust prior periods. We also elected certain transition practical expedients that allow us to not reassess (a) whether any expired or existing contracts are or contain leases, (b) the lease classification for any expired or existing leases and (c) initial direct costs for any existing leases. These practical expedients apply to leases that commenced prior to January 1, 2019. Furthermore, we elected the practical expedient transition provisions relating to the treatment of existing land easements. On January 1, 2019 the adoption of this new accounting standard resulted in the recognition on our Consolidated Balance Sheets of approximately $194 million of right-of-use lease assets and $119 million of lease liabilities relating to our operating lease arrangements. The right-of-use lease assets include $85 million of prepaid lease costs that have been reclassified from other deferred debits, and $10 million of deferred lease costs that have been reclassified from other current liabilities. In addition to these balance sheet impacts, the adoption of the guidance resulted in expanded lease disclosures, which are included below. The following table provides information related to our lease costs (dollars in thousands): Year Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 42,190 $ 18,038 $ 60,228 Variable lease cost 113,233 782 114,015 Short-term lease cost — 4,385 4,385 Total lease cost $ 155,423 $ 23,205 $ 178,628 Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet. Lease disclosures relating to 2018 and 2017 are presented under prior lease accounting guidance. Lease expense recognized in the Consolidated Statements of Income was $18 million in 2018 and $18 million in 2017, these amounts do not include purchased power lease contracts. Operating lease cost for purchased power lease contracts was $47 million in 2018 and $60 million in 2017. In addition, contingent rents for purchased power lease contracts was $109 million in 2018 and $100 million in 2017. These purchased power lease costs are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands): December 31, 2019 Year Purchased Power Lease Contracts (a) Land, Property & Equipment Leases Total 2020 $ — $ 14,698 $ 14,698 2021 — 11,963 11,963 2022 — 8,331 8,331 2023 — 6,326 6,326 2024 — 4,141 4,141 Thereafter — 38,697 38,697 Total lease commitments — 84,156 84,156 Less imputed interest — 19,571 19,571 Total lease liabilities $ — $ 64,585 $ 64,585 (a) As of December 31, 2019, we had no operating lease liabilities relating to purchased power lease contracts. See discussion below regarding executed contracts with commencement dates beginning in June 2020. We recognize lease assets and liabilities upon lease commencement. At December 31, 2019 , we have additional lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to purchased power lease contracts. These leases have commencement dates beginning in June 2020 with terms ending through October 2027. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million over the term of the arrangements. The following table provides information related to estimated future minimum operating lease payments (dollars in thousands): December 31, 2018 Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total 2019 $ 54,499 $ 13,747 $ 68,246 2020 — 12,428 12,428 2021 — 9,478 9,478 2022 — 6,513 6,513 2023 — 5,359 5,359 Thereafter — 42,236 42,236 Total future lease commitments $ 54,499 $ 89,761 $ 144,260 The following tables provide other additional information related to operating lease liabilities: December 31, 2019 Weighted average remaining lease term 13 years Weighted average discount rate (a) 3.71 % (a) Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable. Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands): $ 69,075

Jointly-Owned Facilities

Jointly-Owned Facilities	12 Months Ended
	Dec. 31, 2019
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Jointly-Owned Facilities	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, 2019 (dollars in thousands): Percent Owned Plant in Service Accumulated Depreciation Construction Work in Progress Generating facilities: Palo Verde Units 1 and 3 29.1 % $ 1,877,748 $ 1,102,609 $ 22,071 Palo Verde Unit 2 (a) 16.8 % 634,545 377,722 11,831 Palo Verde Common 28.0 % (b) 746,653 290,084 46,570 Palo Verde Sale Leaseback (a) 351,050 249,144 — Four Corners Generating Station 63.0 % 1,520,171 559,272 44,842 Cholla common facilities (c) 50.5 % 184,608 95,720 1,323 Transmission facilities: ANPP 500kV System 33.5 % (b) 133,396 51,248 2,723 Navajo Southern System 26.7 % (b) 89,672 31,985 194 Palo Verde — Yuma 500kV System 19.0 % (b) 15,274 6,486 4,886 Four Corners Switchyards 63.0 % (b) 69,994 16,674 2,395 Phoenix — Mead System 17.1 % (b) 39,355 18,570 53 Palo Verde — Rudd 500kV System 50.0 % 93,112 26,719 317 Morgan — Pinnacle Peak System 64.6 % (b) 117,752 18,822 — Round Valley System 50.0 % 515 164 — Palo Verde — Morgan System 88.9 % (b) 238,689 13,146 — Hassayampa — North Gila System 80.0 % 143,422 12,676 — Cholla 500kV Switchyard 85.7 % 7,651 1,597 535 Saguaro 500kV Switchyard 60.0 % 20,425 12,949 — Kyrene — Knox System 50.0 % 578 315 — (a) See Note 19. (b) Weighted-average of interests. (c) PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information) and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned. See "Navajo Plant" in Note 4 for more details.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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 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. 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 five claims pursuant to the terms of the August 18, 2014 settlement agreement, for five separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $84.3 million for these claims (APS’s share is $24.5 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 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). On October 31, 2019, APS filed its next claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $16 million (APS’s share is $4.7 million ). On February 11, 2020, the DOE approved a payment of $15.4 million (APS’s share is $4.5 million ). 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 of up to approximately $13.9 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 $13.5 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 $137.6 million , subject to a maximum annual premium of approximately $20.5 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 $120.1 million , with a maximum annual retrospective premium of approximately $17.9 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, 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 $25.5 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 $73.4 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 2020 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $590 million in 2020 ; $613 million in 2021 ; $624 million in 2022 ; $616 million in 2023 ; $581 million in 2024 ; and $5.5 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. These amounts include estimated commitments relating to purchased power lease contracts (see Note 9). 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, 2020 2021 2022 2023 2024 Thereafter Coal take-or-pay commitments (a) $ 185,347 $ 186,554 $ 187,400 $ 189,120 $ 193,192 $ 1,240,964 (a) Total take-or-pay commitments are approximately $2.2 billion . The total net present value of these commitments is approximately $1.6 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, 2019 2018 2017 Total purchases $ 204,888 $ 206,093 $ 165,220 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 $36 million in 2020 ; $35 million in 2021 ; $31 million in 2022 ; $30 million in 2023 ; $28 million in 2024 ; and $133 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Coal Mine Reclamation Obligations APS 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 $166 million at December 31, 2019 and $213 million at December 31, 2018 . Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $17 million in 2020 ; $16 million in 2021 ; $17 million in 2022 ; $18 million in 2023 ; $19 million in 2024 ; and $88 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 The Comprehensive Environmental Response Compensation and Liability Act ("CERCLA" or "Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ("PRPs"). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("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 for OU3, APS anticipates finalizing the RI/FS in the spring or summer of 2020. 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, Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, 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 environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named 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. On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. 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. EPA required the plant to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plant. In addition, EPA issued a final 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 was approximately $400 million , which has been incurred. 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 purchased the interest from 4CA on July 3, 2018. See "Four Corners - 4CA Matter" below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million , which was assumed by NTEC through its purchase of the 7% interest. 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 State Implementation Plan ("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, whereby APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See "Cholla" in Note 4 for information regarding future plans for Cholla and 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 BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. 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 the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing 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. Such closure requirements are deemed "forced closure" or "closure for cause" of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below. Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants: • Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to, either, authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits. • On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal. • Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On November 4, 2019, EPA proposed that all unlined CCR surface impoundments, regardless of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity). • On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s proposal regarding alternative closure would require express EPA authorization for such facilities to continue operating their CCR disposal units under alternative closure. We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows. 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 $15 million . The Navajo Plant currently disposes of CCR in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS's share of incremental costs is approximately $1 million , which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must cease operating and initiate closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2020. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million , which would be incurred over 30 years. The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment process, we cannot predict any ultimate impacts to the Company; however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations or cash flows. Clean Power Plan/Affordable Clean Energy Regulations . On June 19, 2019, EPA took final action on its proposals to repeal EPA's 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and those regulations had been stayed pending judicial review. The ACE regulations are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal, the finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs in the near future. We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits in the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition, to the extent that the ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet. 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 the Office of Surface Mining Reclamation and Enforcement ("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 the Endangered Species Act ("ESA") and the National Environmental Policy Act ("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. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. The Ninth Circuit denied this petition for rehearing on December 11, 2019. Four Corners National Pollutant Discharge Elimination System ("NPDES") Permit On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the EPA Environmental Appeals Board, based upon a November 1, 2019 filing by several environmental groups. We cannot predict the outcome of this review and whether the review will have a material impact on our financial position, results of operations or cash flows. Four Corners 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 and ultimately purchased the interest on July 3, 2018 . NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million , and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC's 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West's guarantee is secured by a portion of APS's payments to be owed to NTEC under the 2016 Coal Supply Agreement. The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included 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. The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) is approximately $10 million , which was due to 4CA on December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations. 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. As of December 31, 2019 , standby letters of credit totaled $1.7 million and will expire in 2020. As of December 31, 2019 , surety bonds expiring through 2020 totaled $14 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, 2019 . In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See "Four Corners - 4CA Matter" above for information related to this guarantee.) A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee to be immaterial. In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West reduce as payments are made under the respective guaranteed agreements. The Equity Contribution Guarantees are currently anticipated to be terminated upon completion of construction of the respective projects, which is anticipated to occur prior to December 31, 2020, and the PTC Guarantees (approximately $40 million

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations In 2019, APS received updated decommissioning estimates for the Navajo Plant closure in December 2019, which resulted in a decrease to the ARO in the amount of $8 million (see Note 4 for additional information). In addition, APS received a new decommissioning study for Palo Verde. This resulted in a decrease to the ARO in the amount of $89 million , a decrease in plant in service of $80 million and a reduction in the regulatory liability of $9 million . In 2018, APS recognized an ARO for the removal of hazardous waste containing solar panels at all of our utility scale solar plants, which resulted in an increase to the ARO in the amount of $14 million . In addition, due to the sale of 4CA assets to NTEC in 2018 (see Note 11 for more information on 4CA matters) there was a decrease to the ARO of $9 million . APS recognized an ARO of $7 million for rooftop solar removals in accordance with the obligations included in the customer contracts, which requires APS to remove the panels at the end of the contract life and includes the costs for the disposal of hazardous materials in accordance with environmental regulations. Finally, APS has other ARO adjustments resulting in a net decrease of $1 million . The following table shows the change in our asset retirement obligations for 2019 and 2018 (dollars in thousands): 2019 2018 Asset retirement obligations at the beginning of year $ 726,545 $ 679,529 Changes attributable to: Accretion expense 39,726 36,876 Settlements (12,591 ) (9,726 ) Estimated cash flow revisions (96,462 ) 2,002 Newly incurred or acquired obligations — 17,864 Asset retirement obligations at the end of year $ 657,218 $ 726,545 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 4.

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data (Unaudited)	Selected Quarterly Financial Data (Unaudited) Consolidated quarterly financial information for 2019 and 2018 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. 2019 Quarter Ended 2019 March 31, June 30, September 30, December 31, Total Operating revenues $ 740,530 $ 869,501 $ 1,190,787 $ 670,391 $ 3,471,209 Operations and maintenance 245,634 227,543 238,582 229,857 941,616 Operating income 60,084 196,589 403,290 11,997 671,960 Income taxes 2,418 17,080 53,266 (88,537 ) (15,773 ) Net income 22,791 149,019 317,149 68,854 557,813 Net income attributable to common shareholders 17,918 144,145 312,276 63,981 538,320 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.16 $ 1.28 $ 2.78 $ 0.57 $ 4.79 Net income attributable to common shareholders — Diluted 0.16 1.28 2.77 0.57 4.77 2018 Quarter Ended 2018 March 31, June 30, September 30, December 31, Total Operating revenues $ 692,714 $ 974,123 $ 1,268,034 $ 756,376 $ 3,691,247 Operations and maintenance 265,682 268,397 246,545 256,120 1,036,744 Operating income 31,334 242,162 433,307 66,884 773,687 Income taxes (1,265 ) 44,039 84,333 6,795 133,902 Net income 8,094 171,612 319,885 30,949 530,540 Net income attributable to common shareholders 3,221 166,738 315,012 26,076 511,047 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.03 $ 1.49 $ 2.81 $ 0.23 $ 4.56 Net income attributable to common shareholders — Diluted 0.03 1.48 2.80 0.23 4.54 Selected Quarterly Financial Data (Unaudited) - APS APS's quarterly financial information for 2019 and 2018 is as follows (dollars in thousands): 2019 Quarter Ended 2019 March 31, June 30, September 30, December 31, Total Operating revenues $ 740,530 $ 869,501 $ 1,190,787 $ 670,391 $ 3,471,209 Operations and maintenance 240,375 224,143 235,440 226,758 926,716 Operating income 65,377 200,018 406,465 15,124 686,984 Net income attributable to common shareholder 28,276 150,176 318,870 67,949 565,271 2018 Quarter Ended 2018 March 31, June 30, September 30, December 31, Total Operating revenues $ 692,006 $ 971,963 $ 1,267,997 $ 756,376 $ 3,688,342 Operations and maintenance 254,601 251,999 226,346 236,281 969,227 Operating income 37,878 251,590 453,547 86,753 829,768 Net income attributable to common shareholder 9,599 177,825 338,366 44,475 570,265

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are: Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. 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 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 cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trust and other special use funds. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 8 for fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent certain investments in 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. 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 Other Special Use Funds The nuclear decommissioning trust and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union medical trust. See Note 20 for additional discussion about our investment accounts. We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below 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 trustees’ and escrow agent's internal operating controls and valuation processes. Fixed Income Securities 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. Fixed income securities may also include short-term investments 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. These instruments are valued using active market prices or utilizing observable inputs described above. Equity Securities 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. The nuclear decommissioning trust and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid, investments are valued using active market prices. Fair Value Tables The following table presents the fair value at December 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 551 $ 33 $ (69 ) (a) $ 515 Nuclear decommissioning trust: Equity securities 10,872 — — 2,401 (b) 13,273 U.S. commingled equity funds — — — 518,844 (c) 518,844 U.S. Treasury debt 160,607 — — — 160,607 Corporate debt — 115,869 — — 115,869 Mortgage-backed securities — 118,795 — — 118,795 Municipal bonds — 73,040 — — 73,040 Other fixed income — 10,347 — — 10,347 Subtotal nuclear decommissioning trust 171,479 318,051 — 521,245 1,010,775 Other special use funds: Equity securities 7,142 — — 474 (b) 7,616 U.S. Treasury debt 232,848 — — — 232,848 Municipal bonds — 4,631 — — 4,631 Subtotal other special use funds 239,990 4,631 — 474 245,095 Total assets $ 411,469 $ 323,233 $ 33 $ 521,650 $ 1,256,385 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (67,992 ) $ (3,429 ) $ (711 ) (a) $ (72,132 ) (a) Represents counterparty netting, margin, and collateral. See Note 17 . (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. The following table presents the fair value at December 31, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Cash equivalents $ 1,200 $ — $ — $ — $ 1,200 Risk management activities — derivative instruments: Commodity contracts — 3,140 2 (2,029 ) (a) 1,113 Nuclear decommissioning trust: Equity securities 5,203 — — 2,148 (b) 7,351 U.S. commingled equity funds — — — 396,805 (c) 396,805 U.S. Treasury debt 148,173 — — — 148,173 Corporate debt — 96,656 — — 96,656 Mortgage-backed securities — 113,115 — — 113,115 Municipal bonds — 79,073 — — 79,073 Other fixed income — 9,961 — — 9,961 Subtotal nuclear decommissioning trust 153,376 298,805 — 398,953 851,134 Other special use funds: Equity securities 45,130 — — 593 (b) 45,723 U.S. Treasury debt 173,310 — — — 173,310 Municipal bonds — 17,068 — — 17,068 Subtotal other special use funds 218,440 17,068 — 593 236,101 Total assets $ 373,016 $ 319,013 $ 2 $ 397,517 $ 1,089,548 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (52,696 ) $ (8,216 ) $ 875 (a) $ (60,037 ) (a) Represents counterparty netting, margin, and collateral. See Note 17 . (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. 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 4 ). 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, 2019 and December 31, 2018 : December 31, 2019 Valuation Technique Significant Unobservable Input Range Weighted-Average Commodity Contracts Assets Liabilities Electricity: Forward Contracts (a) $ 33 $ 819 Discounted cash flows Electricity forward price (per MWh) $22.18 - $22.18 $ 22.18 Natural Gas: Forward Contracts (a) — 2,610 Discounted cash flows Natural gas forward price (per MMBtu) $2.33 -$ 2.78 $ 2.49 Total $ 33 $ 3,429 (a) Includes swaps and physical and financial contracts. December 31, 2018 Valuation Technique Significant Unobservable Input Range Weighted-Average Commodity Contracts Assets Liabilities Electricity: Forward Contracts (a) $ — $ 2,456 Discounted cash flows Electricity forward price (per MWh) $17.88 - $37.03 $ 26.10 Natural Gas: Forward Contracts (a) 2 5,760 Discounted cash flows Natural gas forward price (per MMBtu) $1.79 - $2.92 $ 2.48 Total $ 2 $ 8,216 (a) Includes swaps and physical and financial contracts. 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, 2019 and 2018 (dollars in thousands): Year Ended December 31, Commodity Contracts 2019 2018 Net derivative balance at beginning of period $ (8,214 ) $ (18,256 ) Total net gains (losses) realized/unrealized: Included in earnings — — Included in OCI — — Deferred as a regulatory asset or liability (13,457 ) (1,130 ) Settlements 12,250 (787 ) Transfers into Level 3 from Level 2 (6,512 ) (12,830 ) Transfers from Level 3 into Level 2 12,537 24,789 Net derivative balance at end of period $ (3,396 ) $ (8,214 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ — Transfers between levels in the fair value hierarchy shown in the table above 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 short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 7 for our long-term debt fair values. The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $44.3 million as of December 31, 2019 , as presented on the Consolidated Balance Sheets. The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy. See Note 11 for more information on 4CA matters.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2019 , 2018 and 2017 (in thousands, except per share amounts): 2019 2018 2017 Net income attributable to common shareholders $ 538,320 $ 511,047 $ 488,456 Weighted average common shares outstanding — basic 112,443 112,129 111,839 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 315 421 528 Weighted average common shares outstanding — diluted 112,758 112,550 112,367 Earnings per weighted-average common share outstanding Net income attributable to common shareholders - basic $ 4.79 $ 4.56 $ 4.37 Net income attributable to common shareholders - diluted $ 4.77 $ 4.54 $ 4.35

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	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, 2019 , 1.6 million common shares were available for issuance under the 2012 Plan. During 2019, 2018, and 2017, 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. Stock-Based Compensation Expense and Activity Compensation cost included in net income for stock-based compensation plans was $18 million in 2019 , $20 million in 2018 , and $21 million in 2017 . The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $7 million in 2019 , $7 million in 2018 , and $15 million in 2017 . As of December 31, 2019 , there were approximately $9 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 $21 million in 2019 , $24 million in 2018 and $22 million in 2017 . The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2019 , 2018 and 2017 : Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b) 2019 2018 2017 2019 2018 2017 Units granted 109,106 132,997 161,963 142,874 171,708 147,706 Weighted-average grant date fair value $ 89.15 $ 77.51 $ 72.60 $ 92.16 $ 76.56 $ 78.99 (a) Units granted includes awards that will be cash settled of 48,972 in 2019, 66,252 in 2018, and 67,599 in 2017. (b) Reflects the target payout level. The following table is a summary of the status of non-vested awards as of December 31, 2019 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, 2019 270,991 $ 74.39 312,384 $ 77.67 Granted 109,106 89.15 142,874 92.16 Vested (132,102 ) 73.48 (139,214 ) 78.99 Forfeited (c) (5,383 ) 80.10 (9,074 ) 81.03 Nonvested at December 31, 2019 242,612 (a) 81.38 306,970 83.65 Vested Awards Outstanding at December 31, 2019 67,148 139,214 (a) Includes 141,621 of awards that will be cash settled. (b) The nonvested performance shares are reflected at target payout level. (c) We account for forfeitures as they occur. Share-based liabilities paid relating to restricted stock units were $5 million , $4 million and $4 million in 2019, 2018 and 2017, respectively. This includes cash used to settle restricted stock units of $5 million , $5 million and $4 million in 2019, 2018 and 2017, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are 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. 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, 100% cash, 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, cash, 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.

Derivative Accounting

Derivative Accounting	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Accounting	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 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 14 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 4). 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, 2019 and 2018, 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, 2019 December 31, 2018 Power GWh 193 250 Gas Billion cubic feet 257 218 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, 2019 , 2018 and 2017 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2019 2018 2017 Loss Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ — $ — $ (59 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (1,512 ) (2,000 ) (3,519 ) (a) During the years ended December 31, 2019 , 2018 , and 2017 , 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 $0.8 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, 2019 , 2018 and 2017 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2019 2018 2017 Net Loss Recognized in Income Operating revenues $ — $ (2,557 ) $ (1,192 ) Net Loss Recognized in Income Fuel and purchased power (a) (84,953 ) (12,951 ) (87,991 ) Total $ (84,953 ) $ (15,508 ) $ (89,183 ) (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 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. 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, 2019 and 2018 . 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, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 584 $ (474 ) $ 110 $ 405 $ 515 Current liabilities (38,235 ) 474 (37,761 ) (1,185 ) (38,946 ) Deferred credits and other (33,186 ) — (33,186 ) — (33,186 ) Total liabilities (71,421 ) 474 (70,947 ) (1,185 ) (72,132 ) Total $ (70,837 ) $ — $ (70,837 ) $ (780 ) $ (71,617 ) (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 $ 1,185 and cash margin provided to counterparties of $405 . As of December 31, 2018: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 3,106 $ (2,149 ) $ 957 $ 156 $ 1,113 Investments and other assets 36 (36 ) — — — Total assets 3,142 (2,185 ) 957 156 1,113 Current liabilities (36,345 ) 2,149 (34,196 ) (1,310 ) (35,506 ) Deferred credits and other (24,567 ) 36 (24,531 ) — (24,531 ) Total liabilities (60,912 ) 2,185 (58,727 ) (1,310 ) (60,037 ) Total $ (57,770 ) $ — $ (57,770 ) $ (1,154 ) $ (58,924 ) (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 $1,310 and cash margin provided to counterparties of $156 . 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, 2019 , 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, 2019 (dollars in thousands): December 31, 2019 Aggregate fair value of derivative instruments in a net liability position $ 71,116 Cash collateral posted — Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) 70,519 (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 $95 million if our debt credit ratings were to fall below investment grade.

Other Income and Other Expense

Other Income and Other Expense	12 Months Ended
	Dec. 31, 2019
Other Income and Expenses [Abstract]
Other Income and Other Expense	Other Income and Other Expense The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2019 , 2018 and 2017 (dollars in thousands): 2019 2018 2017 Other income: Interest income $ 10,377 $ 8,647 $ 3,497 Debt return on Four Corners SCR deferral (Note 4) 19,541 16,153 354 Debt return on Ocotillo modernization project (Note 4) 20,282 — — Miscellaneous 63 96 155 Total other income $ 50,263 $ 24,896 $ 4,006 Other expense: Non-operating costs $ (10,663 ) $ (10,076 ) $ (11,749 ) Investment losses — net (1,835 ) (417 ) (4,113 ) Miscellaneous (5,382 ) (7,473 ) (5,677 ) Total other expense $ (17,880 ) $ (17,966 ) $ (21,539 ) Other Income and Other Expense - APS The following table provides detail of APS’s other income and other expense for 2019 , 2018 and 2017 (dollars in thousands): 2019 2018 2017 Other income: Interest income $ 6,998 $ 6,496 $ 2,504 Debt return on Four Corners SCR deferral (Note 4) 19,541 16,153 354 Debt return on Ocotillo modernization project (Note 4) 20,282 — — Miscellaneous 63 97 155 Total other income $ 46,884 $ 22,746 $ 3,013 Other expense: Non-operating costs $ (9,612 ) $ (9,462 ) $ (10,825 ) Miscellaneous (3,378 ) (5,830 ) (3,088 ) Total other expense $ (12,990 ) $ (15,292 ) $ (13,913 )

Palo Verde Sale Leaseback Varia

Palo Verde Sale Leaseback Variable Interest Entities	12 Months Ended
	Dec. 31, 2019
Variable Interest Entities [Abstract]
Palo Verde Sale Leaseback Variable Interest Entities	Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2020 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. 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 2019 , 2018 and 2017 . 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, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands): December 31, 2019 December 31, 2018 Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 101,906 $ 105,775 Equity-Noncontrolling interests 122,540 125,790 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 $301 million beginning in 2020, 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.

Investments in Nuclear Decommis

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds	12 Months Ended
	Dec. 31, 2019
Investments, Debt and Equity Securities [Abstract]
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds	Investments in Nuclear Decommissioning Trusts and Other Special Use Funds We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Consolidated Balance Sheets. See Note 14 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below. Nuclear Decommissioning Trusts - To fund the future 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. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities. Coal Reclamation Escrow Account - APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover 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) in other regulatory liabilities. Activities relating to APS coal reclamation escrow account investments are included within the other special use funds in the table below. Active Union Employee Medical Account - APS has investments restricted for paying active union employee medical costs. These investments were transferred from APS other postretirement benefit trust assets into the active union employee medical trust in January 2018. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In August 2019, the Company was reimbursed $15 million for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the tables below. APS The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at December 31, 2019 and December 31, 2018 (dollars in thousands): December 31, 2019 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity Securities $ 529,716 $ 7,142 $ 536,858 $ 337,681 $ — Available for Sale-Fixed Income Securities 478,658 237,479 716,137 (a) 25,795 (669 ) Other 2,401 474 2,875 (b) — — Total $ 1,010,775 $ 245,095 $ 1,255,870 $ 363,476 $ (669 ) (a) As of December 31, 2019 , the amortized cost basis of these available-for-sale investments is $691 million. (b) Represents net pending securities sales and purchases. December 31, 2018 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity Securities $ 402,008 $ 45,130 $ 447,138 $ 222,147 $ (459 ) Available for Sale-Fixed Income Securities 446,978 190,378 637,356 (a) 8,634 (6,778 ) Other 2,148 593 2,741 (b) — — Total $ 851,134 $ 236,101 $ 1,087,235 $ 230,781 $ (7,237 ) (a) As of December 31, 2018 , the amortized cost basis of these available-for-sale investments is $635 million. (b) Represents net pending securities sales and purchases. The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2019 , 2018 and 2017 (dollars in thousands): Year Ended December 31, Nuclear Decommissioning Trusts Other Special Use Funds Total 2019 Realized gains $ 11,024 $ 108 $ 11,132 Realized losses (6,972 ) — (6,972 ) Proceeds from the sale of securities (a) 473,806 245,228 719,034 2018 Realized gains 6,679 1 6,680 Realized losses (13,552 ) — (13,552 ) Proceeds from the sale of securities (a) 554,385 98,648 653,033 2017 Realized gains 21,813 17 21,830 Realized losses (13,146 ) (9 ) (13,155 ) Proceeds from the sale of securities (a) 542,246 4,093 546,339 (a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust. Fixed Income Securities Contractual Maturities The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2019 is as follows (dollars in thousands): Nuclear Decommissioning Trusts Coal Reclamation Escrow Account Active Union Medical Trust Total Less than one year $ 26,984 $ 31,953 $ 40,449 $ 99,386 1 year – 5 years 136,139 25,229 138,042 299,410 5 years – 10 years 105,797 — — 105,797 Greater than 10 years 209,738 1,806 — 211,544 Total $ 478,658 $ 58,988 $ 178,491 $ 716,137

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2019
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Changes in Accumulated Other Comprehensive Loss	Changes in Accumulated Other Comprehensive Loss The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2017 $ (42,440 ) $ (2,562 ) $ (45,002 ) OCI (loss) before reclassifications 102 (78 ) 24 Amounts reclassified from accumulated other comprehensive loss 4,295 (a) 1,527 (b) 5,822 Reclassification of income tax effect related to (7,954 ) (598 ) (8,552 ) Balance December 31, 2018 (45,997 ) (1,711 ) (47,708 ) OCI (loss) before reclassifications (14,041 ) — (14,041 ) Amounts reclassified from accumulated other comprehensive loss 3,516 (a) 1,137 (b) 4,653 Balance December 31, 2019 $ (56,522 ) $ (574 ) $ (57,096 ) (a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8 . (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 17 . Changes in Accumulated Other Comprehensive Loss - APS The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2017 $ (24,421 ) $ (2,562 ) $ (26,983 ) OCI (loss) before reclassifications (326 ) (78 ) (404 ) Amounts reclassified from accumulated other comprehensive loss 3,791 (a) 1,527 (b) 5,318 Reclassification of income tax effect related to (4,440 ) (598 ) (5,038 ) Balance December 31, 2018 (25,396 ) (1,711 ) (27,107 ) OCI (loss) before reclassifications (12,572 ) — (12,572 ) Amounts reclassified from accumulated other comprehensive loss 3,020 (a) 1,137 (b) 4,157 Balance December 31, 2019 $ (34,948 ) $ (574 ) $ (35,522 ) (a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8 . (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 17 .

SCHEDULE I - CONDENSED FINANCIA

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
CONDENSED FINANCIAL INFORMATION OF REGISTRANT	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, 2019 2018 2017 Operating revenues $ — $ — $ 119 Operating expenses 12,451 53,844 24,591 Operating loss (12,451 ) (53,844 ) (24,472 ) Other Equity in earnings of subsidiaries 562,946 569,249 507,495 Other expense (3,957 ) (3,202 ) (2,422 ) Total 558,989 566,047 505,073 Interest expense 15,069 12,074 5,633 Income before income taxes 531,469 500,129 474,968 Income tax benefit (6,851 ) (10,918 ) (13,488 ) Net income attributable to common shareholders 538,320 511,047 488,456 Other comprehensive income (loss) — attributable to common shareholders (9,388 ) 5,846 (1,180 ) Total comprehensive income — attributable to common shareholders $ 528,932 $ 516,893 $ 487,276 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, 2019 2018 ASSETS Current assets Cash and cash equivalents $ 19 $ 41 Accounts receivable 104,640 99,989 Income tax receivable 15,905 32,737 Other current assets 401 1,502 Total current assets 120,965 134,269 Investments and other assets Investments in subsidiaries 6,067,957 5,859,834 Deferred income taxes 40,757 5,243 Other assets 50,139 34,910 Total investments and other assets 6,158,853 5,899,987 Total Assets $ 6,279,818 $ 6,034,256 LIABILITIES AND EQUITY Current liabilities Accounts payable $ 7,634 $ 9,565 Accrued taxes 8,573 9,006 Common dividends payable 87,982 82,675 Short-term borrowings 114,675 76,400 Current maturities of long-term debt 450,000 — Operating lease liabilities 81 — Other current liabilities 15,126 19,215 Total current liabilities 684,071 196,861 Long-term debt less current maturities (Note 7) (575 ) 448,796 Pension liabilities 17,942 17,766 Operating lease liabilities 1,780 — Other 23,412 22,128 Total deferred credits and other 43,134 39,894 COMMITMENTS AND CONTINGENCIES (SEE NOTES) Common stock equity Common stock 2,650,134 2,629,440 Accumulated other comprehensive loss (57,096 ) (47,708 ) Retained earnings 2,837,610 2,641,183 Total Pinnacle West Shareholders’ equity 5,430,648 5,222,915 Noncontrolling interests 122,540 125,790 Total Equity 5,553,188 5,348,705 Total Liabilities and Equity $ 6,279,818 $ 6,034,256 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, 2019 2018 2017 Cash flows from operating activities Net income $ 538,320 $ 511,047 $ 488,456 Adjustments to reconcile net income to net cash provided by operating activities: Equity in earnings of subsidiaries — net (562,946 ) (569,249 ) (507,495 ) Depreciation and amortization 76 76 76 Deferred income taxes (35,831 ) 49,535 (264 ) Accounts receivable 182 (7,881 ) (2,106 ) Accounts payable (2,129 ) 1,967 (11,162 ) Accrued taxes and income tax receivables — net 16,400 (13,535 ) (22,247 ) Dividends received from subsidiaries 336,300 316,000 296,800 Other (1,300 ) 31,807 15,092 Net cash flow provided by operating activities 289,072 319,767 257,150 Cash flows from investing activities Investments in subsidiaries 1,557 (142,796 ) (178,027 ) Repayments of loans from subsidiaries 4,190 6,477 2,987 Advances of loans to subsidiaries (4,165 ) (500 ) (6,388 ) Net cash flow provided by (used for) investing activities 1,582 (136,819 ) (181,428 ) Cash flows from financing activities Issuance of long-term debt — 150,000 298,761 Short-term debt borrowings under revolving credit facility 49,000 20,000 58,000 Short-term debt repayments under revolving credit facility (65,000 ) (32,000 ) (32,000 ) Commercial paper - net 54,275 (7,000 ) 27,700 Dividends paid on common stock (329,643 ) (308,892 ) (289,793 ) Repayment of long-term debt — — (125,000 ) Common stock equity issuance - net of purchases 692 (5,055 ) (13,390 ) Other — (1 ) — Net cash flow used for financing activities (290,676 ) (182,948 ) (75,722 ) Net decrease in cash and cash equivalents (22 ) — — Cash and cash equivalents at beginning of year 41 41 41 Cash and cash equivalents at end of year $ 19 $ 41 $ 41 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.

SCHEDULE II - RESERVE FOR UNCOL

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	12 Months Ended
	Dec. 31, 2019
Reserve for uncollectibles
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	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: 2019 $ 4,069 $ 11,819 $ — $ 7,717 $ 8,171 2018 2,513 10,870 — 9,314 4,069 2017 3,037 6,836 — 7,360 2,513
ARIZONA PUBLIC SERVICE COMPANY
Reserve for uncollectibles
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES	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: 2019 $ 4,069 $ 11,819 $ — $ 7,717 $ 8,171 2018 2,513 10,870 — 9,314 4,069 2017 3,037 6,836 — 7,360 2,513

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Description of Business and Basis of Presentation	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. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. See Note 11 for more information on 4CA matters. 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 19 for additional information. 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.
Accounting Records and Use of Estimates	Accounting Records and Use of Estimates Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulatory Accounting	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 judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to 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. Management judgments also include assessing the impact of potential Commission-ordered refunds to customers on regulatory liabilities.
Electric Revenues	Electric Revenues On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers; accordingly our 2019 and 2018 electric revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed. We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. 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 regulated retail 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 electricity are netted against other contracts to sell electricity. This is called a "book-out" and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale 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	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 an estimated write-off factor to 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	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. Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West. 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 12 for additional information. APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it is probable it will 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, 2019 were as follows: • Fossil plant — 17 years ; • Nuclear plant — 22 years ; • Other generation — 21 years ; • Transmission — 40 years ; • Distribution — 34 years ; and • General plant — 8 years .
Asset Retirement Obligations	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.
Allowance for Funds Used During Construction	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 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 6.98% for 2019 , 7.03% for 2018 , and 6.68% for 2017 . 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	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	Fair Value Measurements We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of 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 7 for additional information. 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.
Derivative Accounting	Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal 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
Loss Contingencies and Environmental Liabilities	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	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 another 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 8 for additional information on pension and other postretirement benefits.
Nuclear Fuel	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
Income Taxes	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 5 for additional discussion.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.
Intangible Assets	Intangible Assets
Investments	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 measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence). Bright Canyon holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence). Our investments in the nuclear decommissioning trusts, coal reclamation escrow account and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 14 and 20 for more information on these investments.
Business Segments	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.
New Accounting Standards	New Accounting Standards Standards Adopted in 2019 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 requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially 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. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 9 for additional information. ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract In August 2018, a new accounting standard was issued that clarifies how customers in a cloud computing service arrangement should account for implementation costs associated with the arrangement. To determine which implementation costs should be capitalized, the new guidance aligns the accounting with existing guidance pertaining to internal-use software. As a result of this new standard, certain cloud computing service arrangement implementation costs will now be subject to capitalization and amortized on a straight-line basis over the cloud computing service arrangement term. The new standard was effective for us on January 1, 2020, with early application permitted, and may have been applied using either a retrospective or prospective transition approach. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements. Standard Adopted in 2020 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 requires 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. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were 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 adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses, these changes did not have a material impact on our financial statements.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of property, plant and equipment	Pinnacle West’s property, plant and equipment included in the December 31, 2019 and 2018 Consolidated Balance Sheets is composed of the following (dollars in thousands): Property, Plant and Equipment: 2019 2018 Generation $ 8,916,872 $ 8,285,514 Transmission 3,095,907 3,033,579 Distribution 6,690,697 6,378,345 General plant 1,132,816 1,039,190 Plant in service and held for future use 19,836,292 18,736,628 Accumulated depreciation and amortization (6,637,857 ) (6,366,014 ) Net 13,198,435 12,370,614 Construction work in progress 808,133 1,170,062 Palo Verde sale leaseback, net of accumulated depreciation 101,906 105,775 Intangible assets, net of accumulated amortization 290,564 262,902 Nuclear fuel, net of accumulated amortization 123,500 120,217 Total property, plant and equipment $ 14,522,538 $ 14,029,570
Summary of supplemental cash flow information	The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands): Year ended December 31, 2019 2018 2017 Cash paid during the period for: Income taxes, net of refunds $ 12,535 $ 21,173 $ 2,186 Interest, net of amounts capitalized 218,664 208,479 189,288 Significant non-cash investing and financing activities: Accrued capital expenditures $ 141,297 $ 132,620 $ 130,404 Dividends declared but not paid 87,982 82,675 77,667 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 11,262 — — Sale of 4CA 7% interest in Four Corners — 68,907 — The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands): Year ended December 31, 2019 2018 2017 Cash paid (received) during the period for: Income taxes, net of refunds $ (15,042 ) $ 77,942 $ (14,098 ) Interest, net of amounts capitalized 204,261 196,419 184,210 Significant non-cash investing and financing activities: Accrued capital expenditures $ 141,297 $ 132,620 $ 130,057 Dividends declared but not paid 88,000 82,700 77,700 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 11,262 — —

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands): Year Ended December 31, Year Ended December 31, 2019 2018 Retail Electric Service Residential $ 1,761,122 $ 1,867,370 Non-Residential 1,509,514 1,628,891 Wholesale Energy Sales 121,805 109,198 Transmission Services for Others 62,460 60,261 Other Sources 16,308 25,527 Total Operating Revenues $ 3,471,209 $ 3,691,247

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule Of Capital Structure and Cost Of Capital	the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 45.3 % 4.10 % Common stock equity 54.7 % 10.15 % Weighted-average cost of capital 7.41 %
Schedule of changes in the deferred fuel and purchased power regulatory asset	The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2019 and 2018 (dollars in thousands): Twelve Months Ended 2019 2018 Beginning balance $ 37,164 $ 75,637 Deferred fuel and purchased power costs — current period 82,481 78,277 Amounts charged to customers (49,508 ) (116,750 ) Ending balance $ 70,137 $ 37,164
Schedule of regulatory assets	The detail of regulatory assets is as follows (dollars in thousands): S December 31, 2019 December 31, 2018 Amortization Through Current Non-Current Current Non-Current Pension (a) $ — $ 660,223 $ — $ 733,351 Retired power plant costs 2033 28,182 142,503 28,182 167,164 Income taxes - AFUDC equity 2049 6,800 154,974 6,457 151,467 Deferred fuel and purchased power (b) (c) 2020 70,137 — 37,164 — Deferred fuel and purchased power — mark-to-market (Note 17) 2024 36,887 33,185 31,728 23,768 Deferred property taxes 2027 8,569 58,196 8,569 66,356 SCR deferral N/A — 52,644 — 23,276 Four Corners cost deferral 2024 8,077 32,152 8,077 40,228 Ocotillo deferral N/A — 38,144 — — Deferred compensation 2036 — 36,464 — 36,523 Income taxes — investment tax credit basis adjustment 2048 1,098 24,981 1,079 25,522 Lost fixed cost recovery (b) 2020 26,067 — 32,435 — Palo Verde VIEs (Note 19) 2046 — 20,635 — 20,015 Coal reclamation 2026 1,546 17,688 1,546 15,607 Loss on reacquired debt 2038 1,637 12,031 1,637 13,668 Mead-Phoenix transmission line - contributions in aid of construction 2050 332 9,712 332 10,044 TCA balancing account (b) 2021 6,324 2,885 3,860 772 Tax expense of Medicare subsidy 2024 1,235 4,940 1,235 6,176 AG-1 deferral 2022 2,787 2,716 2,654 5,819 Tax expense adjustor mechanism (b) 2020 1,612 — — — Other Various 1,917 — 1,947 3,185 Total regulatory assets (d) $ 203,207 $ 1,304,073 $ 166,902 $ 1,342,941 (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 8 for further discussion. (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. (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.”
Schedule of regulatory liabilities	The detail of regulatory liabilities is as follows (dollars in thousands): December 31, 2019 December 31, 2018 Amortization Through Current Non-Current Current Non-Current Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a) 2046 $ 59,918 $ 1,054,053 $ — $ 1,272,709 Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a) 2058 6,302 237,357 6,302 243,691 Asset retirement obligations 2057 — 418,423 — 278,585 Removal costs (c) 47,356 136,072 39,866 177,533 Other postretirement benefits (d) 37,575 139,634 37,864 125,903 Income taxes - change in rates 2049 2,797 68,265 2,769 70,069 Spent nuclear fuel 2027 6,676 51,019 6,503 57,002 Four Corners coal reclamation 2038 1,059 51,704 1,858 17,871 Income taxes - deferred investment tax credit 2048 2,202 50,034 2,164 51,120 Renewable energy standard (b) 2021 39,287 10,300 44,966 20 Demand side management (b) 2021 15,024 24,146 14,604 4,123 Sundance maintenance 2031 5,698 11,319 1,278 17,228 Property tax deferral N/A — 7,046 — 2,611 Tax expense adjustor mechanism (b) 2020 7,018 — 3,237 — Deferred gains on utility property 2022 2,423 4,163 4,423 6,581 FERC transmission true up 2021 1,045 2,004 — — Other Various 532 2,296 42 930 Total regulatory liabilities $ 234,912 $ 2,267,835 $ 165,876 $ 2,325,976 (a) For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as "Deferred income taxes" under Cash Flows From Operating Activities. (b) See “Cost Recovery Mechanisms” discussion above. (c) In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal. (d) See Note 8 .

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of unrecognized tax benefits roll forward	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): Pinnacle West Consolidated APS Consolidated 2019 2018 2017 2019 2018 2017 Total unrecognized tax benefits, January 1 $ 40,731 $ 41,966 $ 36,075 $ 40,731 $ 41,966 $ 36,075 Additions for tax positions of the current year 3,373 3,436 2,937 3,373 3,436 2,937 Additions for tax positions of prior years 1,843 2,696 4,783 1,843 2,696 4,783 Reductions for tax positions of prior years for: Changes in judgment (2,078 ) (1,764 ) (1,829 ) (2,078 ) (1,764 ) (1,829 ) Settlements with taxing authorities — — — — — — Lapses of applicable statute of limitations (434 ) (5,603 ) — (434 ) (5,603 ) — Total unrecognized tax benefits, December 31 $ 43,435 $ 40,731 $ 41,966 $ 43,435 $ 40,731 $ 41,966
Summary of unrecognized tax benefits	The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): Pinnacle West Consolidated APS Consolidated 2019 2018 2017 2019 2018 2017 Unrecognized tax benefit interest expense/(benefit) recognized $ 459 $ (780 ) $ 577 $ 459 $ (780 ) $ 577 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 2019 2018 2017 2019 2018 2017 Unrecognized tax benefit interest accrued $ 1,589 $ 1,130 $ 1,910 $ 1,589 $ 1,130 $ 1,910 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 2019 2018 2017 2019 2018 2017 Tax positions, that if recognized, would decrease our effective tax rate $ 22,813 $ 19,504 $ 16,373 $ 22,813 $ 19,504 $ 16,373
Components of income tax expense	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, 2019 2018 2017 2019 2018 2017 Current: Federal $ (13,551 ) $ 18,375 $ 11,624 $ (54,697 ) $ 88,180 $ 21,512 State 3,195 3,342 3,052 695 1,877 2,778 Total current (10,356 ) 21,717 14,676 (54,002 ) 90,057 24,290 Deferred: Federal (14,982 ) 94,721 223,729 29,321 32,436 221,078 State 9,565 17,464 19,867 15,109 22,321 23,800 Total deferred (5,417 ) 112,185 243,596 44,430 54,757 244,878 Income tax expense/(benefit) $ (15,773 ) $ 133,902 $ 258,272 $ (9,572 ) $ 144,814 $ 269,168
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations	The following chart compares pretax income at the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to income tax expense (dollars in thousands): Pinnacle West Consolidated APS Consolidated Year Ended December 31, Year Ended December 31, 2019 2018 2017 2019 2018 2017 Federal income tax expense at statutory rate $ 113,828 $ 139,533 $ 268,177 $ 120,790 $ 154,260 $ 277,540 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 18,599 23,115 21,380 19,267 24,531 22,329 State income tax credits net of federal income tax benefit (8,519 ) (6,704 ) (6,483 ) (6,781 ) (5,440 ) (5,053 ) Nondeductible expenditures associated with ballot initiative — 7,879 — — — — Stock compensation (2,252 ) (1,804 ) (6,659 ) (1,054 ) (780 ) (3,489 ) Excess deferred income taxes - Tax Cuts and Jobs Act (124,082 ) (6,725 ) 9,348 (124,082 ) (4,715 ) 9,431 Allowance for equity funds used during construction (see Note 1) (2,476 ) (7,231 ) (12,937 ) (2,476 ) (7,231 ) (12,937 ) Palo Verde VIE noncontrolling interest (see Note 19) (4,094 ) (4,094 ) (6,823 ) (4,094 ) (4,094 ) (6,823 ) Investment tax credit amortization (6,851 ) (6,742 ) (6,715 ) (6,851 ) (6,742 ) (6,715 ) Other 74 (3,325 ) (1,016 ) (4,291 ) (4,975 ) (5,115 ) Income tax expense/(benefit) $ (15,773 ) $ 133,902 $ 258,272 $ (9,572 ) $ 144,814 $ 269,168
Components of the net deferred income tax liability	The components of the net deferred income tax liability were as follows (dollars in thousands): Pinnacle West Consolidated APS Consolidated December 31, December 31, 2019 2018 2019 2018 DEFERRED TAX ASSETS Risk management activities $ 17,552 $ 15,785 $ 17,552 $ 15,785 Regulatory liabilities: Excess deferred income taxes - Tax Cuts and Jobs Act 335,877 376,869 335,877 376,869 Asset retirement obligation and removal costs 143,011 117,201 143,011 117,201 Unamortized investment tax credits 52,236 53,284 52,236 53,284 Other postretirement benefits 43,841 40,532 43,841 40,532 Other 52,382 40,380 52,382 40,380 Pension liabilities 73,210 112,019 67,976 107,009 Coal reclamation liabilities 40,837 47,508 40,837 47,508 Renewable energy incentives 28,066 30,779 28,066 30,779 Credit and loss carryforwards 54,795 1,755 10,992 — Other 63,102 58,820 70,948 59,919 Total deferred tax assets 904,909 894,932 863,718 889,266 DEFERRED TAX LIABILITIES Plant-related (2,448,458 ) (2,277,724 ) (2,448,458 ) (2,277,724 ) Risk management activities (27 ) (237 ) (27 ) (237 ) Other postretirement assets and other special use funds (66,399 ) (57,697 ) (65,965 ) (57,274 ) Regulatory assets: Allowance for equity funds used during construction (40,023 ) (39,086 ) (40,023 ) (39,086 ) Deferred fuel and purchased power (35,162 ) (23,086 ) (35,162 ) (23,086 ) Pension benefits (163,339 ) (181,504 ) (163,339 ) (181,504 ) Retired power plant costs (see Note 4) (42,228 ) (48,348 ) (42,228 ) (48,348 ) Other (82,722 ) (72,096 ) (82,722 ) (72,096 ) Other (18,890 ) (2,575 ) (18,890 ) (2,575 ) Total deferred tax liabilities (2,897,248 ) (2,702,353 ) (2,896,814 ) (2,701,930 ) Deferred income taxes — net $ (1,992,339 ) $ (1,807,421 ) $ (2,033,096 ) $ (1,812,664 )

Lines of Credit and Short-Ter_2

Lines of Credit and Short-Term Borrowings (Tables)	12 Months Ended
	Dec. 31, 2019
Lines of Credit and Short-Term Borrowings
Schedule of consolidated credit facilities and amounts available and outstanding	The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2019 and 2018 (dollars in thousands): December 31, 2019 December 31, 2018 Pinnacle West APS Total Pinnacle West APS Total Commitments under Credit Facilities $ 200,000 $ 1,000,000 $ 1,200,000 $ 350,000 $ 1,000,000 $ 1,350,000 Outstanding Commercial Paper and Revolving Credit Facility Borrowings (76,675 ) — (76,675 ) (76,400 ) — (76,400 ) Amount of Credit Facilities Available $ 123,325 $ 1,000,000 $ 1,123,325 $ 273,600 $ 1,000,000 $ 1,273,600 Weighted-Average Commitment Fees 0.125% 0.100% 0.125% 0.100%

Long-Term Debt and Liquidity _2

Long-Term Debt and Liquidity Matters (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Components of long-term debt on the Consolidated Balance Sheets	The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2019 and 2018 (dollars in thousands): Maturity Interest December 31, Dates (a) Rates 2019 2018 APS Pollution control bonds: Variable 2029 (b) $ 35,975 $ 35,975 Fixed 2024 4.70% 115,150 115,150 Total pollution control bonds 151,125 151,125 Senior unsecured notes 2020-2049 2.20%-6.88% 4,875,000 4,575,000 Term loans (c) 200,000 — Unamortized discount (12,434 ) (12,638 ) Unamortized premium 7,423 7,736 Unamortized debt issuance cost (37,981 ) (31,787 ) Total APS long-term debt 5,183,133 4,689,436 Less current maturities 350,000 500,000 Total APS long-term debt less current maturities 4,833,133 4,189,436 Pinnacle West Senior unsecured notes 2020 2.25% 300,000 300,000 Term loan 2020 (d) 150,000 150,000 Unamortized discount (57 ) (121 ) Unamortized debt issuance cost (518 ) (1,083 ) Total Pinnacle West long-term debt 449,425 448,796 Less current maturities 450,000 — Total Pinnacle West long-term debt less current maturities (575 ) 448,796 TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES $ 4,832,558 $ 4,638,232 (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 1.54% at December 31, 2019 and 1.76% at December 31, 2018 . (c) The weighted-average interest rate was 2.12% at December 31, 2019 . (d) The weighted-average interest rate was 2.20% at December 31, 2019 and 3.02% at December 31, 2018 .
Principal payments due on Pinnacle West's and APS's total long-term debt	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 2020 $ 800,000 $ 350,000 2021 — — 2022 — — 2023 — — 2024 365,150 365,150 Thereafter 4,510,975 4,510,975 Total $ 5,676,125 $ 5,226,125
Schedule of estimated fair value of long-term debt, including current maturities	The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of As of Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 449,425 $ 450,822 $ 448,796 $ 443,955 APS 5,183,133 5,743,570 4,689,436 4,789,608 Total $ 5,632,558 $ 6,194,392 $ 5,138,232 $ 5,233,563

Retirement Plans and Other Be_2

Retirement Plans and Other Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)	The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands): Pension Other Benefits 2019 2018 2017 2019 2018 2017 Service cost-benefits earned during the period $ 49,902 $ 56,669 $ 54,858 $ 18,369 $ 21,100 $ 17,119 Interest cost on benefit obligation 136,843 124,689 129,756 29,894 28,147 29,959 Expected return on plan assets (171,884 ) (182,853 ) (174,271 ) (38,412 ) (42,082 ) (53,401 ) Amortization of: Prior service cost (credit) — — 81 (37,821 ) (37,842 ) (37,842 ) Net actuarial loss 42,584 32,082 47,900 — — 5,118 Net periodic benefit cost (benefit) $ 57,445 $ 30,587 $ 58,324 $ (27,970 ) $ (30,677 ) $ (39,047 ) Portion of cost charged to expense $ 30,312 $ 10,120 $ 27,295 $ (19,859 ) $ (21,426 ) $ (18,274 )
Schedule of changes in the benefit obligations and funded status	The following table shows the plans’ changes in the benefit obligations and funded status for the years 2019 and 2018 (dollars in thousands): Pension Other Benefits 2019 2018 2019 2018 Change in Benefit Obligation Benefit obligation at January 1 $ 3,190,626 $ 3,394,186 $ 676,771 $ 753,393 Service cost 49,902 56,669 18,369 21,100 Interest cost 136,843 124,689 29,894 28,147 Benefit payments (177,882 ) (184,161 ) (32,486 ) (31,540 ) Actuarial (gain) loss 413,625 (200,757 ) 54,376 (94,329 ) Benefit obligation at December 31 3,613,114 3,190,626 746,924 676,771 Change in Plan Assets Fair value of plan assets at January 1 2,733,476 3,057,027 723,677 1,022,371 Actual return on plan assets 602,030 (201,078 ) 144,095 (40,354 ) Employer contributions 150,000 50,000 — — Benefit payments (167,155 ) (172,473 ) (30,278 ) (72,453 ) Transfer to active union medical account — — — (185,887 ) Fair value of plan assets at December 31 3,318,351 2,733,476 837,494 723,677 Funded Status at December 31 $ (294,763 ) $ (457,150 ) $ 90,570 $ 46,906
Schedule of projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets	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, 2019 and 2018 (dollars in thousands): 2019 2018 Projected benefit obligation $ 177,775 $ 3,190,626 Accumulated benefit obligation 169,091 3,038,774 Fair value of plan assets — 2,733,476
Schedule of amounts recognized on the Consolidated Balance Sheets	The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2019 and 2018 (dollars in thousands): Pension Other Benefits 2019 2018 2019 2018 Noncurrent asset $ — $ — $ 90,570 $ 46,906 Current liability (14,578 ) (13,980 ) — — Noncurrent liability (280,185 ) (443,170 ) — — Net amount recognized $ (294,763 ) $ (457,150 ) $ 90,570 $ 46,906
Schedule of accumulated other comprehensive loss	The following table shows the details related to accumulated other comprehensive loss as of December 31, 2019 and 2018 (dollars in thousands): Pension Other Benefits 2019 2018 2019 2018 Net actuarial loss $ 735,186 $ 794,292 $ 12,238 $ 63,544 Prior service credit — — (189,912 ) (227,733 ) APS’s portion recorded as a regulatory (asset) liability (660,223 ) (733,351 ) 177,209 163,767 Income tax expense (benefit) (18,546 ) (15,083 ) 570 561 Accumulated other comprehensive loss $ 56,417 $ 45,858 $ 105 $ 139
Schedule of estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost	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 2020 (dollars in thousands): Pension Other Benefits Net actuarial loss $ 33,642 $ — Prior service credit — (37,575 ) Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2020 $ 33,642 $ (37,575 )
Schedule of weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs	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, 2019 2018 2019 2018 2017 Discount rate – pension 3.30 % 4.34 % 4.34 % 3.65 % 4.08 % Discount rate – other benefits 3.42 % 4.39 % 4.39 % 3.71 % 4.17 % 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 6.25 % 6.05 % 6.55 % Expected long-term return on plan assets - other benefits N/A N/A 5.40 % 5.40 % 6.05 % 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 % 4.75 % 4.75 % 4.75 % 5.00 % Ultimate healthcare cost trend rate 4.75 % 4.75 % 4.75 % 4.75 % 5.00 % Number of years to ultimate trend rate (pre-65 participants) 6 7 7 8 4
Schedule of effects of one percentage point change in the assumed initial and ultimate health care cost trend rates	A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects on our December 31, 2019 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 $ 9,299 $ (3,827 ) Effect on service and interest cost components of net periodic other postretirement benefit costs 9,434 (7,257 ) Effect on the accumulated other postretirement benefit obligation 124,073 (97,710 )
Schedule of fair value of pension plan and other postretirement benefit plan assets, by asset category	The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2019 , by asset category, are as follows (dollars in thousands): Level 1 Level 2 Other (a) Total Pension Plan: Cash and cash equivalents $ 9,370 $ — $ — $ 9,370 Fixed income securities: Corporate — 1,541,729 — 1,541,729 U.S. Treasury 406,112 — — 406,112 Other (b) — 92,240 — 92,240 Common stock equities (c) 250,829 — — 250,829 Mutual funds (d) 185,928 — — 185,928 Common and collective trusts: Equities — — 392,403 392,403 Real estate — — 171,645 171,645 Fixed Income — — 98,065 98,065 Partnerships — — 103,796 103,796 Short-term investments and other (e) — — 66,234 66,234 Total $ 852,239 $ 1,633,969 $ 832,143 $ 3,318,351 Other Benefits: Cash and cash equivalents $ 2,184 $ — $ — $ 2,184 Fixed income securities: Corporate — 202,640 — 202,640 U.S. Treasury 353,650 — — 353,650 Other (b) — 7,999 — 7,999 Common stock equities (c) 146,316 — — 146,316 Mutual funds (d) 14,351 — — 14,351 Common and collective trusts: Equities — — 83,648 83,648 Real estate — — 19,806 19,806 Short-term investments and other (e) 2,881 — 4,019 6,900 Total $ 519,382 $ 210,639 $ 107,473 $ 837,494 (a) These investments primarily represent assets valued using NAV 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 international common stock equities. (e) This category includes plan receivables and payables. December 31, 2019 : Other Benefits Actual Allocation Long-term fixed income assets 68 % Return-generating assets 32 % Total 100 % The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2018 , by asset category, are as follows (dollars in thousands): Level 1 Level 2 Other (a) Total Pension Plan: Cash and cash equivalents $ 451 $ — $ — $ 451 Fixed income securities: Corporate — 1,237,744 — 1,237,744 U.S. Treasury 372,649 — — 372,649 Other (b) — 78,902 — 78,902 Common stock equities (c) 196,661 — — 196,661 Mutual funds (d) 120,976 — — 120,976 Common and collective trusts: Equities — — 272,926 272,926 Real estate — — 165,123 165,123 Fixed Income — — 86,483 86,483 Partnerships — — 125,217 125,217 Short-term investments and other (e) — — 76,344 76,344 Total $ 690,737 $ 1,316,646 $ 726,093 $ 2,733,476 Other Benefits: Cash and cash equivalents $ 93 $ — $ — $ 93 Fixed income securities: Corporate — 163,286 — 163,286 U.S. Treasury 318,017 — — 318,017 Other (b) — 7,531 — 7,531 Common stock equities (c) 129,199 — — 129,199 Mutual funds (d) 10,963 — — 10,963 Common and collective trusts: Equities — — 65,720 65,720 Real estate — — 19,054 19,054 Short-term investments and other (e) 3,633 — 6,181 9,814 Total $ 461,905 $ 170,817 $ 90,955 $ 723,677 (a) These investments primarily represent assets valued using NAV 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. Based on the IPS, and given the pension plan's funded status at year-end 2019, the target and actual allocation for the pension plan at December 31, 2019 are as follows: Pension Target Allocation Actual Allocation Long-term fixed income assets 62 % 63 % Return-generating assets 38 % 37 % 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 %
Schedule of estimated future benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter	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 2020 $ 199,395 $ 31,531 2021 201,597 32,777 2022 206,618 33,566 2023 213,208 34,415 2024 218,150 34,468 Years 2025-2029 1,111,171 174,607

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease cost	The following table provides information related to our lease costs (dollars in thousands): Year Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 42,190 $ 18,038 $ 60,228 Variable lease cost 113,233 782 114,015 Short-term lease cost — 4,385 4,385 Total lease cost $ 155,423 $ 23,205 $ 178,628 The following tables provide other additional information related to operating lease liabilities: December 31, 2019 Weighted average remaining lease term 13 years Weighted average discount rate (a) 3.71 % (a) Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable. Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands): $ 69,075
Schedule of future minimum payments	The following table provides information related to estimated future minimum operating lease payments (dollars in thousands): December 31, 2018 Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total 2019 $ 54,499 $ 13,747 $ 68,246 2020 — 12,428 12,428 2021 — 9,478 9,478 2022 — 6,513 6,513 2023 — 5,359 5,359 Thereafter — 42,236 42,236 Total future lease commitments $ 54,499 $ 89,761 $ 144,260
Maturity of our operating lease liabilities	The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands): December 31, 2019 Year Purchased Power Lease Contracts (a) Land, Property & Equipment Leases Total 2020 $ — $ 14,698 $ 14,698 2021 — 11,963 11,963 2022 — 8,331 8,331 2023 — 6,326 6,326 2024 — 4,141 4,141 Thereafter — 38,697 38,697 Total lease commitments — 84,156 84,156 Less imputed interest — 19,571 19,571 Total lease liabilities $ — $ 64,585 $ 64,585 (a) As of December 31, 2019, we had no operating lease liabilities relating to purchased power lease contracts. See discussion below regarding executed contracts with commencement dates beginning in June 2020.

Jointly-Owned Facilities (Table

Jointly-Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2019
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
APS's interests in jointly-owned facilities recorded on the Consolidated Balance Sheets	The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2019 (dollars in thousands): Percent Owned Plant in Service Accumulated Depreciation Construction Work in Progress Generating facilities: Palo Verde Units 1 and 3 29.1 % $ 1,877,748 $ 1,102,609 $ 22,071 Palo Verde Unit 2 (a) 16.8 % 634,545 377,722 11,831 Palo Verde Common 28.0 % (b) 746,653 290,084 46,570 Palo Verde Sale Leaseback (a) 351,050 249,144 — Four Corners Generating Station 63.0 % 1,520,171 559,272 44,842 Cholla common facilities (c) 50.5 % 184,608 95,720 1,323 Transmission facilities: ANPP 500kV System 33.5 % (b) 133,396 51,248 2,723 Navajo Southern System 26.7 % (b) 89,672 31,985 194 Palo Verde — Yuma 500kV System 19.0 % (b) 15,274 6,486 4,886 Four Corners Switchyards 63.0 % (b) 69,994 16,674 2,395 Phoenix — Mead System 17.1 % (b) 39,355 18,570 53 Palo Verde — Rudd 500kV System 50.0 % 93,112 26,719 317 Morgan — Pinnacle Peak System 64.6 % (b) 117,752 18,822 — Round Valley System 50.0 % 515 164 — Palo Verde — Morgan System 88.9 % (b) 238,689 13,146 — Hassayampa — North Gila System 80.0 % 143,422 12,676 — Cholla 500kV Switchyard 85.7 % 7,651 1,597 535 Saguaro 500kV Switchyard 60.0 % 20,425 12,949 — Kyrene — Knox System 50.0 % 578 315 — (a) See Note 19. (b) Weighted-average of interests. (c) PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information) and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Summary of estimated coal take-or-pay commitments	The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands): Years Ended December 31, 2020 2021 2022 2023 2024 Thereafter Coal take-or-pay commitments (a) $ 185,347 $ 186,554 $ 187,400 $ 189,120 $ 193,192 $ 1,240,964 (a) Total take-or-pay commitments are approximately $2.2 billion . The total net present value of these commitments is approximately $1.6 billion .
Summary of actual take-or-pay commitments	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, 2019 2018 2017 Total purchases $ 204,888 $ 206,093 $ 165,220

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Change in asset retirement obligations	The following table shows the change in our asset retirement obligations for 2019 and 2018 (dollars in thousands): 2019 2018 Asset retirement obligations at the beginning of year $ 726,545 $ 679,529 Changes attributable to: Accretion expense 39,726 36,876 Settlements (12,591 ) (9,726 ) Estimated cash flow revisions (96,462 ) 2,002 Newly incurred or acquired obligations — 17,864 Asset retirement obligations at the end of year $ 657,218 $ 726,545

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of quarterly financial information	Consolidated quarterly financial information for 2019 and 2018 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. 2019 Quarter Ended 2019 March 31, June 30, September 30, December 31, Total Operating revenues $ 740,530 $ 869,501 $ 1,190,787 $ 670,391 $ 3,471,209 Operations and maintenance 245,634 227,543 238,582 229,857 941,616 Operating income 60,084 196,589 403,290 11,997 671,960 Income taxes 2,418 17,080 53,266 (88,537 ) (15,773 ) Net income 22,791 149,019 317,149 68,854 557,813 Net income attributable to common shareholders 17,918 144,145 312,276 63,981 538,320 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.16 $ 1.28 $ 2.78 $ 0.57 $ 4.79 Net income attributable to common shareholders — Diluted 0.16 1.28 2.77 0.57 4.77 2018 Quarter Ended 2018 March 31, June 30, September 30, December 31, Total Operating revenues $ 692,714 $ 974,123 $ 1,268,034 $ 756,376 $ 3,691,247 Operations and maintenance 265,682 268,397 246,545 256,120 1,036,744 Operating income 31,334 242,162 433,307 66,884 773,687 Income taxes (1,265 ) 44,039 84,333 6,795 133,902 Net income 8,094 171,612 319,885 30,949 530,540 Net income attributable to common shareholders 3,221 166,738 315,012 26,076 511,047 Earnings Per Share: Net income attributable to common shareholders — Basic $ 0.03 $ 1.49 $ 2.81 $ 0.23 $ 4.56 Net income attributable to common shareholders — Diluted 0.03 1.48 2.80 0.23 4.54 APS's quarterly financial information for 2019 and 2018 is as follows (dollars in thousands): 2019 Quarter Ended 2019 March 31, June 30, September 30, December 31, Total Operating revenues $ 740,530 $ 869,501 $ 1,190,787 $ 670,391 $ 3,471,209 Operations and maintenance 240,375 224,143 235,440 226,758 926,716 Operating income 65,377 200,018 406,465 15,124 686,984 Net income attributable to common shareholder 28,276 150,176 318,870 67,949 565,271 2018 Quarter Ended 2018 March 31, June 30, September 30, December 31, Total Operating revenues $ 692,006 $ 971,963 $ 1,267,997 $ 756,376 $ 3,688,342 Operations and maintenance 254,601 251,999 226,346 236,281 969,227 Operating income 37,878 251,590 453,547 86,753 829,768 Net income attributable to common shareholder 9,599 177,825 338,366 44,475 570,265

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities that are measured at fair value on a recurring basis	The following table presents the fair value at December 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 551 $ 33 $ (69 ) (a) $ 515 Nuclear decommissioning trust: Equity securities 10,872 — — 2,401 (b) 13,273 U.S. commingled equity funds — — — 518,844 (c) 518,844 U.S. Treasury debt 160,607 — — — 160,607 Corporate debt — 115,869 — — 115,869 Mortgage-backed securities — 118,795 — — 118,795 Municipal bonds — 73,040 — — 73,040 Other fixed income — 10,347 — — 10,347 Subtotal nuclear decommissioning trust 171,479 318,051 — 521,245 1,010,775 Other special use funds: Equity securities 7,142 — — 474 (b) 7,616 U.S. Treasury debt 232,848 — — — 232,848 Municipal bonds — 4,631 — — 4,631 Subtotal other special use funds 239,990 4,631 — 474 245,095 Total assets $ 411,469 $ 323,233 $ 33 $ 521,650 $ 1,256,385 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (67,992 ) $ (3,429 ) $ (711 ) (a) $ (72,132 ) (a) Represents counterparty netting, margin, and collateral. See Note 17 . (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. The following table presents the fair value at December 31, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Cash equivalents $ 1,200 $ — $ — $ — $ 1,200 Risk management activities — derivative instruments: Commodity contracts — 3,140 2 (2,029 ) (a) 1,113 Nuclear decommissioning trust: Equity securities 5,203 — — 2,148 (b) 7,351 U.S. commingled equity funds — — — 396,805 (c) 396,805 U.S. Treasury debt 148,173 — — — 148,173 Corporate debt — 96,656 — — 96,656 Mortgage-backed securities — 113,115 — — 113,115 Municipal bonds — 79,073 — — 79,073 Other fixed income — 9,961 — — 9,961 Subtotal nuclear decommissioning trust 153,376 298,805 — 398,953 851,134 Other special use funds: Equity securities 45,130 — — 593 (b) 45,723 U.S. Treasury debt 173,310 — — — 173,310 Municipal bonds — 17,068 — — 17,068 Subtotal other special use funds 218,440 17,068 — 593 236,101 Total assets $ 373,016 $ 319,013 $ 2 $ 397,517 $ 1,089,548 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (52,696 ) $ (8,216 ) $ 875 (a) $ (60,037 ) (a) Represents counterparty netting, margin, and collateral. See Note 17 . (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments	The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2019 and December 31, 2018 : December 31, 2019 Valuation Technique Significant Unobservable Input Range Weighted-Average Commodity Contracts Assets Liabilities Electricity: Forward Contracts (a) $ 33 $ 819 Discounted cash flows Electricity forward price (per MWh) $22.18 - $22.18 $ 22.18 Natural Gas: Forward Contracts (a) — 2,610 Discounted cash flows Natural gas forward price (per MMBtu) $2.33 -$ 2.78 $ 2.49 Total $ 33 $ 3,429 (a) Includes swaps and physical and financial contracts. December 31, 2018 Valuation Technique Significant Unobservable Input Range Weighted-Average Commodity Contracts Assets Liabilities Electricity: Forward Contracts (a) $ — $ 2,456 Discounted cash flows Electricity forward price (per MWh) $17.88 - $37.03 $ 26.10 Natural Gas: Forward Contracts (a) 2 5,760 Discounted cash flows Natural gas forward price (per MMBtu) $1.79 - $2.92 $ 2.48 Total $ 2 $ 8,216 (a) Includes swaps and physical and financial contracts.
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs	The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2019 and 2018 (dollars in thousands): Year Ended December 31, Commodity Contracts 2019 2018 Net derivative balance at beginning of period $ (8,214 ) $ (18,256 ) Total net gains (losses) realized/unrealized: Included in earnings — — Included in OCI — — Deferred as a regulatory asset or liability (13,457 ) (1,130 ) Settlements 12,250 (787 ) Transfers into Level 3 from Level 2 (6,512 ) (12,830 ) Transfers from Level 3 into Level 2 12,537 24,789 Net derivative balance at end of period $ (3,396 ) $ (8,214 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ —

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Schedule of earnings per weighted average common share outstanding	The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2019 , 2018 and 2017 (in thousands, except per share amounts): 2019 2018 2017 Net income attributable to common shareholders $ 538,320 $ 511,047 $ 488,456 Weighted average common shares outstanding — basic 112,443 112,129 111,839 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 315 421 528 Weighted average common shares outstanding — diluted 112,758 112,550 112,367 Earnings per weighted-average common share outstanding Net income attributable to common shareholders - basic $ 4.79 $ 4.56 $ 4.37 Net income attributable to common shareholders - diluted $ 4.77 $ 4.54 $ 4.35

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Summary of Nonvested Restricted Stock, Stock Grants and Stock Units	The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2019 , 2018 and 2017 : Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b) 2019 2018 2017 2019 2018 2017 Units granted 109,106 132,997 161,963 142,874 171,708 147,706 Weighted-average grant date fair value $ 89.15 $ 77.51 $ 72.60 $ 92.16 $ 76.56 $ 78.99 (a) Units granted includes awards that will be cash settled of 48,972 in 2019, 66,252 in 2018, and 67,599 in 2017. (b) Reflects the target payout level. The following table is a summary of the status of non-vested awards as of December 31, 2019 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, 2019 270,991 $ 74.39 312,384 $ 77.67 Granted 109,106 89.15 142,874 92.16 Vested (132,102 ) 73.48 (139,214 ) 78.99 Forfeited (c) (5,383 ) 80.10 (9,074 ) 81.03 Nonvested at December 31, 2019 242,612 (a) 81.38 306,970 83.65 Vested Awards Outstanding at December 31, 2019 67,148 139,214 (a) Includes 141,621 of awards that will be cash settled. (b) The nonvested performance shares are reflected at target payout level. (c) We account for forfeitures as they occur.
Summary of Nonvested Performance Shares	The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2019 , 2018 and 2017 : Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b) 2019 2018 2017 2019 2018 2017 Units granted 109,106 132,997 161,963 142,874 171,708 147,706 Weighted-average grant date fair value $ 89.15 $ 77.51 $ 72.60 $ 92.16 $ 76.56 $ 78.99 (a) Units granted includes awards that will be cash settled of 48,972 in 2019, 66,252 in 2018, and 67,599 in 2017. (b) Reflects the target payout level. The following table is a summary of the status of non-vested awards as of December 31, 2019 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, 2019 270,991 $ 74.39 312,384 $ 77.67 Granted 109,106 89.15 142,874 92.16 Vested (132,102 ) 73.48 (139,214 ) 78.99 Forfeited (c) (5,383 ) 80.10 (9,074 ) 81.03 Nonvested at December 31, 2019 242,612 (a) 81.38 306,970 83.65 Vested Awards Outstanding at December 31, 2019 67,148 139,214 (a) Includes 141,621 of awards that will be cash settled. (b) The nonvested performance shares are reflected at target payout level. (c) We account for forfeitures as they occur.

Derivative Accounting (Tables)

Derivative Accounting (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)	As of December 31, 2019 and 2018, 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, 2019 December 31, 2018 Power GWh 193 250 Gas Billion cubic feet 257 218
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships	The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2019 , 2018 and 2017 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2019 2018 2017 Loss Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ — $ — $ (59 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (1,512 ) (2,000 ) (3,519 ) (a) During the years ended December 31, 2019 , 2018 , and 2017 , we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments	The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2019 , 2018 and 2017 (dollars in thousands): Financial Statement Year Ended December 31, Commodity Contracts Location 2019 2018 2017 Net Loss Recognized in Income Operating revenues $ — $ (2,557 ) $ (1,192 ) Net Loss Recognized in Income Fuel and purchased power (a) (84,953 ) (12,951 ) (87,991 ) Total $ (84,953 ) $ (15,508 ) $ (89,183 ) (a) Amounts are before the effect of PSA deferrals.
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting liabilities	The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting as of December 31, 2019 and 2018 . 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, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 584 $ (474 ) $ 110 $ 405 $ 515 Current liabilities (38,235 ) 474 (37,761 ) (1,185 ) (38,946 ) Deferred credits and other (33,186 ) — (33,186 ) — (33,186 ) Total liabilities (71,421 ) 474 (70,947 ) (1,185 ) (72,132 ) Total $ (70,837 ) $ — $ (70,837 ) $ (780 ) $ (71,617 ) (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 $ 1,185 and cash margin provided to counterparties of $405 . As of December 31, 2018: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 3,106 $ (2,149 ) $ 957 $ 156 $ 1,113 Investments and other assets 36 (36 ) — — — Total assets 3,142 (2,185 ) 957 156 1,113 Current liabilities (36,345 ) 2,149 (34,196 ) (1,310 ) (35,506 ) Deferred credits and other (24,567 ) 36 (24,531 ) — (24,531 ) Total liabilities (60,912 ) 2,185 (58,727 ) (1,310 ) (60,037 ) Total $ (57,770 ) $ — $ (57,770 ) $ (1,154 ) $ (58,924 ) (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 $1,310 and cash margin provided to counterparties of $156 .
Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting assets	The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting as of December 31, 2019 and 2018 . 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, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 584 $ (474 ) $ 110 $ 405 $ 515 Current liabilities (38,235 ) 474 (37,761 ) (1,185 ) (38,946 ) Deferred credits and other (33,186 ) — (33,186 ) — (33,186 ) Total liabilities (71,421 ) 474 (70,947 ) (1,185 ) (72,132 ) Total $ (70,837 ) $ — $ (70,837 ) $ (780 ) $ (71,617 ) (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 $ 1,185 and cash margin provided to counterparties of $405 . As of December 31, 2018: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 3,106 $ (2,149 ) $ 957 $ 156 $ 1,113 Investments and other assets 36 (36 ) — — — Total assets 3,142 (2,185 ) 957 156 1,113 Current liabilities (36,345 ) 2,149 (34,196 ) (1,310 ) (35,506 ) Deferred credits and other (24,567 ) 36 (24,531 ) — (24,531 ) Total liabilities (60,912 ) 2,185 (58,727 ) (1,310 ) (60,037 ) Total $ (57,770 ) $ — $ (57,770 ) $ (1,154 ) $ (58,924 ) (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 $1,310 and cash margin provided to counterparties of $156 .
Information about derivative instruments that have credit-risk-related contingent features	The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2019 (dollars in thousands): December 31, 2019 Aggregate fair value of derivative instruments in a net liability position $ 71,116 Cash collateral posted — Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) 70,519 (a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

Other Income and Other Expense

Other Income and Other Expense (Tables)	12 Months Ended
	Dec. 31, 2019
Other Income and Expenses [Abstract]
Detail of other income and other expense	The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2019 , 2018 and 2017 (dollars in thousands): 2019 2018 2017 Other income: Interest income $ 10,377 $ 8,647 $ 3,497 Debt return on Four Corners SCR deferral (Note 4) 19,541 16,153 354 Debt return on Ocotillo modernization project (Note 4) 20,282 — — Miscellaneous 63 96 155 Total other income $ 50,263 $ 24,896 $ 4,006 Other expense: Non-operating costs $ (10,663 ) $ (10,076 ) $ (11,749 ) Investment losses — net (1,835 ) (417 ) (4,113 ) Miscellaneous (5,382 ) (7,473 ) (5,677 ) Total other expense $ (17,880 ) $ (17,966 ) $ (21,539 ) The following table provides detail of APS’s other income and other expense for 2019 , 2018 and 2017 (dollars in thousands): 2019 2018 2017 Other income: Interest income $ 6,998 $ 6,496 $ 2,504 Debt return on Four Corners SCR deferral (Note 4) 19,541 16,153 354 Debt return on Ocotillo modernization project (Note 4) 20,282 — — Miscellaneous 63 97 155 Total other income $ 46,884 $ 22,746 $ 3,013 Other expense: Non-operating costs $ (9,612 ) $ (9,462 ) $ (10,825 ) Miscellaneous (3,378 ) (5,830 ) (3,088 ) Total other expense $ (12,990 ) $ (15,292 ) $ (13,913 )

Palo Verde Sale Leaseback Var_2

Palo Verde Sale Leaseback Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2019
Variable Interest Entities [Abstract]
Amounts relating to the VIEs included in Consolidated Balance Sheets	Our Consolidated Balance Sheets at December 31, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands): December 31, 2019 December 31, 2018 Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 101,906 $ 105,775 Equity-Noncontrolling interests 122,540 125,790

Investments in Nuclear Decomm_2

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)	12 Months Ended
	Dec. 31, 2019
Investments, Debt and Equity Securities [Abstract]
Fair value of APS's nuclear decommissioning trust fund assets	The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at December 31, 2019 and December 31, 2018 (dollars in thousands): December 31, 2019 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity Securities $ 529,716 $ 7,142 $ 536,858 $ 337,681 $ — Available for Sale-Fixed Income Securities 478,658 237,479 716,137 (a) 25,795 (669 ) Other 2,401 474 2,875 (b) — — Total $ 1,010,775 $ 245,095 $ 1,255,870 $ 363,476 $ (669 ) (a) As of December 31, 2019 , the amortized cost basis of these available-for-sale investments is $691 million. (b) Represents net pending securities sales and purchases. December 31, 2018 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity Securities $ 402,008 $ 45,130 $ 447,138 $ 222,147 $ (459 ) Available for Sale-Fixed Income Securities 446,978 190,378 637,356 (a) 8,634 (6,778 ) Other 2,148 593 2,741 (b) — — Total $ 851,134 $ 236,101 $ 1,087,235 $ 230,781 $ (7,237 ) (a) As of December 31, 2018 , the amortized cost basis of these available-for-sale investments is $635 million. (b) Represents net pending securities sales and purchases.
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds	The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2019 , 2018 and 2017 (dollars in thousands): Year Ended December 31, Nuclear Decommissioning Trusts Other Special Use Funds Total 2019 Realized gains $ 11,024 $ 108 $ 11,132 Realized losses (6,972 ) — (6,972 ) Proceeds from the sale of securities (a) 473,806 245,228 719,034 2018 Realized gains 6,679 1 6,680 Realized losses (13,552 ) — (13,552 ) Proceeds from the sale of securities (a) 554,385 98,648 653,033 2017 Realized gains 21,813 17 21,830 Realized losses (13,146 ) (9 ) (13,155 ) Proceeds from the sale of securities (a) 542,246 4,093 546,339 (a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust.
Fair value of fixed income securities, summarized by contractual maturities	The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2019 is as follows (dollars in thousands): Nuclear Decommissioning Trusts Coal Reclamation Escrow Account Active Union Medical Trust Total Less than one year $ 26,984 $ 31,953 $ 40,449 $ 99,386 1 year – 5 years 136,139 25,229 138,042 299,410 5 years – 10 years 105,797 — — 105,797 Greater than 10 years 209,738 1,806 — 211,544 Total $ 478,658 $ 58,988 $ 178,491 $ 716,137

Changes in Accumulated Other _2

Changes in Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2019
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component	The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2017 $ (42,440 ) $ (2,562 ) $ (45,002 ) OCI (loss) before reclassifications 102 (78 ) 24 Amounts reclassified from accumulated other comprehensive loss 4,295 (a) 1,527 (b) 5,822 Reclassification of income tax effect related to (7,954 ) (598 ) (8,552 ) Balance December 31, 2018 (45,997 ) (1,711 ) (47,708 ) OCI (loss) before reclassifications (14,041 ) — (14,041 ) Amounts reclassified from accumulated other comprehensive loss 3,516 (a) 1,137 (b) 4,653 Balance December 31, 2019 $ (56,522 ) $ (574 ) $ (57,096 ) (a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8 . (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 17 . The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2017 $ (24,421 ) $ (2,562 ) $ (26,983 ) OCI (loss) before reclassifications (326 ) (78 ) (404 ) Amounts reclassified from accumulated other comprehensive loss 3,791 (a) 1,527 (b) 5,318 Reclassification of income tax effect related to (4,440 ) (598 ) (5,038 ) Balance December 31, 2018 (25,396 ) (1,711 ) (27,107 ) OCI (loss) before reclassifications (12,572 ) — (12,572 ) Amounts reclassified from accumulated other comprehensive loss 3,020 (a) 1,137 (b) 4,157 Balance December 31, 2019 $ (34,948 ) $ (574 ) $ (35,522 ) (a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8 . (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 17 .

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended			36 Months Ended
	May 31, 2014$ / kWh	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)$ / sharesshares
Approximate remaining average useful lives of utility property
Depreciation		$ 522	$ 486	$ 453
Depreciation rates (as a percent)		2.81%	2.81%	2.80%
Allowance for Funds Used During Construction
Composite rate used to calculate AFUDC (as a percent)		6.98%	7.03%	6.68%
Income Taxes
Percent likelihood largest tax benefit amount is realized (greater than)		50.00%
Intangible Assets
Amortization expense		$ 66	$ 68	$ 72
Estimated amortization expense on existing intangible assets over the next five years
2019		68			$ 68
2020		52			52
2021		41			41
2022		32			32
2023		$ 22			$ 22
Remaining amortization period for intangible assets		8 years
Pinnacle West
Preferred Stock
Preferred stock, shares authorized (in shares) | shares		10,000,000			10,000,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear Fuel
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh) | $ / kWh	0.001
Preferred Stock
Preferred stock, shares authorized (in shares) | shares		15,535,000			15,535,000
Preferred stock par or stated value per share 1 (in dollars per share) | $ / shares		$ 25			$ 25
Preferred stock par or stated value per share 2 (in dollars per share) | $ / shares		50			50
Preferred stock par or stated value per share 3 (in dollars per share) | $ / shares		$ 100			$ 100
Minimum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					0.18%
Maximum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					24.49%
Investments
Ownership percentage for classification as cost method investments by El Dorado		20.00%
Fossil Plant
Approximate remaining average useful lives of utility property
Average useful life		17 years
Nuclear plant
Approximate remaining average useful lives of utility property
Average useful life		22 years
Other Generation
Approximate remaining average useful lives of utility property
Average useful life		21 years
Transmission
Approximate remaining average useful lives of utility property
Average useful life		40 years
Distribution
Approximate remaining average useful lives of utility property
Average useful life		34 years
General plant
Approximate remaining average useful lives of utility property
Average useful life		8 years
El Paso's Interest in Four Corners | 4CA
Utility Plant and Depreciation [Line Items]
Ownership interest acquired (as a percent)		7.00%			7.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Utility Plant and Depreciation [Line Items]
Net	$ 13,198,435	$ 12,370,614
Construction work in progress	808,133	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation	101,906	105,775
Intangible assets, net of accumulated amortization	290,564	262,902
Nuclear fuel, net of accumulated amortization	123,500	120,217
Total property, plant and equipment	14,522,538	14,029,570
Electric Service
Utility Plant and Depreciation [Line Items]
Generation	8,916,872	8,285,514
Transmission	3,095,907	3,033,579
Distribution	6,690,697	6,378,345
General plant	1,132,816	1,039,190
Plant in service and held for future use	19,836,292	18,736,628
Accumulated depreciation and amortization	(6,637,857)	(6,366,014)
Net	13,198,435	12,370,614
Construction work in progress	808,133	1,170,062
Palo Verde sale leaseback, net of accumulated depreciation	101,906	105,775
Intangible assets, net of accumulated amortization	290,564	262,902
Nuclear fuel, net of accumulated amortization	123,500	120,217
Total property, plant and equipment	$ 14,522,538	$ 14,029,570

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash and Cash Equivalents [Line Items]
Income taxes, net of refunds	$ 12,535	$ 21,173	$ 2,186
Interest, net of amounts capitalized	218,664	208,479	189,288
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Accrued capital expenditures	141,297	132,620	130,404
Dividends declared but not paid	87,982	82,675	77,667
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	11,262	0	0
Sale of 4CA 7% interest in Four Corners	0	68,907	0
ARIZONA PUBLIC SERVICE COMPANY
Cash and Cash Equivalents [Line Items]
Income taxes, net of refunds	(15,042)	77,942	(14,098)
Interest, net of amounts capitalized	204,261	196,419	184,210
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Accrued capital expenditures	141,297	132,620	130,057
Dividends declared but not paid	88,000	82,700	77,700
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	$ 11,262	$ 0	$ 0

Revenue - Sources of Revenue (D

Revenue - Sources of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Total Operating Revenues	$ 3,471,209	$ 3,691,247
Retail Electric Service | Retail residential
Disaggregation of Revenue [Line Items]
Total Operating Revenues	1,761,122	1,867,370
Retail Electric Service | Retail non-residential
Disaggregation of Revenue [Line Items]
Total Operating Revenues	1,509,514	1,628,891
Retail Electric Service | Wholesale
Disaggregation of Revenue [Line Items]
Total Operating Revenues	121,805	109,198
Transmission Services for Others
Disaggregation of Revenue [Line Items]
Total Operating Revenues	62,460	60,261
Other Sources
Disaggregation of Revenue [Line Items]
Total Operating Revenues	$ 16,308	$ 25,527

Revenue - Narrative (Details)

Revenue - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Operating revenues	$ 3,471,209	$ 3,691,247
Regulatory cost recovery revenue	56,000	47,000
Electric and Transmission Service
Disaggregation of Revenue [Line Items]
Operating revenues	$ 3,415,000	$ 3,644,000

Regulatory Matters - Retail Rat

Regulatory Matters - Retail Rate Case Filing (Details) - ACC - ARIZONA PUBLIC SERVICE COMPANY	Oct. 31, 2019USD ($)	Jun. 30, 2019USD ($)	Aug. 13, 2018USD ($)	Feb. 13, 2018	Jan. 08, 2018USD ($)	Jan. 03, 2018Customer	Mar. 27, 2017USD ($)$ / kWh	Dec. 31, 2019USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory impact, operating results								$ (10,000,000)
Requested rate increase for tax act	$ 184,000,000		$ (86,500,000)		$ (119,100,000)
Retail Rate Case Filing with Arizona Corporation Commission
Public Utilities, General Disclosures [Line Items]
Base rate decrease, elimination of tax expense adjustment mechanism	$ 115,000,000
Approximate percentage of increase in average customer bill	5.60%						3.28%
Approximate percentage of increase in average residential customer bill	5.40%			4.54%			4.54%
Rate matter, cost base rate		$ 8,870,000,000
Rate matter, funding limited income crisis bill program	$ 1,250,000
Settlement agreement, net retail base rate increase							$ 94,600,000
Settlement agreement, non-fuel, non-depreciation, base rate increase							87,200,000
Fuel-related base rate decrease							53,600,000
Base rate increase, changes in depreciation schedules							$ 61,000,000
Authorized return on common equity (as a percent)							10.00%
Percentage of debt in capital structure							44.20%
Percentage of common equity in capital structure							55.80%
Resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh							0.129
Number of customers which signed complaint | Customer						25
AZ Sun II Program | Retail Rate Case Filing with Arizona Corporation Commission
Public Utilities, General Disclosures [Line Items]
Minimum annual renewable energy standard and tariff							$ 10,000,000
Maximum annual renewable energy standard and tariff							$ 15,000,000
Minimum
Public Utilities, General Disclosures [Line Items]
Regulatory impact, operating results	$ 69,000,000
Minimum | Retail Rate Case Filing with Arizona Corporation Commission
Public Utilities, General Disclosures [Line Items]
Environmental surcharge cap rate (in dollars per kWh) | $ / kWh							0.00016
Maximum | Retail Rate Case Filing with Arizona Corporation Commission
Public Utilities, General Disclosures [Line Items]
Environmental surcharge cap rate (in dollars per kWh) | $ / kWh							0.00050

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters - Capital Structure and Costs of Capital (Details)	Oct. 31, 2019
Cost of Capital
Long-term debt	4.10%
Common stock equity	10.15%
Weighted-average cost of capital	7.41%
Retail Rate Case Filing with Arizona Corporation Commission | ARIZONA PUBLIC SERVICE COMPANY
Capital Structure
Common stock equity	54.70%
Retail Rate Case Filing with Arizona Corporation Commission | ACC | ARIZONA PUBLIC SERVICE COMPANY
Capital Structure
Long-term debt	45.30%

Regulatory Matters - Narrative

Regulatory Matters - Narrative (Details) Customer in Thousands

Feb. 14, 2020USD ($)

Feb. 01, 2020USD ($)$ / kWh

Nov. 14, 2019USD ($)Customer

Oct. 31, 2019USD ($)

Oct. 29, 2019USD ($)

Jun. 01, 2019USD ($)

May 01, 2019$ / kWh

Apr. 10, 2019

Feb. 15, 2019USD ($)

Feb. 01, 2019$ / kWh

Aug. 13, 2018USD ($)

Jun. 01, 2018USD ($)

May 01, 2018$ / kWh

Feb. 20, 2018

Feb. 15, 2018USD ($)

Feb. 01, 2018$ / kWh

Jan. 08, 2018USD ($)

Nov. 20, 2017USD ($)

Dec. 20, 2016$ / kWh

Dec. 31, 2020USD ($)

Dec. 31, 2019USD ($)

Dec. 31, 2017$ / kWh

Dec. 31, 2012$ / kWh

Jul. 01, 2019USD ($)

Mar. 15, 2019agreement

Dec. 31, 2018USD ($)

Jun. 29, 2018USD ($)

Nov. 14, 2017USD ($)

Sep. 01, 2017USD ($)

Jun. 30, 2017USD ($)

Regulatory Matters [Line Items]

Ballot initiative, proposed required energy supply to be obtained from renewable sources (as a percent)

50.00%

Number of customers | Customer

13

Inconvenience payment

$ 25

ARIZONA PUBLIC SERVICE COMPANY | Lost Fixed Cost Recovery Mechanism

Regulatory Matters [Line Items]

Fixed cost recoverable per residential power lost (in dollars per kWh) | $ / kWh

0.031

Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh

0.023

Fixed costs recoverable per power lost (in dollars per kWh) | $ / kWh

0.025

Rate matter cap percentage of retail revenue

1.00%

Amount of adjustment approved representing prorated sales losses pending approval

$ 36,200,000

$ 60,700,000

Decrease in amount of adjustment representing prorated sales losses

$ 24,500,000

ARIZONA PUBLIC SERVICE COMPANY | ACC

Regulatory Matters [Line Items]

Requested rate decrease for tax act

$ (184,000,000)

$ 86,500,000

$ 119,100,000

Requested rate increase (decrease), deferred taxes amortization, period

28 years 6 months

Requested rate increase (decrease), amount, one-time bill credit

$ 64,000,000

Requested rate increase (decrease), amount, one-time bill credit, additional benefit

$ 39,500,000

Regulatory impact, operating results

$ (10,000,000)

ARIZONA PUBLIC SERVICE COMPANY | ACC | Arizona Renewable Energy Standard and Tariff 2018

Regulatory Matters [Line Items]

Amount of proposed budget

$ 86,300,000

$ 89,900,000

$ 90,000,000

ARIZONA PUBLIC SERVICE COMPANY | ACC | Demand Side Management Adjustor Charge 2018

Regulatory Matters [Line Items]

Amount of proposed budget

51,900,000

$ 34,100,000

$ 52,600,000

$ 52,600,000

ARIZONA PUBLIC SERVICE COMPANY | ACC | Power Supply Adjustor (PSA)

Regulatory Matters [Line Items]

Fuel And purchased power costs, excess annual limit

$ 16,400,000

Maximum increase decrease in PSA rate (in dollars per kWh) | $ / kWh

0.004

PSA rate (in dollars per kWh) | $ / kWh

(0.001658)

(0.004555)

Forward component of PSA rate (in dollars per kWh) | $ / kWh

(0.000536)

(0.002009)

Historical component of PSA rate (in dollars per kWh) | $ / kWh

0.001122

0.002546

ARIZONA PUBLIC SERVICE COMPANY | ACC | Net Metering

Regulatory Matters [Line Items]

Cost of service, resource comparison proxy method, maximum annual percentage decrease

10.00%

Cost of service for interconnected DG system customers, grandfathered period

20 years

Guaranteed export price period

10 years

Settlement agreement, energy price for exported energy (in dollars per kWh) | $ / kWh

0.129

Request second-year energy price for exported energy | $ / kWh

0.105

0.116

ARIZONA PUBLIC SERVICE COMPANY | FERC | Transmission rates, transmission cost adjustor and other transmission matters

Regulatory Matters [Line Items]

Rate matters, increase (decrease) in cost recovery

$ (4,900,000)

$ (22,700,000)

Cost Recovery Mechanisms | ARIZONA PUBLIC SERVICE COMPANY | ACC | Power Supply Adjustor (PSA)

Regulatory Matters [Line Items]

PSA rate in prior years (in dollars per kWh) | $ / kWh

(0.002897)

Number of agreements | agreement

2

Solar Communities | ARIZONA PUBLIC SERVICE COMPANY | ACC | Arizona Renewable Energy Standard and Tariff 2018

Regulatory Matters [Line Items]

Program term

3 years

Minimum | ARIZONA PUBLIC SERVICE COMPANY | ACC

Regulatory Matters [Line Items]

Regulatory impact, operating results

$ 69,000,000

Minimum | Solar Communities | ARIZONA PUBLIC SERVICE COMPANY | ACC | Arizona Renewable Energy Standard and Tariff 2018

Regulatory Matters [Line Items]

Required annual capital investment

$ 10,000,000

Maximum | Solar Communities | ARIZONA PUBLIC SERVICE COMPANY | ACC | Arizona Renewable Energy Standard and Tariff 2018

Regulatory Matters [Line Items]

Required annual capital investment

$ 15,000,000

Subsequent Event | ARIZONA PUBLIC SERVICE COMPANY | Lost Fixed Cost Recovery Mechanism

Regulatory Matters [Line Items]

Amount of adjustment approved representing prorated sales losses pending approval

$ 26,600,000

Decrease in amount of adjustment representing prorated sales losses

$ 9,600,000

Subsequent Event | ARIZONA PUBLIC SERVICE COMPANY | ACC | Power Supply Adjustor (PSA)

Regulatory Matters [Line Items]

PSA rate (in dollars per kWh) | $ / kWh

0.000456

Forward component of PSA rate (in dollars per kWh) | $ / kWh

0.002086

Historical component of PSA rate (in dollars per kWh) | $ / kWh

0.001630

Subsequent Event | ARIZONA PUBLIC SERVICE COMPANY | FERC | Environmental Improvement Surcharge

Regulatory Matters [Line Items]

Rate matters, increase (decrease) in cost recovery

$ (8,750,000)

Subsequent Event | Cost Recovery Mechanisms | ARIZONA PUBLIC SERVICE COMPANY | ACC | Power Supply Adjustor (PSA)

Regulatory Matters [Line Items]

Maximum increase decrease in PSA rate (in dollars per kWh) | $ / kWh

0.004

PSA rate in prior years (in dollars per kWh) | $ / kWh

(0.002115)

Forecast | ARIZONA PUBLIC SERVICE COMPANY | FERC | Environmental Improvement Surcharge

Regulatory Matters [Line Items]

Rate matters, increase (decrease) in cost recovery, excess of annual amount

$ (2,000,000)

Regulatory Matters - Deferred F

Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in regulatory asset
Deferred fuel and purchased power costs — current period	$ 82,481	$ 78,277	$ 48,405
Amounts charged to customers	(49,508)	(116,750)	14,767
ARIZONA PUBLIC SERVICE COMPANY
Change in regulatory asset
Deferred fuel and purchased power costs — current period	82,481	78,277	48,405
Amounts charged to customers	(49,508)	(116,750)	14,767
ACC | ARIZONA PUBLIC SERVICE COMPANY | Power Supply Adjustor (PSA)
Change in regulatory asset
Beginning balance	37,164	75,637
Deferred fuel and purchased power costs — current period	82,481	78,277
Amounts charged to customers	(49,508)	(116,750)
Ending balance	$ 70,137	$ 37,164	$ 75,637

Regulatory Matters - Four Corne

Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($) $ in Millions	Dec. 30, 2013	Sep. 30, 2018	Apr. 30, 2018	Jun. 30, 2016	Dec. 31, 2019	Dec. 31, 2015
Retired power plant costs
Acquisition
Regulatory asset, net book value					$ 73
Navajo Plant
Acquisition
Regulatory asset, net book value					$ 82
SCE | Four Corners
Acquisition
Regulatory assets						$ 12
Regulatory assets, write of amount				$ 12
Four Corners Units 4 and 5 | SCE
Acquisition
Transmission termination agreement net receipt due to negotiation of alternate arrangement	$ 40
Settlement agreement, ACC approved rate adjustment, annualized customer impact		$ 58.5	$ 67.5

Regulatory Matters - Schedule o

Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Detail of regulatory assets
Regulatory assets, current	$ 203,207	$ 166,902
Regulatory assets, non-current	1,304,073	1,342,941
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	660,223	733,351
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	28,182	28,182
Regulatory assets, non-current	142,503	167,164
Income taxes - AFUDC equity
Detail of regulatory assets
Regulatory assets, current	6,800	6,457
Regulatory assets, non-current	154,974	151,467
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	70,137	37,164
Regulatory assets, non-current	0	0
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	36,887	31,728
Regulatory assets, non-current	33,185	23,768
Property tax deferral
Detail of regulatory assets
Regulatory assets, current	8,569	8,569
Regulatory assets, non-current	58,196	66,356
SCR deferral
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	52,644	23,276
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	8,077	8,077
Regulatory assets, non-current	32,152	40,228
Lost fixed cost recovery (b)
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	38,144	0
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	36,464	36,523
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,098	1,079
Regulatory assets, non-current	24,981	25,522
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	26,067	32,435
Regulatory assets, non-current	0	0
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	20,635	20,015
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	1,546	1,546
Regulatory assets, non-current	17,688	15,607
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,637	1,637
Regulatory assets, non-current	12,031	13,668
Mead-Phoenix transmission line - contributions in aid of construction
Detail of regulatory assets
Regulatory assets, current	332	332
Regulatory assets, non-current	9,712	10,044
TCA balancing account
Detail of regulatory assets
Regulatory assets, current	6,324	3,860
Regulatory assets, non-current	2,885	772
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,235	1,235
Regulatory assets, non-current	4,940	6,176
AG-1 deferral
Detail of regulatory assets
Regulatory assets, current	2,787	2,654
Regulatory assets, non-current	2,716	5,819
Tax expense adjustor mechanism
Detail of regulatory assets
Regulatory assets, current	1,612	0
Regulatory assets, non-current	0	0
Other
Detail of regulatory assets
Regulatory assets, current	1,917	1,947
Regulatory assets, non-current	$ 0	$ 3,185

Regulatory Matters - Schedule_2

Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Detail of regulatory liabilities
Regulatory liabilities, current	$ 234,912	$ 165,876
Regulatory liabilities, non-current	2,267,835	2,325,976
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	418,423	278,585
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	47,356	39,866
Regulatory liabilities, non-current	136,072	177,533
Other postretirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	37,575	37,864
Regulatory liabilities, non-current	139,634	125,903
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	2,797	2,769
Regulatory liabilities, non-current	68,265	70,069
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	6,676	6,503
Regulatory liabilities, non-current	51,019	57,002
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	1,059	1,858
Regulatory liabilities, non-current	51,704	17,871
Income taxes - deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	2,202	2,164
Regulatory liabilities, non-current	50,034	51,120
Renewable energy program
Detail of regulatory liabilities
Regulatory liabilities, current	39,287	44,966
Regulatory liabilities, non-current	10,300	20
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	15,024	14,604
Regulatory liabilities, non-current	24,146	4,123
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	5,698	1,278
Regulatory liabilities, non-current	11,319	17,228
Property tax deferral
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	7,046	2,611
Tax expense adjustor mechanism
Detail of regulatory liabilities
Regulatory liabilities, current	7,018	3,237
Regulatory liabilities, non-current	0	0
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,423	4,423
Regulatory liabilities, non-current	4,163	6,581
FERC transmission true up
Detail of regulatory liabilities
Regulatory liabilities, current	1,045	0
Regulatory liabilities, non-current	2,004	0
Other
Detail of regulatory liabilities
Regulatory liabilities, current	532	42
Regulatory liabilities, non-current	2,296	930
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
Detail of regulatory liabilities
Regulatory liabilities, current	59,918	0
Regulatory liabilities, non-current	1,054,053	1,272,709
FERC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
Detail of regulatory liabilities
Regulatory liabilities, current	6,302	6,302
Regulatory liabilities, non-current	$ 237,357	$ 243,691

Income Taxes (Details)

Income Taxes (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2017	Sep. 30, 2019	Dec. 31, 2018
Income Taxes
Reduction in net deferred income tax liabilities				$ 1,140,000,000
Income tax benefit	$ 57,000,000	$ 62,000,000
Deferred Tax Liabilities, Gross	2,897,248,000	2,897,248,000	$ 2,897,248,000		$ 56,000,000	$ 2,702,353,000
Amortization period			28 years 6 months
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less than)	1,000,000	1,000,000	$ 1,000,000
General business tax credit carryforwards	62,000,000	62,000,000	62,000,000
increase (decrease) in deferred income taxes due to regulation adoption			39,000,000
Income tax expense benefit attributable to non controlling interests			0
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Deferred Tax Liabilities, Gross	2,896,814,000	2,896,814,000	2,896,814,000			$ 2,701,930,000
State
Income Taxes
Amount of state loss carryforwards	23,000,000	23,000,000	23,000,000
Federal
Income Taxes
Amount of state loss carryforwards	$ 9,000,000	$ 9,000,000	$ 9,000,000

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	$ 40,731	$ 41,966	$ 36,075
Additions for tax positions of the current year	3,373	3,436	2,937
Additions for tax positions of prior years	1,843	2,696	4,783
Reductions for tax positions of prior years for:
Changes in judgment	(2,078)	(1,764)	(1,829)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	(434)	(5,603)	0
Total unrecognized tax benefits, end of the year	43,435	40,731	41,966
ARIZONA PUBLIC SERVICE COMPANY
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	40,731	41,966	36,075
Additions for tax positions of the current year	3,373	3,436	2,937
Additions for tax positions of prior years	1,843	2,696	4,783
Reductions for tax positions of prior years for:
Changes in judgment	(2,078)	(1,764)	(1,829)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	(434)	(5,603)	0
Total unrecognized tax benefits, end of the year	$ 43,435	$ 40,731	$ 41,966

Income Taxes - Summary of Unrec

Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	$ 22,813	$ 19,504	$ 16,373
Unrecognized tax benefit interest expense/(benefit) recognized	459	(780)	577
Unrecognized tax benefit interest accrued	1,589	1,130	1,910
ARIZONA PUBLIC SERVICE COMPANY
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	22,813	19,504	16,373
Unrecognized tax benefit interest expense/(benefit) recognized	459	(780)	577
Unrecognized tax benefit interest accrued	$ 1,589	$ 1,130	$ 1,910

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal									$ (13,551)	$ 18,375	$ 11,624
State									3,195	3,342	3,052
Total current									(10,356)	21,717	14,676
Deferred:
Federal									(14,982)	94,721	223,729
State									9,565	17,464	19,867
Total deferred									(5,417)	112,185	243,596
Income tax expense/(benefit)	$ (88,537)	$ 53,266	$ 17,080	$ 2,418	$ 6,795	$ 84,333	$ 44,039	$ (1,265)	(15,773)	133,902	258,272
ARIZONA PUBLIC SERVICE COMPANY
Current:
Federal									(54,697)	88,180	21,512
State									695	1,877	2,778
Total current									(54,002)	90,057	24,290
Deferred:
Federal									29,321	32,436	221,078
State									15,109	22,321	23,800
Total deferred									44,430	54,757	244,878
Income tax expense/(benefit)									$ (9,572)	$ 144,814	$ 269,168

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at statutory rate									$ 113,828	$ 139,533	$ 268,177
State income tax net of federal income tax benefit									18,599	23,115	21,380
State income tax credits net of federal income tax benefit									(8,519)	(6,704)	(6,483)
Nondeductible expenditures associated with ballot initiative									0	7,879	0
Stock compensation									(2,252)	(1,804)	(6,659)
Excess deferred income taxes - Tax Cuts and Jobs Act									(124,082)	(6,725)	9,348
Allowance for equity funds used during construction (see Note 1)									(2,476)	(7,231)	(12,937)
Palo Verde VIE noncontrolling interest (see Note 19)									(4,094)	(4,094)	(6,823)
Investment tax credit amortization									(6,851)	(6,742)	(6,715)
Other									74	(3,325)	(1,016)
Income tax expense/(benefit)	$ (88,537)	$ 53,266	$ 17,080	$ 2,418	$ 6,795	$ 84,333	$ 44,039	$ (1,265)	(15,773)	133,902	258,272
ARIZONA PUBLIC SERVICE COMPANY
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at statutory rate									120,790	154,260	277,540
State income tax net of federal income tax benefit									19,267	24,531	22,329
State income tax credits net of federal income tax benefit									(6,781)	(5,440)	(5,053)
Nondeductible expenditures associated with ballot initiative									0	0	0
Stock compensation									(1,054)	(780)	(3,489)
Excess deferred income taxes - Tax Cuts and Jobs Act									(124,082)	(4,715)	9,431
Allowance for equity funds used during construction (see Note 1)									(2,476)	(7,231)	(12,937)
Palo Verde VIE noncontrolling interest (see Note 19)									(4,094)	(4,094)	(6,823)
Investment tax credit amortization									(6,851)	(6,742)	(6,715)
Other									(4,291)	(4,975)	(5,115)
Income tax expense/(benefit)									$ (9,572)	$ 144,814	$ 269,168

Income Taxes - Components of De

Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
DEFERRED TAX ASSETS
Risk management activities	$ 17,552		$ 15,785
Regulatory liabilities:
Excess deferred income taxes - Tax Cuts and Jobs Act	335,877		376,869
Asset retirement obligation and removal costs	143,011		117,201
Unamortized investment tax credits	52,236		53,284
Other postretirement liabilities	43,841		40,532
Other	52,382		40,380
Pension liabilities	73,210		112,019
Coal reclamation liabilities	40,837		47,508
Renewable energy incentives	28,066		30,779
Credit and loss carryforwards	54,795		1,755
Other	63,102		58,820
Total deferred tax assets	904,909		894,932
DEFERRED TAX LIABILITIES
Plant-related	(2,448,458)		(2,277,724)
Risk management activities	(27)		(237)
Other postretirement assets and other special use funds	(66,399)		(57,697)
Regulatory assets:
Allowance for equity funds used during construction	(40,023)		(39,086)
Deferred fuel and purchased power	(35,162)		(23,086)
Pension benefits	(163,339)		(181,504)
Retired power plant costs (see Note 4)	(42,228)		(48,348)
Other	(82,722)		(72,096)
Other	(18,890)		(2,575)
Total deferred tax liabilities	(2,897,248)	$ (56,000)	(2,702,353)
Deferred income taxes — net	(1,992,339)		(1,807,421)
ARIZONA PUBLIC SERVICE COMPANY
DEFERRED TAX ASSETS
Risk management activities	17,552		15,785
Regulatory liabilities:
Excess deferred income taxes - Tax Cuts and Jobs Act	335,877		376,869
Asset retirement obligation and removal costs	143,011		117,201
Unamortized investment tax credits	52,236		53,284
Other postretirement liabilities	43,841		40,532
Other	52,382		40,380
Pension liabilities	67,976		107,009
Coal reclamation liabilities	40,837		47,508
Renewable energy incentives	28,066		30,779
Credit and loss carryforwards	10,992		0
Other	70,948		59,919
Total deferred tax assets	863,718		889,266
DEFERRED TAX LIABILITIES
Plant-related	(2,448,458)		(2,277,724)
Risk management activities	(27)		(237)
Other postretirement assets and other special use funds	(65,965)		(57,274)
Regulatory assets:
Allowance for equity funds used during construction	(40,023)		(39,086)
Deferred fuel and purchased power	(35,162)		(23,086)
Pension benefits	(163,339)		(181,504)
Retired power plant costs (see Note 4)	(42,228)		(48,348)
Other	(82,722)		(72,096)
Other	(18,890)		(2,575)
Total deferred tax liabilities	(2,896,814)		(2,701,930)
Deferred income taxes — net	$ (2,033,096)		$ (1,812,664)

Lines of Credit and Short-Ter_3

Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pinnacle West
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.125%	0.125%
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.10%	0.10%
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Commitments under Credit Facilities	$ 1,200,000	$ 1,350,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(76,675)	(76,400)
Amount of Credit Facilities Available	1,123,325	1,273,600
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Commitments under Credit Facilities	200,000	350,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(76,675)	(76,400)
Amount of Credit Facilities Available	123,325	273,600
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commitments under Credit Facilities	1,000,000	1,000,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	0	0
Amount of Credit Facilities Available	$ 1,000,000	$ 1,000,000

Lines of Credit and Short-Ter_4

Lines of Credit and Short-Term Borrowings (Details)	May 09, 2019USD ($)	Dec. 31, 2019USD ($)Facility	Dec. 31, 2018USD ($)	Nov. 27, 2018USD ($)
ARIZONA PUBLIC SERVICE COMPANY | ACC
Debt Provisions
Percentage of APS's capitalization used in calculation of short-term debt authorization				7.00%
Required amount to be used in purchases of natural gas and power which is used in calculation of short-term debt authorization				$ 500,000,000
Term loan | Pinnacle West
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	$ 50,000,000
Long-term line of credit		$ 38,000,000
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Long-term line of credit		76,675,000	$ 76,400,000
Amount committed		1,200,000,000	1,350,000,000
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Long-term line of credit		76,675,000	76,400,000
Amount committed		200,000,000	350,000,000
Revolving credit facility | Pinnacle West | Revolving Credit Facility Maturing June 2019
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	$ 150,000,000
Revolving credit facility | Pinnacle West | Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		300,000,000
Long-term line of credit		0
Amount committed		200,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Long-term line of credit		0	0
Amount committed		1,000,000,000	$ 1,000,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing June 2022
Lines of Credit and Short-Term Borrowings
Amount committed		500,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Amount committed		500,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving Credit Facility Maturing in 2022 and 2023
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		1,400,000,000
Long-term line of credit		0
Amount committed		$ 1,000,000,000
Number of credit facilities | Facility		2
Additional capacity increase available		$ 700,000,000
Letter of credit | Pinnacle West | Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit		0
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit		1,700,000
Commercial paper | Pinnacle West | Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Commercial paper		77,000,000
Commercial paper | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Maximum commercial paper support available under credit facility		500,000,000
Commercial paper | ARIZONA PUBLIC SERVICE COMPANY | Revolving Credit Facility Maturing in 2022 and 2023
Lines of Credit and Short-Term Borrowings
Commercial paper		$ 0
LIBOR | Term loan | Pinnacle West
Lines of Credit and Short-Term Borrowings
Debt instrument, basis spread on variable rate	0.55%

Long-Term Debt and Liquidity _3

Long-Term Debt and Liquidity Matters (Details) - USD ($)	Jan. 15, 2020	Dec. 31, 2019	May 09, 2019	Mar. 01, 2019	Feb. 26, 2019	Nov. 20, 2019	Aug. 19, 2019	Feb. 28, 2019	Nov. 27, 2018
Maximum
Debt Provisions
Ratio of consolidated debt to consolidated capitalization (as a percent)		65.00%
Pinnacle West
Debt Provisions
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)		52.00%
Pinnacle West | Term loan
Long-Term Debt and Liquidity Matters [Line Items]
Maximum borrowing capacity on credit facility			$ 50,000,000
ARIZONA PUBLIC SERVICE COMPANY | Term loan
Long-Term Debt and Liquidity Matters [Line Items]
Maximum borrowing capacity on credit facility					$ 200,000,000
ARIZONA PUBLIC SERVICE COMPANY
Debt Provisions
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)		47.00%
ARIZONA PUBLIC SERVICE COMPANY | ACC
Debt Provisions
Long term debt authorization		$ 5,900,000,000							$ 5,100,000,000
ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Extinguishment of debt				$ 500,000,000
Interest rate (as a percent)				8.75%
Senior unsecured notes | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)		2.25%
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)		6.88%
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)		2.20%
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Extinguishment of debt		$ 100,000,000
Notes issued						$ 300,000,000	$ 300,000,000	$ 300,000,000
Interest rate (as a percent)						3.50%	2.60%	4.25%
Subsequent Event | Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Extinguishment of debt	$ 150,000,000
Notes issued	$ 250,000,000
LIBOR | Pinnacle West | Term loan
Long-Term Debt and Liquidity Matters [Line Items]
Debt instrument, basis spread on variable rate			0.55%
LIBOR | ARIZONA PUBLIC SERVICE COMPANY | Term loan
Long-Term Debt and Liquidity Matters [Line Items]
Debt instrument, basis spread on variable rate					0.50%

Long-Term Debt and Liquidity _4

Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Long-Term Debt and Liquidity Matters [Line Items]
Total long-term debt	$ 5,632,558	$ 5,138,232
Long-term debt less current maturities (Note 7)	4,832,558	4,638,232
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	5,676,125
Unamortized discount	(57)	(121)
Unamortized debt issue costs	(518)	(1,083)
Total long-term debt	449,425	448,796
Less current maturities	450,000	0
Total long-term debt less current maturities	(575)	448,796
Long-term debt less current maturities (Note 7)	(575)	448,796
ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	5,226,125
Unamortized discount	(12,434)	(12,638)
Unamortized premium	7,423	7,736
Unamortized debt issue costs	(37,981)	(31,787)
Total long-term debt	5,183,133	4,689,436
Less current maturities	350,000	500,000
Total long-term debt less current maturities	4,833,133	4,189,436
Long-term debt less current maturities (Note 7)	4,833,133	4,189,436
Pollution Control Bonds - Variable | ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 35,975	$ 35,975
Pollution Control Bonds - Variable | ARIZONA PUBLIC SERVICE COMPANY | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	1.54%	1.76%
Pollution Control Bonds - Fixed | ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 115,150	$ 115,150
Pollution Control Bonds - Fixed | ARIZONA PUBLIC SERVICE COMPANY | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	4.70%
Total Pollution Control Bonds | ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 151,125	151,125
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 4,875,000	4,575,000
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	2.20%
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	6.88%
Senior unsecured notes | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 300,000	300,000
Interest rate (as a percent)	2.25%
Term loan | Term loans | ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Term loans	$ 200,000	0
Term loan | Term Loan Facility Maturing 2020 | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Term loans	$ 150,000	$ 150,000
Weighted-average interest rate (as a percent)	2.20%	3.02%
Term loan | Term Loan Facility Maturing 2020 | ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	2.12%

Long-Term Debt and Liquidity _5

Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Pinnacle West
Principal payments due on long-term debt
2020	$ 800,000
2021	0
2022	0
2023	0
2024	365,150
Thereafter	4,510,975
Total	5,676,125
ARIZONA PUBLIC SERVICE COMPANY
Principal payments due on long-term debt
2020	350,000
2021	0
2022	0
2023	0
2024	365,150
Thereafter	4,510,975
Total	$ 5,226,125

Long-Term Debt and Liquidity _6

Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 5,632,558	$ 5,138,232
Fair Value	6,194,392	5,233,563
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	449,425	448,796
Fair Value	450,822	443,955
ARIZONA PUBLIC SERVICE COMPANY
Estimated fair value of long-term debt, including current maturities
Carrying Amount	5,183,133	4,689,436
Fair Value	$ 5,743,570	$ 4,789,608

Retirement Plans and Other Be_3

Retirement Plans and Other Benefits Retirement Plans and Other Benefits - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Partnership funding commitments, contribution amount (up to)	$ 50,000,000
Partnership funding commitments, funded amount	$ 38,000,000
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Funded percentage (more than)	100.00%
Expected long-term return on plan assets for next fiscal year (as a percent)	5.75%
Contributions
Employer contributions	$ 150,000,000	$ 50,000,000	$ 100,000,000
Minimum contributions under MAP-21
Minimum contributions under MAP-21	0
Voluntary employer contributions over next three years (up to)	$ 100,000,000
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets for next fiscal year (as a percent)	5.00%
Contributions
Employer contributions	$ 0	0
Minimum contributions under MAP-21
Retiree medical cost reimbursement	30,000,000	72,000,000
Pinnacle West
Employee savings plan benefits
Expenses recorded for the defined contribution savings plan	$ 11,000,000	$ 11,000,000	10,000,000
ARIZONA PUBLIC SERVICE COMPANY
Employee savings plan benefits
APS's employees share of total cost of the plans (as a percent)	99.00%
ARIZONA PUBLIC SERVICE COMPANY | Other Benefits
Contributions
Employer contributions			$ 1,000,000

Retirement Plans and Other Be_4

Retirement Plans and Other Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net periodic benefit costs and the portion of these costs charged to expense
Portion of cost charged to expense	$ (22,989)	$ (49,791)	$ (24,664)
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost-benefits earned during the period	49,902	56,669	54,858
Interest cost on benefit obligation	136,843	124,689	129,756
Expected return on plan assets	(171,884)	(182,853)	(174,271)
Amortization of prior service cost (credit)	0	0	81
Amortization of net actuarial loss	42,584	32,082	47,900
Net periodic benefit cost (benefit)	57,445	30,587	58,324
Portion of cost charged to expense	30,312	10,120	27,295
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost-benefits earned during the period	18,369	21,100	17,119
Interest cost on benefit obligation	29,894	28,147	29,959
Expected return on plan assets	(38,412)	(42,082)	(53,401)
Amortization of prior service cost (credit)	(37,821)	(37,842)	(37,842)
Amortization of net actuarial loss	0	0	5,118
Net periodic benefit cost (benefit)	(27,970)	(30,677)	(39,047)
Portion of cost charged to expense	$ (19,859)	$ (21,426)	$ (18,274)

Retirement Plans and Other Be_5

Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	$ 3,190,626	$ 3,394,186
Service cost	49,902	56,669	$ 54,858
Interest cost	136,843	124,689	129,756
Benefit payments	(177,882)	(184,161)
Actuarial (gain) loss	413,625	(200,757)
Benefit obligation at the end of the period	3,613,114	3,190,626	3,394,186
Change in Plan Assets
Balance at the beginning of the period	2,733,476	3,057,027
Actual return on plan assets	602,030	(201,078)
Employer contributions	150,000	50,000	100,000
Benefit payments	(167,155)	(172,473)
Transfer to active union medical account	0	0
Balance at the end of the period	3,318,351	2,733,476	3,057,027
Funded Status at the end of the period	(294,763)	(457,150)
Other Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	676,771	753,393
Service cost	18,369	21,100	17,119
Interest cost	29,894	28,147	29,959
Benefit payments	(32,486)	(31,540)
Actuarial (gain) loss	54,376	(94,329)
Benefit obligation at the end of the period	746,924	676,771	753,393
Change in Plan Assets
Balance at the beginning of the period	723,677	1,022,371
Actual return on plan assets	144,095	(40,354)
Employer contributions	0	0
Benefit payments	(30,278)	(72,453)
Transfer to active union medical account	0	(185,887)
Balance at the end of the period	837,494	723,677	$ 1,022,371
Funded Status at the end of the period	$ 90,570	$ 46,906

Retirement Plans and Other Be_6

Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
Projected benefit obligation	$ 177,775	$ 3,190,626
Accumulated benefit obligation	169,091	3,038,774
Fair value of plan assets	$ 0	$ 2,733,476

Retirement Plans and Other Be_7

Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	$ 90,570	$ 46,906
Pension Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	0	0
Current liability	(14,578)	(13,980)
Noncurrent liability	(280,185)	(443,170)
Net amount recognized	(294,763)	(457,150)
Other Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	90,570	46,906
Current liability	0	0
Noncurrent liability	0	0
Net amount recognized	$ 90,570	$ 46,906

Retirement Plans and Other Be_8

Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	$ 735,186	$ 794,292
Prior service credit	0	0
APS’s portion recorded as a regulatory (asset) liability	(660,223)	(733,351)
Income tax expense (benefit)	(18,546)	(15,083)
Accumulated other comprehensive loss	56,417	45,858
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	33,642
Prior service credit	0
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2020	33,642
Other Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	12,238	63,544
Prior service credit	(189,912)	(227,733)
APS’s portion recorded as a regulatory (asset) liability	177,209	163,767
Income tax expense (benefit)	570	561
Accumulated other comprehensive loss	105	$ 139
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	0
Prior service credit	(37,575)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2020	$ (37,575)

Retirement Plans and Other Be_9

Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Weighted-average assumptions used to determine benefit obligations
Rate of compensation increase (as a percent)	4.00%	4.00%
Initial pre-65 healthcare cost trend rate (as a percent)	7.00%	7.00%
Initial post-65 healthcare cost trend rate (as a percent)	4.75%	4.75%
Ultimate health care cost trend rate (as a percent)	4.75%	4.75%
Number of years to ultimate trend rate (pre-65 participants)	6 years	7 years
Weighted-average assumptions used to determine net periodic benefit costs
Initial pre-65 health care cost trend rate (as a percent)	7.00%	7.00%	7.00%
Initial post-65 health care cost trend rate (as a percent)	4.75%	4.75%	5.00%
Ultimate healthcare cost trend rate (as a percent)	4.75%	4.75%	5.00%
Number of years to ultimate trend rate (pre-65 participants)	7 years	8 years	4 years
Pension Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	3.30%	4.34%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.34%	3.65%	4.08%
Rate of compensation increase (as a percent)	4.00%	4.00%	4.00%
Expected long-term return on plan assets (as a percent)	6.25%	6.05%	6.55%
Other Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	3.42%	4.39%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.39%	3.71%	4.17%
Expected long-term return on plan assets (as a percent)	5.40%	5.40%	6.05%
Effects of one percentage point change in the assumed initial and ultimate health care cost trend rates
Effect of 1% increase on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$ 9,299
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	(3,827)
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs	9,434
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs	(7,257)
Effect of 1% increase on the accumulated other postretirement benefit obligation	124,073
Effect of 1% decrease on the accumulated other postretirement benefit obligation	$ (97,710)

Retirement Plans and Other B_10

Retirement Plans and Other Benefits - Asset Allocation (Details)	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Actual Allocation	100.00%
Pension Benefits | Long-term fixed income assets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	62.00%
Actual Allocation	63.00%
Pension Benefits | Return-generating assets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	38.00%
Target Allocation	38.00%
Actual Allocation	37.00%
Pension Benefits | Equities in US and other developed markets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	18.00%
Pension Benefits | Equities in emerging markets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	6.00%
Pension Benefits | Alternative investments
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	14.00%
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	100.00%
Other Benefits | Long-term fixed income assets
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	68.00%
Other Benefits | Return-generating assets
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	32.00%

Retirement Plans and Other B_11

Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	$ 832,143	$ 726,093
Fair value of plan assets	3,318,351	2,733,476	$ 3,057,027
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	852,239	690,737
Pension Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,633,969	1,316,646
Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	107,473	90,955
Fair value of plan assets	837,494	723,677	$ 1,022,371
Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	519,382	461,905
Other Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	210,639	170,817
Cash and cash equivalents | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	9,370	451
Cash and cash equivalents | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	9,370	451
Cash and cash equivalents | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	2,184	93
Cash and cash equivalents | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	2,184	93
Corporate | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	1,541,729	1,237,744
Corporate | Pension Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,541,729	1,237,744
Corporate | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	202,640	163,286
Corporate | Other Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	202,640	163,286
U.S. Treasury | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	406,112	372,649
U.S. Treasury | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	406,112	372,649
U.S. Treasury | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	353,650	318,017
U.S. Treasury | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	353,650	318,017
Other fixed income | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	92,240	78,902
Other fixed income | Pension Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	92,240	78,902
Other fixed income | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	7,999	7,531
Other fixed income | Other Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	7,999	7,531
Common stock equities | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	250,829	196,661
Common stock equities | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	250,829	196,661
Common stock equities | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	146,316	129,199
Common stock equities | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	146,316	129,199
Mutual funds | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	185,928	120,976
Mutual funds | Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	185,928	120,976
Mutual funds | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	14,351	10,963
Mutual funds | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	14,351	10,963
Equities | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	392,403	272,926
Fair value of plan assets	392,403	272,926
Equities | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	83,648	65,720
Fair value of plan assets	83,648	65,720
Real estate | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	171,645	165,123
Fair value of plan assets	171,645	165,123
Real estate | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	19,806	19,054
Fair value of plan assets	19,806	19,054
Fixed income securities | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	98,065	86,483
Fair value of plan assets	98,065	86,483
Partnerships | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	103,796	125,217
Fair value of plan assets	103,796	125,217
Short-term investments and other | Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	66,234	76,344
Fair value of plan assets	66,234	76,344
Short-term investments and other | Pension Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	0
Short-term investments and other | Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	4,019	6,181
Fair value of plan assets	6,900	9,814
Short-term investments and other | Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	2,881	3,633
Short-term investments and other | Other Benefits | Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	$ 0	$ 0

Retirement Plans and Other B_12

Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Pension Benefits
Estimated Future Benefit Payments
2020	$ 199,395
2021	201,597
2022	206,618
2023	213,208
2024	218,150
Years 2025-2029	1,111,171
Other Benefits
Estimated Future Benefit Payments
2020	31,531
2021	32,777
2022	33,566
2023	34,415
2024	34,468
Years 2025-2029	$ 174,607

Leases - Additional information

Leases - Additional information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)Counterparty	Jan. 01, 2019USD ($)
Operating Leased Assets [Line Items]
Number of lease agreements | Counterparty			3
Operating lease right-of-use assets (Note 16)	$ 0		$ 145,813	$ 194,000
Operating lease, liability			64,585	119,000
Other	(129,312)		(33,400)
Other current liabilities	184,229		168,323
Lease not yet commenced			705,000
Operating lease, expense	18,000	$ 18,000
Accounting Standards Update 2016-02
Operating Leased Assets [Line Items]
Other				85,000
Other current liabilities				$ (10,000)
Purchased Power Lease Contracts
Operating Leased Assets [Line Items]
Operating lease, liability			$ 0
Operating lease, expense	47,000	60,000
Contingent rentals	$ 109,000	$ 100,000

Leases - Lease costs (Details)

Leases - Lease costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Operating Leased Assets [Line Items]
Operating lease cost	$ 60,228
Variable lease cost	114,015
Short-term lease cost	4,385
Total lease cost	178,628
Purchased Power Lease Contracts
Operating Leased Assets [Line Items]
Operating lease cost	42,190
Variable lease cost	113,233
Short-term lease cost	0
Total lease cost	155,423
Land, Property & Equipment Leases
Operating Leased Assets [Line Items]
Operating lease cost	18,038
Variable lease cost	782
Short-term lease cost	4,385
Total lease cost	$ 23,205

Leases - Maturity of our operat

Leases - Maturity of our operating lease liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
2020	$ 14,698
2021	11,963
2022	8,331
2023	6,326
2024	4,141
Thereafter	38,697
Total lease commitments	84,156
Less imputed interest	19,571
Total lease liabilities	64,585	$ 119,000
Purchased Power Lease Contracts
Lessee, Lease, Description [Line Items]
2020	0
2021	0
2022	0
2023	0
2024	0
Thereafter	0
Total lease commitments	0
Less imputed interest	0
Total lease liabilities	0
Land, Property & Equipment Leases
Lessee, Lease, Description [Line Items]
2020	14,698
2021	11,963
2022	8,331
2023	6,326
2024	4,141
Thereafter	38,697
Total lease commitments	84,156
Less imputed interest	19,571
Total lease liabilities	$ 64,585

Leases - Future minimum operati

Leases - Future minimum operating lease (Details) $ in Thousands	Dec. 31, 2018USD ($)
Lessee, Lease, Description [Line Items]
2019	$ 68,246
2020	12,428
2021	9,478
2022	6,513
2023	5,359
Thereafter	42,236
Total future lease commitments	144,260
Purchased Power Lease Contracts
Lessee, Lease, Description [Line Items]
2019	54,499
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total future lease commitments	54,499
Land, Property & Equipment Leases
Lessee, Lease, Description [Line Items]
2019	13,747
2020	12,428
2021	9,478
2022	6,513
2023	5,359
Thereafter	42,236
Total future lease commitments	$ 89,761

Leases - Other additional infor

Leases - Other additional information related to operating lease liabilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Weighted average remaining lease term	13 years
Weighted average discount rate (a)	3.71%
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows	$ 69,075

Jointly-Owned Facilities (Detai

Jointly-Owned Facilities (Details) - ARIZONA PUBLIC SERVICE COMPANY $ in Thousands	Dec. 31, 2019USD ($)
Palo Verde Units 1 and 3
Interests in jointly-owned facilities
Percent Owned	29.10%
Plant in Service	$ 1,877,748
Accumulated Depreciation	1,102,609
Construction work in progress	$ 22,071
Palo Verde Unit 2
Interests in jointly-owned facilities
Percent Owned	16.80%
Plant in Service	$ 634,545
Accumulated Depreciation	377,722
Construction work in progress	$ 11,831
Palo Verde Common
Interests in jointly-owned facilities
Percent Owned	28.00%
Plant in Service	$ 746,653
Accumulated Depreciation	290,084
Construction work in progress	46,570
Palo Verde Sale Leaseback
Interests in jointly-owned facilities
Plant in Service	351,050
Accumulated Depreciation	249,144
Construction work in progress	$ 0
Four Corners Generating Station
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	$ 1,520,171
Accumulated Depreciation	559,272
Construction work in progress	$ 44,842
Cholla Common Facilities
Interests in jointly-owned facilities
Percent Owned	50.50%
Plant in Service	$ 184,608
Accumulated Depreciation	95,720
Construction work in progress	$ 1,323
ANPP 500kV System
Interests in jointly-owned facilities
Percent Owned	33.50%
Plant in Service	$ 133,396
Accumulated Depreciation	51,248
Construction work in progress	$ 2,723
Navajo Southern System
Interests in jointly-owned facilities
Percent Owned	26.70%
Plant in Service	$ 89,672
Accumulated Depreciation	31,985
Construction work in progress	$ 194
Palo Verde — Yuma 500kV System
Interests in jointly-owned facilities
Percent Owned	19.00%
Plant in Service	$ 15,274
Accumulated Depreciation	6,486
Construction work in progress	$ 4,886
Four Corners Switchyards
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	$ 69,994
Accumulated Depreciation	16,674
Construction work in progress	$ 2,395
Phoenix — Mead System
Interests in jointly-owned facilities
Percent Owned	17.10%
Plant in Service	$ 39,355
Accumulated Depreciation	18,570
Construction work in progress	$ 53
Palo Verde — Rudd 500kV System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 93,112
Accumulated Depreciation	26,719
Construction work in progress	$ 317
Morgan — Pinnacle Peak System
Interests in jointly-owned facilities
Percent Owned	64.60%
Plant in Service	$ 117,752
Accumulated Depreciation	18,822
Construction work in progress	$ 0
Round Valley System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 515
Accumulated Depreciation	164
Construction work in progress	$ 0
Palo Verde — Morgan System
Interests in jointly-owned facilities
Percent Owned	88.90%
Plant in Service	$ 238,689
Accumulated Depreciation	13,146
Construction work in progress	$ 0
Hassayampa — North Gila System
Interests in jointly-owned facilities
Percent Owned	80.00%
Plant in Service	$ 143,422
Accumulated Depreciation	12,676
Construction work in progress	$ 0
Cholla 500kV Switchyard
Interests in jointly-owned facilities
Percent Owned	85.70%
Plant in Service	$ 7,651
Accumulated Depreciation	1,597
Construction work in progress	$ 535
Saguaro 500kV Switchyard
Interests in jointly-owned facilities
Percent Owned	60.00%
Plant in Service	$ 20,425
Accumulated Depreciation	12,949
Construction work in progress	$ 0
Kyrene — Knox System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 578
Accumulated Depreciation	315
Construction work in progress	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)	Feb. 11, 2020USD ($)	Oct. 31, 2019USD ($)	Dec. 31, 2019USD ($)Trust	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jun. 30, 2018USD ($)claim	Dec. 31, 1986Trust
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
Total obligation			$ 165,695,000	$ 212,785,000
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Maximum insurance against public liability per occurrence for a nuclear incident			13,900,000,000
Maximum available nuclear liability insurance			450,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program			13,500,000,000
Maximum assessment per reactor for each nuclear incident			137,600,000
Annual limit per incident with respect to maximum assessment			$ 20,500,000
Number of VIE lessor trusts | Trust			3				3
Maximum potential retrospective assessment per incident of APS			$ 120,100,000
Annual payment limitation with respect to maximum potential retrospective assessment			17,900,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde			2,800,000,000
Request second-year energy price for exported energy			$ 25,500,000
Period to provide collateral assurance based on rating triggers			20 days
Collateral assurance based on rating triggers			$ 73,400,000
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2020			590,000,000
2021			613,000,000
2022			624,000,000
2023			616,000,000
2024			581,000,000
Thereafter			5,500,000,000
Total obligation			165,695,000	212,785,000
ARIZONA PUBLIC SERVICE COMPANY | Coal take-or-pay commitments
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2020			185,347,000
2021			186,554,000
2022			187,400,000
2023			189,120,000
2024			193,192,000
Thereafter			1,240,964,000
Total obligation			2,200,000,000
Present value of commitments			1,600,000,000
Total purchases			204,888,000	206,093,000	$ 165,220,000
ARIZONA PUBLIC SERVICE COMPANY | Renewable energy credits
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2020			36,000,000
2021			35,000,000
2022			31,000,000
2023			30,000,000
2024			28,000,000
Thereafter			133,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2020			17,000,000
2021			16,000,000
2022			17,000,000
2023			18,000,000
2024			19,000,000
Thereafter			88,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Balance Sheet Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
Total obligation			$ 166,000,000	$ 213,000,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company		$ 16,000,000				$ 84,300,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company		$ 4,700,000				$ 24,500,000
Gain contingency, new claims filed, number | claim						5
Subsequent Event | Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company	$ 15,400,000
Subsequent Event | Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company	$ 4,500,000

Commitments and Contingencies_2

Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) - ARIZONA PUBLIC SERVICE COMPANY - Contaminated groundwater wells $ in Millions	Apr. 05, 2018plaintiffDefendant	Dec. 16, 2016plaintiff	Aug. 06, 2013Defendant	Dec. 31, 2019USD ($)
Commitments and Contingencies [Line Items]
Costs related to investigation and study under Superfund site | $				$ 2
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit | Defendant	28		24
Number of plaintiffs		2
Settled Litigation
Commitments and Contingencies [Line Items]
Number of plaintiffs	2

Commitments and Contingencies_3

Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($) $ in Millions	Jul. 03, 2018	Jul. 06, 2016	Dec. 31, 2019
Financial Assurances
Equity contribution guarantees			$ 40
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit			1.7
Four Corners | NTEC
Environmental Matters [Abstract]
Option to purchase, ownership interest (as a percent)	7.00%	7.00%
Payment received for coal supply agreement	$ 70
Four Corners | 4CA
Environmental Matters [Abstract]
Percentage share cost of control		7.00%
Four Corners | Coal Supply Agreement Arbitration | NTEC
Environmental Matters [Abstract]
Option to purchase, ownership interest (as a percent)		7.00%
Four Corners | Coal Supply Agreement Arbitration | 4CA
Environmental Matters [Abstract]
Asset purchase agreement			$ 10
Regional Haze Rules | Four Corners Units 4 and 5 | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Percentage share cost of control			63.00%
Expected environmental cost			$ 400
Regional Haze Rules | Four Corners Units 4 and 5 | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			$ 45
Regional Haze Rules | Four Corners Units 4 and 5 | Natural Gas Tolling Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional percentage share of cost of control			7.00%
Coal Combustion Waste | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			$ 22
Coal Combustion Waste | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			1
Coal Combustion Waste | Minimum | Cholla | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			15
Coal Combustion Waste | Minimum | Cholla and Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			10
Coal Combustion Waste | Maximum | Cholla and Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			15
Surety Bonds Expiring in 2020 | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Surety bonds expiring, amount			$ 14

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligations
Newly incurred or acquired obligations	$ 0	$ 17,864
ARO, decrease		1,000
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	726,545	679,529
Changes attributable to:
Accretion expense	39,726	36,876
Settlements	(12,591)	(9,726)
Estimated cash flow revisions	(96,462)	2,002
Newly incurred or acquired obligations	0	17,864
Asset retirement obligations at the end of year	657,218	726,545
Palo Verde Nuclear Generating Station
Asset Retirement Obligations
ARO, decrease	89,000
Increase in regulatory asset	80,000
Decrease in regulatory liability	9,000
Solar Panels
Asset Retirement Obligations
Newly incurred or acquired obligations		14,000
Changes attributable to:
Newly incurred or acquired obligations		14,000
4CA
Asset Retirement Obligations
ARO, decrease		9,000
Navajo Generating Station
Asset Retirement Obligations
ARO, decrease	$ 8,000
Consumer Solar Panels
Asset Retirement Obligations
Newly incurred or acquired obligations		7,000
Changes attributable to:
Newly incurred or acquired obligations		$ 7,000

Selected Quarterly Financial _3

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES (NOTE 2)	$ 670,391	$ 1,190,787	$ 869,501	$ 740,530	$ 756,376	$ 1,268,034	$ 974,123	$ 692,714	$ 3,471,209	$ 3,691,247	$ 3,565,296
Operations and maintenance	229,857	238,582	227,543	245,634	256,120	246,545	268,397	265,682	941,616	1,036,744	949,107
Operating income	11,997	403,290	196,589	60,084	66,884	433,307	242,162	31,334	671,960	773,687	909,763
Income taxes	(88,537)	53,266	17,080	2,418	6,795	84,333	44,039	(1,265)	(15,773)	133,902	258,272
Net income	68,854	317,149	149,019	22,791	30,949	319,885	171,612	8,094	557,813	530,540	507,949
Net income attributable to common shareholders	$ 63,981	$ 312,276	$ 144,145	$ 17,918	$ 26,076	$ 315,012	$ 166,738	$ 3,221	$ 538,320	$ 511,047	$ 488,456
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.57	$ 2.78	$ 1.28	$ 0.16	$ 0.23	$ 2.81	$ 1.49	$ 0.03	$ 4.79	$ 4.56	$ 4.37
Net income attributable to common shareholders — diluted (in dollars per share)	$ 0.57	$ 2.77	$ 1.28	$ 0.16	$ 0.23	$ 2.80	$ 1.48	$ 0.03	$ 4.77	$ 4.54	$ 4.35
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES (NOTE 2)	$ 670,391	$ 1,190,787	$ 869,501	$ 740,530	$ 756,376	$ 1,267,997	$ 971,963	$ 692,006	$ 3,471,209	$ 3,688,342	$ 3,557,652
Operations and maintenance	226,758	235,440	224,143	240,375	236,281	226,346	251,999	254,601	926,716	969,227	917,983
Operating income	15,124	406,465	200,018	65,377	86,753	453,547	251,590	37,878	686,984	829,768	924,539
Income taxes									(9,572)	144,814	269,168
Net income									584,764	589,758	523,802
Net income attributable to common shareholders	$ 67,949	$ 318,870	$ 150,176	$ 28,276	$ 44,475	$ 338,366	$ 177,825	$ 9,599	$ 565,271	$ 570,265	$ 504,309

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets
Cash equivalents		$ 1,200
Commodity contracts,assets	$ 515	1,113
Commodity contracts, liabilities	(69)	(2,029)
Nuclear decommissioning trust	1,010,775	851,134
Nuclear decommissioning trust, other	521,245	398,953
Other special use fund	245,095	236,101
Other special use funds, other	474	593
Total assets	1,256,385	1,089,548
Total assets Other	521,650	397,517
Liabilities
Other	(711)	(875)
Derivative Liability	(72,132)	(60,037)
Equity securities
Assets
Nuclear decommissioning trust	13,273	7,351
Nuclear decommissioning trust, other	2,401	2,148
Other special use fund	7,616	45,723
Other special use funds, other	474	593
U.S. commingled equity funds
Assets
Nuclear decommissioning trust	518,844	396,805
U.S. Treasury debt
Assets
Nuclear decommissioning trust	160,607	148,173
Other special use fund	232,848	173,310
Corporate debt
Assets
Nuclear decommissioning trust	115,869	96,656
Mortgage-backed securities
Assets
Nuclear decommissioning trust	118,795	113,115
Municipal bonds
Assets
Nuclear decommissioning trust	73,040	79,073
Other special use fund	4,631	17,068
Other fixed income
Assets
Nuclear decommissioning trust	10,347	9,961
(Level 1)
Assets
Cash equivalents		1,200
Commodity contracts,assets	0	0
Nuclear decommissioning trust	171,479	153,376
Other special use fund	239,990	218,440
Total assets	411,469	373,016
Liabilities
Gross derivative liability	0	0
(Level 1) | Equity securities
Assets
Nuclear decommissioning trust	10,872	5,203
Other special use fund	7,142	45,130
(Level 1) | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	0	0
(Level 1) | U.S. Treasury debt
Assets
Nuclear decommissioning trust	160,607	148,173
Other special use fund	232,848	173,310
(Level 1) | Corporate debt
Assets
Nuclear decommissioning trust	0	0
(Level 1) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	0	0
(Level 1) | Municipal bonds
Assets
Nuclear decommissioning trust	0	0
Other special use fund	0	0
(Level 1) | Other fixed income
Assets
Nuclear decommissioning trust	0	0
(Level 2)
Assets
Cash equivalents		0
Commodity contracts,assets	551	3,140
Nuclear decommissioning trust	318,051	298,805
Other special use fund	4,631	17,068
Total assets	323,233	319,013
Liabilities
Gross derivative liability	(67,992)	(52,696)
(Level 2) | Equity securities
Assets
Nuclear decommissioning trust	0	0
Other special use fund	0	0
(Level 2) | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	0	0
(Level 2) | U.S. Treasury debt
Assets
Nuclear decommissioning trust	0	0
Other special use fund	0	0
(Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	115,869	96,656
(Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	118,795	113,115
(Level 2) | Municipal bonds
Assets
Nuclear decommissioning trust	73,040	79,073
Other special use fund	4,631	17,068
(Level 2) | Other fixed income
Assets
Nuclear decommissioning trust	10,347	9,961
(Level 3)
Assets
Cash equivalents		0
Commodity contracts,assets	33	2
Nuclear decommissioning trust	0	0
Other special use fund	0	0
Total assets	33	2
Liabilities
Gross derivative liability	(3,429)	(8,216)
(Level 3) | Equity securities
Assets
Nuclear decommissioning trust	0	0
Other special use fund	0	0
(Level 3) | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	0	0
(Level 3) | U.S. Treasury debt
Assets
Nuclear decommissioning trust	0	0
Other special use fund	0	0
(Level 3) | Corporate debt
Assets
Nuclear decommissioning trust	0	0
(Level 3) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	0	0
(Level 3) | Municipal bonds
Assets
Nuclear decommissioning trust	0	0
Other special use fund	0	0
(Level 3) | Other fixed income
Assets
Nuclear decommissioning trust	0	0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds
Assets
Nuclear decommissioning trust	$ 518,844	$ 396,805

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Quantitative Information (Details) - Forward Contracts $ in Thousands	Dec. 31, 2019USD ($)$ / MWh	Dec. 31, 2018USD ($)$ / MWh
Electricity forward contracts | Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input | $ / MWh	22.18	17.88
Electricity forward contracts | Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input | $ / MWh	22.18	37.03
Electricity forward contracts | Weighted-Average
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input | $ / MWh	22.18	26.10
Natural gas forward contracts | Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input | $ / MWh	2.33	1.79
Natural gas forward contracts | Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input | $ / MWh	2.78	2.92
Natural gas forward contracts | Weighted-Average
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Significant Unobservable Input | $ / MWh	2.49	2.48
(Level 3)
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	$ 33	$ 2
Financial and NonFinancial Liabilities, Fair Value Disclosure | $	3,429	8,216
(Level 3) | Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	33	0
Financial and NonFinancial Liabilities, Fair Value Disclosure | $	819	2,456
(Level 3) | Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets | $	0	2
Financial and NonFinancial Liabilities, Fair Value Disclosure | $	$ 2,610	$ 5,760

Fair Value Measurements - Chang

Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Total net gains (losses) realized/unrealized:
Net derivative beginning balance	$ (8,214)	$ (18,256)
Included in earnings	0	0
Included in OCI	0	0
Deferred as a regulatory asset or liability	(13,457)	(1,130)
Settlements	12,250	(787)
Transfers into Level 3 from Level 2	(6,512)	(12,830)
Transfers from Level 3 into Level 2	12,537	24,789
Net derivative ending balance	(3,396)	(8,214)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019USD ($)
Fair Value Disclosures [Abstract]
Significant level 1 transfers	$ 0
Stated interest rate for notes receivable	3.90%
Financing receivable	$ 44,300,000

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 63,981	$ 312,276	$ 144,145	$ 17,918	$ 26,076	$ 315,012	$ 166,738	$ 3,221	$ 538,320	$ 511,047	$ 488,456
Weighted Average common shares outstanding — basic (in shares)									112,443	112,129	111,839
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units (in shares)									315	421	528
Weighted average common shares outstanding — diluted (in shares)									112,758	112,550	112,367
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.57	$ 2.78	$ 1.28	$ 0.16	$ 0.23	$ 2.81	$ 1.49	$ 0.03	$ 4.79	$ 4.56	$ 4.37
Net Income attributable to common shareholders - diluted (in dollars per share)	$ 0.57	$ 2.77	$ 1.28	$ 0.16	$ 0.23	$ 2.80	$ 1.48	$ 0.03	$ 4.77	$ 4.54	$ 4.35

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 28, 2017shares	Dec. 31, 2012shares	Dec. 31, 2019USD ($)performance_criteriashares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016shares
Stock-Based Compensation
Compensation cost that has been charged against income | $			$ 18	$ 20	$ 21
Total income tax benefit recognized | $			7	7	15
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted | $			$ 9
Expected weighted-average period of recognition of unrecognized compensation cost			2 years
Total fair value of shares vested | $			$ 21	24	22
Performance Shares
Number of performance element criteria | performance_criteria			2
Performance period			3 years
Restricted stock unit awards
Stock-Based Compensation
Share-based liabilities paid | $			$ 5	4	4
Cash flow effect, cash used to settle awards | $			$ 5	$ 5	$ 4
Restricted Stock Units, Stock Grants and Stock Units
Vesting period			4 years
Percentage of cash that the participant may elect as a dividend for the first option available under the plan			50.00%
Percentage of stock that the participant may elect as dividend under second option of plan			50.00%
Restricted Stock Units, Stock Grants, and Stock Units
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares)			109,106
Shares released during period (in shares)			5,383
Performance Shares
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares)			142,874
Shares released during period (in shares)			9,074
Performance Shares | Maximum
Performance Shares
Exact number of shares issued as a percentage of the target award			200.00%
Performance Shares | Minimum
Performance Shares
Exact number of shares issued as a percentage of the target award			0.00%
Officers and Key Employees | Restricted stock unit awards
Restricted Stock Units, Stock Grants and Stock Units
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan			100.00%
Percentage of fully transferable shares of stock in that participant may receive cash			100.00%
Chief Executive Officer | Retention units
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares)		50,617
Additional shares to be granted as retention award if performance requirements are met (in shares)						33,745
Shares released during period (in shares)	84,362
Non-Officer Board of Director Member | Restricted stock unit awards
Restricted Stock Units, Stock Grants and Stock Units
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan			100.00%
Percentage of cash that the participant may elect as a dividend for the first option available under the plan			100.00%
Percentage of stock that the participant may elect as dividend under second option of plan			50.00%
Percentage of cash that the participant may elect as a dividend equivalent deferral for the first option available under the plan			50.00%
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan			50.00%
2012 Plan
Stock-Based Compensation
Common shares available for grant (in shares)			4,600,000
Common shares available for issuance (in shares)			1,600,000

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock Units, Stock Grants, and Stock Units
Stocks granted and the weighted average fair value
Units granted (in shares)	109,106	132,997	161,963
Grant date fair value (in dollars per share)	$ 89.15	$ 77.51	$ 72.60
Number of granted awards to be settled in cash (in shares)	48,972	66,252	67,599
Performance Shares
Stocks granted and the weighted average fair value
Units granted (in shares)	142,874	171,708	147,706
Grant date fair value (in dollars per share)	$ 92.16	$ 76.56	$ 78.99

Stock-Based Compensation - Stat

Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock Units, Stock Grants, and Stock Units
Nonvested shares
Balance at the beginning of the period (in shares)	270,991
Granted (in shares)	109,106
Vested (in shares)	(132,102)
Forfeited (in shares)	(5,383)
Balance at the end of the period (in shares)	242,612	270,991
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 74.39
Granted (in dollars per share)	89.15	$ 77.51	$ 72.60
Vested (in dollars per share)	73.48
Forfeited (in dollars per share)	80.10
Balance at the end of the period (in dollars per share)	$ 81.38	$ 74.39
Vested Awards Outstanding at December 31, 2017 (in shares)	67,148
Vested Awards Outstanding at December 31, 2017 (in dollars per share)
Number of nonvested awards to be settled in cash (in shares)	141,621
Performance Shares
Nonvested shares
Balance at the beginning of the period (in shares)	312,384
Granted (in shares)	142,874
Vested (in shares)	(139,214)
Forfeited (in shares)	(9,074)
Balance at the end of the period (in shares)	306,970	312,384
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 77.67
Granted (in dollars per share)	92.16	$ 76.56	$ 78.99
Vested (in dollars per share)	78.99
Forfeited (in dollars per share)	81.03
Balance at the end of the period (in dollars per share)	$ 83.65	$ 77.67
Vested Awards Outstanding at December 31, 2017 (in shares)	139,214
Vested Awards Outstanding at December 31, 2017 (in dollars per share)

Derivative Accounting (Details)

Derivative Accounting (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
ARIZONA PUBLIC SERVICE COMPANY
Derivative [Line Items]
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change	100.00%
Commodity Contracts
Derivative [Line Items]
Additional collateral to counterparties for energy related non-derivative instrument contracts	$ 95
Commodity Contracts | Designated as Hedging Instruments
Derivative [Line Items]
Estimated net loss before income taxes to be reclassified from accumulated other comprehensive income	$ 0.8
Risk Management Assets | Credit Concentration Risk
Derivative [Line Items]
Concentration risk, percentage	10.00%

Derivative Accounting - Outstan

Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts MWh in Thousands	12 Months Ended
	Dec. 31, 2019MWhBcf	Dec. 31, 2018MWhBcf
Outstanding gross notional amount of derivatives
Power (in MWh) | MWh	193	250
Gas (in bcf) | Bcf	257	218

Derivative Accounting - Gains a

Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Designated as Hedging Instruments
Derivative Instruments in Designated Cash Flows Hedges
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	$ 0	$ 0	$ 0
Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	(84,953,000)	(15,508,000)	(89,183,000)
Revenue | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	0	(2,557,000)	(1,192,000)
Fuel and purchased power | Designated as Hedging Instruments
Derivative Instruments in Designated Cash Flows Hedges
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(1,512,000)	(2,000,000)	(3,519,000)
Fuel and purchased power | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	(84,953,000)	(12,951,000)	(87,991,000)
Other Comprehensive Income (Loss) | Designated as Hedging Instruments
Derivative Instruments in Designated Cash Flows Hedges
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	$ 0	$ 0	$ (59,000)

Derivative Accounting - Derivat

Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Assets
Gross Recognized Derivatives	$ 515,000	$ 1,113,000
Liabilities
Amount Reported on Balance Sheet	(72,132,000)	(60,037,000)
Commodity Contracts
Assets
Gross Recognized Derivatives		3,142,000
Amounts Offset		(2,185,000)
Net Recognized Derivatives		957,000
Other	405,000	156,000
Amount Reported on Balance Sheet		1,113,000
Liabilities
Gross Recognized Derivatives	(71,421,000)	(60,912,000)
Amounts Offset	474,000	2,185,000
Net Recognized Derivatives	(70,947,000)	(58,727,000)
Other	(1,185,000)	(1,310,000)
Amount Reported on Balance Sheet	(72,132,000)	(60,037,000)
Assets and Liabilities
Gross Recognized Derivatives	(70,837,000)	(57,770,000)
Amounts Offset	0	0
Net Recognized Derivatives	(70,837,000)	(57,770,000)
Other	(780,000)	(1,154,000)
Amount Reported on Balance Sheet	(71,617,000)	(58,924,000)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	584,000	3,106,000
Amounts Offset	(474,000)	(2,149,000)
Net Recognized Derivatives	110,000	957,000
Other	405,000	156,000
Amount Reported on Balance Sheet	515,000	1,113,000
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives		36,000
Amounts Offset		(36,000)
Net Recognized Derivatives		0
Other		0
Amount Reported on Balance Sheet		0
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(38,235,000)	(36,345,000)
Amounts Offset	474,000	2,149,000
Net Recognized Derivatives	(37,761,000)	(34,196,000)
Other	(1,185,000)	(1,310,000)
Amount Reported on Balance Sheet	(38,946,000)	(35,506,000)
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(33,186,000)	(24,567,000)
Amounts Offset	0	36,000
Net Recognized Derivatives	(33,186,000)	(24,531,000)
Other	0	0
Amount Reported on Balance Sheet	$ (33,186,000)	$ (24,531,000)

Derivative Accounting - Credit

Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Dec. 31, 2019USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	$ 71,116
Cash collateral posted	0
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	$ 70,519

Other Income and Other Expens_2

Other Income and Other Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other income:
Interest income	$ 10,377	$ 8,647	$ 3,497
Miscellaneous	63	96	155
Total other income	50,263	24,896	4,006
Other expense:
Non-operating costs	(10,663)	(10,076)	(11,749)
Investment losses — net	(1,835)	(417)	(4,113)
Miscellaneous	(5,382)	(7,473)	(5,677)
Total other expense	(17,880)	(17,966)	(21,539)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	6,998	6,496	2,504
Miscellaneous	63	97	155
Total other income	46,884	22,746	3,013
Other expense:
Non-operating costs	(9,612)	(9,462)	(10,825)
Miscellaneous	(3,378)	(5,830)	(3,088)
Total other expense	(12,990)	(15,292)	(13,913)
SCR deferral
Other income:
Debt return on Four Corners SCR (Note 4)	19,541	16,153	354
SCR deferral | ARIZONA PUBLIC SERVICE COMPANY
Other income:
Debt return on Four Corners SCR (Note 4)	19,541	16,153	354
Octotillo deferral
Other income:
Debt return on Four Corners SCR (Note 4)	20,282		0
Octotillo deferral | ARIZONA PUBLIC SERVICE COMPANY
Other income:
Debt return on Four Corners SCR (Note 4)	$ 20,282	$ 0	$ 0

Palo Verde Sale Leaseback Var_3

Palo Verde Sale Leaseback Variable Interest Entities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)TrustLease	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 1986Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 19,493	$ 19,493	$ 19,493
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts | Trust	3			3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 19,493	19,493	$ 19,493
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	19,000	$ 19,000
Initial loss exposure to the VIEs noncontrolling equity participants during lease extension period	301,000
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period	$ 456,000
Period Through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease	1
Period Through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease	2
Period 2017 through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments	$ 23,000
Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments	$ 16,000
Maximum | Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Lease period	2 years

Palo Verde Leaseback Variable I

Palo Verde Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	$ 101,906	$ 105,775
Equity - noncontrolling interests	122,540	125,790
ARIZONA PUBLIC SERVICE COMPANY
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	101,906	105,775
Equity - noncontrolling interests	122,540	125,790
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	101,906	105,775
Equity - noncontrolling interests	$ 122,540	$ 125,790

Investments in Nuclear Decomm_3

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($) $ in Thousands	Aug. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Nuclear decommissioning trust fund assets
Fair Value		$ 1,255,870	$ 1,087,235
Total Unrealized Gains		363,476	230,781
Total Unrealized Losses		(669)	(7,237)
Amortized cost		691,000	635,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains		11,132	6,680	$ 21,830
Realized losses		(6,972)	(13,552)	(13,155)
Proceeds from the sale of securities		719,034	653,033	546,339
Fair value of fixed income securities, summarized by contractual maturities
Employee medical claims amount	$ 15,000
Equity securities
Nuclear decommissioning trust fund assets
Equity Securities		536,858	447,138
Total Unrealized Gains		337,681	222,147
Total Unrealized Losses		0	(459)
Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value		716,137	637,356
Total Unrealized Gains		25,795	8,634
Total Unrealized Losses		(669)	(6,778)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year		99,386
1 year - 5 years		299,410
5 years - 10 years		105,797
Greater than 10 years		211,544
Total		716,137
Other Receivables from Broker-Dealers and Clearing
Nuclear decommissioning trust fund assets
Fair Value		2,875	2,741
Total Unrealized Gains		0	0
Total Unrealized Losses		0	0
Nuclear Decommissioning Trusts
Nuclear decommissioning trust fund assets
Fair Value		1,010,775	851,134
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains		11,024	6,679	21,813
Realized losses		(6,972)	(13,552)	(13,146)
Proceeds from the sale of securities		473,806	554,385	542,246
Nuclear Decommissioning Trusts | Equity securities
Nuclear decommissioning trust fund assets
Equity Securities		529,716	402,008
Nuclear Decommissioning Trusts | Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value		478,658	446,978
Fair value of fixed income securities, summarized by contractual maturities
Less than one year		26,984
1 year - 5 years		136,139
5 years - 10 years		105,797
Greater than 10 years		209,738
Total		478,658
Nuclear Decommissioning Trusts | Other Receivables from Broker-Dealers and Clearing
Nuclear decommissioning trust fund assets
Fair Value		2,401	2,148
Coal Reclamation Escrow Account | Fixed income securities
Fair value of fixed income securities, summarized by contractual maturities
Less than one year		31,953
1 year - 5 years		25,229
5 years - 10 years		0
Greater than 10 years		1,806
Total		58,988
Active Union Medical Trust | Fixed income securities
Fair value of fixed income securities, summarized by contractual maturities
Less than one year		40,449
1 year - 5 years		138,042
5 years - 10 years		0
Greater than 10 years		0
Total		178,491
Other Special Use Funds
Nuclear decommissioning trust fund assets
Fair Value		245,095	236,101
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains		108	1	17
Realized losses		0	0	(9)
Proceeds from the sale of securities		245,228	98,648	$ 4,093
Other Special Use Funds | Equity securities
Nuclear decommissioning trust fund assets
Equity Securities		7,142	45,130
Other Special Use Funds | Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value		237,479	190,378
Other Special Use Funds | Other Receivables from Broker-Dealers and Clearing
Nuclear decommissioning trust fund assets
Fair Value		$ 474	$ 593

Changes in Accumulated Other _3

Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		$ 5,348,705	$ 5,135,730
Ending balance		5,553,188	5,348,705
Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		(45,997)	(42,440)
OCI (loss) before reclassifications		(14,041)	102
Amounts reclassified from accumulated other comprehensive loss		3,516	4,295
Reclassification of income tax effect related to tax reform			(7,954)
Ending balance		(56,522)	(45,997)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		(1,711)	(2,562)
OCI (loss) before reclassifications		0	(78)
Amounts reclassified from accumulated other comprehensive loss		1,137	1,527
Reclassification of income tax effect related to tax reform			(598)
Ending balance		(574)	(1,711)
Accumulated Other Comprehensive Income (Loss)
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		(47,708)	(45,002)
OCI (loss) before reclassifications		(14,041)	24
Amounts reclassified from accumulated other comprehensive loss		4,653	5,822
Reclassification of income tax effect related to tax reform	[1]		(8,552)
Ending balance		(57,096)	(47,708)
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		5,786,797	5,385,869
Ending balance		5,998,803	5,786,797
ARIZONA PUBLIC SERVICE COMPANY | Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		(25,396)	(24,421)
OCI (loss) before reclassifications		(12,572)	(326)
Amounts reclassified from accumulated other comprehensive loss		3,020	3,791
Reclassification of income tax effect related to tax reform			(4,440)
Ending balance		(34,948)	(25,396)
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		(1,711)	(2,562)
OCI (loss) before reclassifications		0	(78)
Amounts reclassified from accumulated other comprehensive loss		1,137	1,527
Reclassification of income tax effect related to tax reform			(598)
Ending balance		(574)	(1,711)
ARIZONA PUBLIC SERVICE COMPANY | Accumulated Other Comprehensive Income (Loss)
Changes in accumulated other comprehensive income (loss) by component
Beginning balance		(27,107)	(26,983)
OCI (loss) before reclassifications		(12,572)	(404)
Amounts reclassified from accumulated other comprehensive loss		4,157	5,318
Reclassification of income tax effect related to tax reform	[2]		(5,038)
Ending balance		$ (35,522)	$ (27,107)
[1]	In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the "Tax Act") on items within accumulated other comprehensive income to retained earnings.
[2]	In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.

SCHEDULE I - CONDENSED FINANC_2

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CONDENSED FINANCIAL STATEMENTS
Operating revenues	$ 670,391	$ 1,190,787	$ 869,501	$ 740,530	$ 756,376	$ 1,268,034	$ 974,123	$ 692,714	$ 3,471,209	$ 3,691,247	$ 3,565,296
Operating expenses									2,799,249	2,917,560	2,655,533
Operating loss	11,997	403,290	196,589	60,084	66,884	433,307	242,162	31,334	671,960	773,687	909,763
Other
Total									86,803	109,040	54,142
Interest expense									235,251	243,465	219,796
Income tax benefit	(88,537)	53,266	17,080	2,418	6,795	84,333	44,039	(1,265)	(15,773)	133,902	258,272
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 63,981	$ 312,276	$ 144,145	$ 17,918	$ 26,076	$ 315,012	$ 166,738	$ 3,221	538,320	511,047	488,456
Other comprehensive income (loss)									(9,388)	5,846	(1,180)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									528,932	516,893	487,276
Pinnacle West
CONDENSED FINANCIAL STATEMENTS
Operating revenues									0	0	119
Operating expenses									12,451	53,844	24,591
Operating loss									(12,451)	(53,844)	(24,472)
Other
Equity in earnings of subsidiaries									562,946	569,249	507,495
Other expense									(3,957)	(3,202)	(2,422)
Total									558,989	566,047	505,073
Interest expense									15,069	12,074	5,633
INCOME BEFORE INCOME TAXES									531,469	500,129	474,968
Income tax benefit									(6,851)	(10,918)	(13,488)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									538,320	511,047	488,456
Other comprehensive income (loss)									(9,388)	5,846	(1,180)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ 528,932	$ 516,893	$ 487,276

SCHEDULE I - CONDENSED FINANC_3

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Balance Sheets (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 10,283,000	$ 5,766,000
Accounts receivable	266,426,000	267,887,000
Income tax receivable	21,727,000	0
Other current assets	61,958,000	56,128,000
Total current assets	1,030,030,000	924,991,000
Investments and other assets
Other assets	96,953,000	103,247,000
Total investments and other assets	1,352,823,000	1,190,482,000
Total Assets	18,479,247,000	17,664,202,000
Current liabilities
Accounts payable	346,448,000	277,336,000
Accrued taxes	144,899,000	154,819,000
Common dividends payable	87,982,000	82,675,000
Short-term borrowings	114,675,000	76,400,000
Current maturities of long-term debt	800,000,000	500,000,000
Operating lease liabilities	12,713,000	0
Other current liabilities	168,323,000	184,229,000
Total current liabilities	2,078,365,000	1,648,964,000
Deferred credits and other
Long-term debt less current maturities (Note 7)	4,832,558,000	4,638,232,000
Operating lease liabilities	51,872,000	0
Other	159,844,000	147,640,000
Total deferred credits and other	6,015,136,000	6,028,301,000
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock	2,659,561,000	2,634,265,000
Accumulated other comprehensive loss	(57,096,000)	(47,708,000)
Retained earnings	2,837,610,000	2,641,183,000
Total shareholders’ equity	5,430,648,000	5,222,915,000
Noncontrolling interests	122,540,000	125,790,000
Total equity	5,553,188,000	5,348,705,000	$ 5,135,730,000	$ 4,935,912,000
Total Liabilities and Equity	18,479,247,000	17,664,202,000
Pinnacle West
Current assets
Cash and cash equivalents	19,000	41,000
Accounts receivable	104,640,000	99,989,000
Income tax receivable	15,905,000	32,737,000
Other current assets	401,000	1,502,000
Total current assets	120,965,000	134,269,000
Investments and other assets
Investments in subsidiaries	6,067,957,000	5,859,834,000
Deferred income taxes	40,757,000	5,243,000
Other assets	50,139,000	34,910,000
Total investments and other assets	6,158,853,000	5,899,987,000
Total Assets	6,279,818,000	6,034,256,000
Current liabilities
Accounts payable	7,634,000	9,565,000
Accrued taxes	8,573,000	9,006,000
Common dividends payable	87,982,000	82,675,000
Short-term borrowings	114,675,000	76,400,000
Current maturities of long-term debt	450,000,000	0
Operating lease liabilities	81,000	0
Other current liabilities	15,126,000	19,215,000
Total current liabilities	684,071,000	196,861,000
Deferred credits and other
Long-term debt less current maturities (Note 7)	(575,000)	448,796,000
Pension liabilities	17,942,000	17,766,000
Operating lease liabilities	1,780,000	0
Other	23,412,000	22,128,000
Total deferred credits and other	43,134,000	39,894,000
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock	2,650,134,000	2,629,440,000
Accumulated other comprehensive loss	(57,096,000)	(47,708,000)
Retained earnings	2,837,610,000	2,641,183,000
Total shareholders’ equity	5,430,648,000	5,222,915,000
Noncontrolling interests	122,540,000	125,790,000
Total equity	5,553,188,000	5,348,705,000
Total Liabilities and Equity	$ 6,279,818,000	$ 6,034,256,000

SCHEDULE I - CONDENSED FINANC_4

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Flows from Operating Activities
Net income	$ 68,854	$ 317,149	$ 149,019	$ 22,791	$ 30,949	$ 319,885	$ 171,612	$ 8,094	$ 557,813	$ 530,540	$ 507,949
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization									664,140	650,955	610,629
Deferred income taxes									(1,479)	117,355	248,164
Accounts receivable									(12,789)	37,530	(93,797)
Accounts payable									50,641	(14,602)	(23,769)
Net cash flow provided by operating activities									956,726	1,277,144	1,118,036
Cash flows from investing activities
Net cash flow used for investing activities									(1,130,977)	(1,192,824)	(1,428,537)
Cash flows from financing activities
Issuance of long-term debt									1,092,188	445,245	848,239
Short-term debt borrowings under revolving credit facility									49,000	45,000	58,000
Short-term debt repayments under revolving credit facility									(65,000)	(57,000)	(32,000)
Dividends paid on common stock									(329,643)	(308,892)	(289,793)
Repayment of long-term debt									(600,000)	(182,000)	(125,000)
Common stock equity issuance and purchases - net									692	(5,055)	(13,390)
Net cash flow provided by (used for) financing activities									178,768	(92,446)	315,512
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS									4,517	(8,126)	5,011
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR				5,766				13,892	5,766	13,892	8,881
CASH AND CASH EQUIVALENTS AT END OF YEAR	10,283				5,766				10,283	5,766	13,892
Pinnacle West
Cash Flows from Operating Activities
Net income									538,320	511,047	488,456
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries - net									(562,946)	(569,249)	(507,495)
Depreciation and amortization									76	76	76
Deferred income taxes									(35,831)	49,535	(264)
Accounts receivable									182	(7,881)	(2,106)
Accounts payable									(2,129)	1,967	(11,162)
Accrued taxes and income tax receivable - net									16,400	(13,535)	(22,247)
Dividends received from subsidiaries									336,300	316,000	296,800
Other									(1,300)	31,807	15,092
Net cash flow provided by operating activities									289,072	319,767	257,150
Cash flows from investing activities
Investments in subsidiaries									1,557	(142,796)	(178,027)
Repayments of loans from subsidiaries									4,190	6,477	2,987
Advances of loans to subsidiaries									(4,165)	(500)	(6,388)
Net cash flow used for investing activities									1,582	(136,819)	(181,428)
Cash flows from financing activities
Issuance of long-term debt									0	150,000	298,761
Short-term debt borrowings under revolving credit facility									49,000	20,000	58,000
Short-term debt repayments under revolving credit facility									(65,000)	(32,000)	(32,000)
Commercial paper - net									54,275	(7,000)	27,700
Dividends paid on common stock									(329,643)	(308,892)	(289,793)
Repayment of long-term debt									0	0	(125,000)
Common stock equity issuance and purchases - net									692	(5,055)	(13,390)
Other									0	(1)	0
Net cash flow provided by (used for) financing activities									(290,676)	(182,948)	(75,722)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS									(22)	0	0
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR				$ 41				$ 41	41	41	41
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 19				$ 41				$ 19	$ 41	$ 41

SCHEDULE II - RESERVE FOR UNC_2

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) - Reserve for uncollectibles. - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
ARIZONA PUBLIC SERVICE COMPANY
Changes in reserve for uncollectibles
Balance at beginning of period	$ 4,069	$ 2,513	$ 3,037
Additions, Charged to cost and expenses	11,819	10,870	6,836
Additions, Charged to other accounts	0	0	0
Deductions	7,717	9,314	7,360
Balance at end of period	8,171	4,069	2,513
Pinnacle West
Changes in reserve for uncollectibles
Balance at beginning of period	4,069	2,513	3,037
Additions, Charged to cost and expenses	11,819	10,870	6,836
Additions, Charged to other accounts	0	0	0
Deductions	7,717	9,314	7,360
Balance at end of period	$ 8,171	$ 4,069	$ 2,513