PINNACLE WEST CAPITAL CORP, 10-K filed on 2/21/2020
Annual Report
v3.19.3.a.u2
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  
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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 COMPANY
Common Stock
ARIZONA PUBLIC SERVICE COMPANY
Additional Paid-In Capital
ARIZONA PUBLIC SERVICE COMPANY
Retained Earnings
ARIZONA PUBLIC SERVICE COMPANY
Accumulated Other Comprehensive Income (Loss)
ARIZONA PUBLIC SERVICE COMPANY
Noncontrolling Interests
Beginning balance 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.
v3.19.3.a.u2
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
v3.19.3.a.u2
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.
v3.19.3.a.u2
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.
v3.19.3.a.u2
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.
v3.19.3.a.u2
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
December 31,
 
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 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.
    
In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019.  This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019.

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

See "2016 Retail Rate Case Filing with the Arizona Corporation Commission" above for information regarding an ACC order in connection with the rate review of the 2017 Rate Case Decision requiring APS to provide grandfathered net metering customers on legacy demand rates with an opportunity to switch to another legacy rate to enable such customers to benefit from legacy net metering rates.

Subpoena from Arizona Corporation Commissioner Robert Burns

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

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.

On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019. On February 13, 2019, Commissioner Burns filed a notice of appeal. On July 12, 2019, Commissioner Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The Arizona Court of Appeals granted the request for oral argument but no date has been set. APS and Pinnacle West cannot predict the outcome of this matter.

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters. The Company's CEO, Mr. Guldner, appeared at the ACC's January 14, 2020 Open Meeting regarding ACC Commissioners' questions about political spending.  Mr. Guldner committed to the ACC that during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.

2018 Renewable Energy Ballot Initiative

On February 20, 2018, a renewable energy advocacy organization filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to provide at least 50% of their annual retail sales of electricity from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The initiative was placed on the November 2018 Arizona elections ballot. On November 6, 2018, the initiative failed to receive adequate voter support and was defeated.
Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan ("IRP") process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On July 2, 2019, the ACC Staff issued a revised set of draft rules, which propose a RES goal of 45% of retail energy served be renewable by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules 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. The ACC held various stakeholder meetings and workshops on ACC Staff’s draft energy rules in July through September 2019 and have scheduled a workshop to be held on March 10 - 11, 2020. On February 19, 2020, the ACC Staff issued a revised proposed set of draft rules that will be discussed at the workshop. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop fifteen-year IRPs which describe how the utility plans to serve customer load in the plan timeframe.  The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged.  In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans.  APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows.  Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020.  On February 20, 2020, the ACC extended the deadline for all utilities to file their IRP’s from April 1, 2020 to June 26, 2020.

Public Utility Regulatory Policies Act

In August 2016, APS filed an application requesting that all of its contracts with qualifying facilities over 100 kW be set at a presumptive maximum 2-year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has a right to sell to the host utility. Host utilities are required to purchase power from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 and briefing on this matter was completed in October 2019 regarding APS’s application. On December 17, 2019, the ACC denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW and the rate paid to the qualifying facilities will be based on the long-term avoided cost.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.  On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15. During the moratorium on disconnections, APS could not charge late fees and interest on amounts that were past due from customers.  Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts.  In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. The emergency rule changes will be effective for 180 days and may be renewed for one additional 180 day period. During that time, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes.  The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff issued draft amendments to the customer service disconnections rules. Stakeholders submitted initial comments to the draft amendments on September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules. The disconnection moratorium resulted in a negative impact to our 2019 operating results of approximately $10 million pre-tax. APS is further assessing the impact to its financial statements beyond 2019, which will be affected by the results of final rulemaking related to disconnections.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report, and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC has scheduled a workshop for February 25-26, 2020 for further consideration and discussion of the retail electric competition rules. APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

Rate Plan Comparison Tool

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and the Company’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation that would result in the lowest bills based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019 and November 14, 2019. APS is providing refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided is not expected to have a material impact on APS's financial statements. The ACC is currently investigating this matter. APS received a civil investigative demand from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks information pertaining to the rate plan comparison tool offered to APS customers. APS is fully cooperating with the Attorney General’s Office in this matter. APS cannot predict the outcome of these matters.

Four Corners
 
SCE-Related Matters. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provide transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter
of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. On December 18, 2019, APS submitted an offer of settlement to FERC to resolve all outstanding issues related to this matter. The offer of settlement provided that APS would not recover in rates any portion of any payment it made to SCE in connection with the expiration of the Transmission Agreement and FERC would close certain dockets related to this matter. On February 5, 2020, FERC issued an order accepting APS’s offer of settlement and resolved this matter.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS filed the SCR Adjustment request in April 2018.  Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment.  The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers.  Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019.  The hearing for this matter occurred in September 2018.  At the hearing, APS accepted ACC Staff's recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018.  The ACC has not issued a decision on this matter.  APS included the costs for the SCR project in the retail rate base in its 2019 retail rate case filing with the ACC. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it plans to retire Cholla Unit 4 by the end of 2020.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s
decommissioning and other retirement-related costs ($73 million as of December 31, 2019), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.
On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.
Navajo Plant
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased operations in November 2019.
  
APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($82 million as of December 31, 2019) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.
Regulatory Assets and Liabilities
 
The detail of regulatory assets is as follows (dollars in thousands):
S
 
 
December 31, 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.”
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.
v3.19.3.a.u2
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.
v3.19.3.a.u2
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.
v3.19.3.a.u2
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
December 31, 2019
 
As of
December 31, 2018
 
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.
v3.19.3.a.u2
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.
v3.19.3.a.u2
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
December 31, 2019
 
 
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


v3.19.3.a.u2
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.
v3.19.3.a.u2
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 52nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("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 as of December 31, 2019) are currently expected to be terminated ten years following the commercial operation date of the applicable project.
v3.19.3.a.u2
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.
v3.19.3.a.u2
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


v3.19.3.a.u2
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
Fair Value (thousands)
 
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
Fair Value (thousands)
 
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.
v3.19.3.a.u2
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


v3.19.3.a.u2
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.
 
Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.
v3.19.3.a.u2
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:
(dollars in thousands)
 
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:
(dollars in thousands)
 
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.
v3.19.3.a.u2
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
)

v3.19.3.a.u2
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.
v3.19.3.a.u2
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
Unrealized
Gains

Total
Unrealized
Losses
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
Unrealized
Gains

Total
Unrealized
Losses
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


v3.19.3.a.u2
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
tax reform
(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
tax reform
(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.
v3.19.3.a.u2
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.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.
v3.19.3.a.u2
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


v3.19.3.a.u2
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.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis.
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
either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.
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 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.
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
 
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.
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.
v3.19.3.a.u2
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

 

 


v3.19.3.a.u2
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



v3.19.3.a.u2
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
December 31,
 
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.

v3.19.3.a.u2
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
)

v3.19.3.a.u2
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%
 

v3.19.3.a.u2
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
December 31, 2019
 
As of
December 31, 2018
 
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


v3.19.3.a.u2
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.

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
%

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


v3.19.3.a.u2
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
December 31, 2019
 
 
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.

v3.19.3.a.u2
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.
v3.19.3.a.u2
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


v3.19.3.a.u2
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


v3.19.3.a.u2
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


v3.19.3.a.u2
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
Fair Value (thousands)
 
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
Fair Value (thousands)
 
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
 
$

 
$


v3.19.3.a.u2
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


v3.19.3.a.u2
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.

v3.19.3.a.u2
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:
(dollars in thousands)
 
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:
(dollars in thousands)
 
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:
(dollars in thousands)
 
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:
(dollars in thousands)
 
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.
v3.19.3.a.u2
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
)

v3.19.3.a.u2
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


v3.19.3.a.u2
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
Unrealized
Gains

Total
Unrealized
Losses
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
Unrealized
Gains

Total
Unrealized
Losses
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


v3.19.3.a.u2
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
tax reform
(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
tax reform
(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.
v3.19.3.a.u2
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, 2019
USD ($)
$ / shares
shares
Dec. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Dec. 31, 2019
USD ($)
$ / shares
shares
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%
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
Regulatory Matters - Retail Rate Case Filing (Details) - ACC - ARIZONA PUBLIC SERVICE COMPANY
12 Months Ended
Oct. 31, 2019
USD ($)
Jun. 30, 2019
USD ($)
Aug. 13, 2018
USD ($)
Feb. 13, 2018
Jan. 08, 2018
USD ($)
Jan. 03, 2018
Customer
Mar. 27, 2017
USD ($)
$ / kWh
Dec. 31, 2019
USD ($)
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             $ 61,000,000.0  
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  
v3.19.3.a.u2
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%
v3.19.3.a.u2
Regulatory Matters - Narrative (Details)
Customer in Thousands
12 Months Ended
Feb. 14, 2020
USD ($)
Feb. 01, 2020
USD ($)
$ / kWh
Nov. 14, 2019
USD ($)
Customer
Oct. 31, 2019
USD ($)
Oct. 29, 2019
USD ($)
Jun. 01, 2019
USD ($)
May 01, 2019
$ / kWh
Apr. 10, 2019
Feb. 15, 2019
USD ($)
Feb. 01, 2019
$ / kWh
Aug. 13, 2018
USD ($)
Jun. 01, 2018
USD ($)
May 01, 2018
$ / kWh
Feb. 20, 2018
Feb. 15, 2018
USD ($)
Feb. 01, 2018
$ / kWh
Jan. 08, 2018
USD ($)
Nov. 20, 2017
USD ($)
Dec. 20, 2016
$ / kWh
Dec. 31, 2020
USD ($)
Dec. 31, 2019
USD ($)
Dec. 31, 2017
$ / kWh
Dec. 31, 2012
$ / kWh
Jul. 01, 2019
USD ($)
Mar. 15, 2019
agreement
Dec. 31, 2018
USD ($)
Jun. 29, 2018
USD ($)
Nov. 14, 2017
USD ($)
Sep. 01, 2017
USD ($)
Jun. 30, 2017
USD ($)
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                                       $ (2,000,000.0)                    
v3.19.3.a.u2
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
v3.19.3.a.u2
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($)
$ in Millions
1 Months Ended 3 Months Ended
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         $ 73.0  
Navajo Plant            
Acquisition            
Regulatory asset, net book value         $ 82.0  
SCE | Four Corners            
Acquisition            
Regulatory assets           $ 12.0
Regulatory assets, write of amount       $ 12.0    
Four Corners Units 4 and 5 | SCE            
Acquisition            
Transmission termination agreement net receipt due to negotiation of alternate arrangement $ 40.0          
Settlement agreement, ACC approved rate adjustment, annualized customer impact   $ 58.5 $ 67.5      
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
Income Taxes (Details) - USD ($)
3 Months Ended 12 Months Ended
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      
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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)
v3.19.3.a.u2
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
v3.19.3.a.u2
Lines of Credit and Short-Term Borrowings (Details)
May 09, 2019
USD ($)
Dec. 31, 2019
USD ($)
Facility
Dec. 31, 2018
USD ($)
Nov. 27, 2018
USD ($)
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%      
v3.19.3.a.u2
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%        
v3.19.3.a.u2
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%  
v3.19.3.a.u2
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details)
$ in Thousands
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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)
v3.19.3.a.u2
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  
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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)  
v3.19.3.a.u2
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)    
v3.19.3.a.u2
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%
v3.19.3.a.u2
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  
v3.19.3.a.u2
Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details)
$ in Thousands
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
Leases - Additional information (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Dec. 31, 2019
USD ($)
Counterparty
Jan. 01, 2019
USD ($)
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    
v3.19.3.a.u2
Leases - Lease costs (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
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  
v3.19.3.a.u2
Leases - Future minimum operating lease (Details)
$ in Thousands
Dec. 31, 2018
USD ($)
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
v3.19.3.a.u2
Leases - Other additional information related to operating lease liabilities (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
Jointly-Owned Facilities (Details) - ARIZONA PUBLIC SERVICE COMPANY
$ in Thousands
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)
12 Months Ended 84 Months Ended
Feb. 11, 2020
USD ($)
Oct. 31, 2019
USD ($)
Dec. 31, 2019
USD ($)
Trust
Dec. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Jun. 30, 2018
USD ($)
claim
Dec. 31, 1986
Trust
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            
v3.19.3.a.u2
Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) - ARIZONA PUBLIC SERVICE COMPANY - Contaminated groundwater wells
$ in Millions
12 Months Ended
Apr. 05, 2018
plaintiff
Defendant
Dec. 16, 2016
plaintiff
Aug. 06, 2013
Defendant
Dec. 31, 2019
USD ($)
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      
v3.19.3.a.u2
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($)
$ in Millions
12 Months Ended
Jul. 03, 2018
Jul. 06, 2016
Dec. 31, 2019
Financial Assurances      
Equity contribution guarantees     $ 40.0
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 $ 70.0    
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     $ 10.0
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     $ 400.0
Regional Haze Rules | Four Corners Units 4 and 5 | Four Corners | ARIZONA PUBLIC SERVICE COMPANY      
Environmental Matters [Abstract]      
Additional expected environment cost     $ 45.0
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     $ 22.0
Coal Combustion Waste | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY      
Environmental Matters [Abstract]      
Additional expected environment cost     1.0
Coal Combustion Waste | Minimum | Cholla | ARIZONA PUBLIC SERVICE COMPANY      
Environmental Matters [Abstract]      
Additional expected environment cost     15.0
Coal Combustion Waste | Minimum | Cholla and Four Corners | ARIZONA PUBLIC SERVICE COMPANY      
Environmental Matters [Abstract]      
Additional expected environment cost     10.0
Coal Combustion Waste | Maximum | Cholla and Four Corners | ARIZONA PUBLIC SERVICE COMPANY      
Environmental Matters [Abstract]      
Additional expected environment cost     15.0
Surety Bonds Expiring in 2020 | ARIZONA PUBLIC SERVICE COMPANY      
Financial Assurances      
Surety bonds expiring, amount     $ 14.0
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
Fair Value Measurements - Level 3 Quantitative Information (Details) - Forward Contracts
$ in Thousands
Dec. 31, 2019
USD ($)
$ / MWh
Dec. 31, 2018
USD ($)
$ / 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
v3.19.3.a.u2
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
v3.19.3.a.u2
Fair Value Measurements - Additional Information (Details)
12 Months Ended
Dec. 31, 2019
USD ($)
Fair Value Disclosures [Abstract]  
Significant level 1 transfers $ 0
Stated interest rate for notes receivable 3.90%
Financing receivable $ 44,300,000
v3.19.3.a.u2
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
v3.19.3.a.u2
Stock-Based Compensation (Details)
$ in Millions
1 Months Ended 12 Months Ended
Feb. 28, 2017
shares
Dec. 31, 2012
shares
Dec. 31, 2019
USD ($)
performance_criteria
shares
Dec. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Dec. 31, 2016
shares
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      
v3.19.3.a.u2
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
v3.19.3.a.u2
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)    
v3.19.3.a.u2
Derivative Accounting (Details)
$ in Millions
12 Months Ended
Dec. 31, 2019
USD ($)
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 $ 95.0
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%
v3.19.3.a.u2
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
12 Months Ended
Dec. 31, 2019
MWh
Bcf
Dec. 31, 2018
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power (in MWh) | MWh 193 250
Gas (in bcf) | Bcf 257 218
v3.19.3.a.u2
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)
v3.19.3.a.u2
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)
v3.19.3.a.u2
Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
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
v3.19.3.a.u2
Palo Verde Sale Leaseback Variable Interest Entities (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2019
USD ($)
Trust
Lease
Dec. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Dec. 31, 1986
Trust
Palo Verde Sale Leaseback Variable Interest Entities        
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 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      
v3.19.3.a.u2
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
v3.19.3.a.u2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($)
$ in Thousands
12 Months Ended
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  
v3.19.3.a.u2
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.
v3.19.3.a.u2
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
v3.19.3.a.u2
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    
v3.19.3.a.u2
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
v3.19.3.a.u2
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